---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

(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, solar and biomass generating assets.

(d)	Electric supply procured under site specific agreements.

•	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 34% of capacity).

•	Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region (approximately 37% of capacity).

•	New England represents operations within ISO-NE (approximately 7% of capacity).

•	New York represents operations within ISO-NY (approximately 6% of capacity).

•	ERCOT represents operations within Electric Reliability Council of Texas (approximately 11% of capacity).

•	Other Power Regions represents Canada, South and West (approximately 5% of capacity).

---

---

(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)	On July 10, 2018, Generation submitted a second 20-year license renewal application to NRC for Peach Bottom Units 2 and 3.

(d)	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. See Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.

---

---

---

---

(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 2018 and 2017 includes physical volumes of 35,100 GWh and 34,761 GWh, respectively, for CENG.

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

---

(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.

---

---

(a)	Natural gas from underground storage represents approximately 28%, 54% and 34% of PECO's, BGE’s and DPL's 2018-2019 heating season planned supplies, respectively.

---

---

(a)	A separate CBA between ComEd and IBEW Local 15 covers approximately 73 employees in ComEd’s System Services Group and will expire in 2020. 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 84 employees, which expires in 2019.

(c)

During 2018, Generation acquired and finalized its CBA with Distrigas Local 369, which will expire in 2020, and additionally, finalized a first collective bargaining agreement, expiring in 2021, with a small unit of employees represented by IUOE Local 501 at Exelon's Hyperion Solutions facility. Also in 2018, Generation finalized a three-year agreement with the Security Officer union at Braidwood and that CBA will expire in 2021. 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 three Security Officer unions at Byron, Clinton and TMI, all expiring between 2019 and 2021, respectively. During 2014, Generation finalized CBAs with TMI Local 777 and Oyster Creek Local 1289, expiring in 2019 and 2021, respectively. Also in 2014, CENG finalized its CBA with Nine Mile Point which will expire in 2020.

(d)

In January 2017, an election was held at BGE which resulted in union representation for certain employees, who numbered 1,284 at the end of 2018. 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 these CBAs were renegotiated in 2014 and were extended through various dates ranging from October 2018 through June 2020. During 2018, ACE finalized a five-year agreement with Local 210, expiring in 2023.

(f)	Other includes shared services employees at BSC.

---

---

---

---

---

---

---

---

---

---

---

•

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 and business models.

•

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 regulatory business model 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.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

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

(f)	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.

(g)	Reflects the sale of 49% of EGRP 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.

(h)	EGRP 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.

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

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

(k)	Generation has agreed to retire and cease generation operations at the Gould Street, Fairless Hills, Eastern, Bethlehem, Southeast Chicago, Notch Cliff, Riverside (unit 8), Westport and Pennsbury units on or before June 1, 2020.

(l)	Generation plans to retire and cease generation operation at Riverside (unit 7) on or about March 14, 2019.

(m)	Generation plans to retire and cease generation operation at the Mystic 7 and Mystic Jet units on or about June 1, 2022.

---

---

(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.

---

---

---

(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.

---

---

•	$100 invested on December 31, 2013 in Exelon common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and

•	All dividends are reinvested.

---

---

---

---

(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.

(c)	Amounts have been recasted to reflect the Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

(d)	Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative.

(a)	Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative.

---

(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.

(b)	Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative.

(a)	Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative.

---

---

---

(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.

---

(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.

---

(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.

---

---

(a)	Includes the consolidated results of Pepco, DPL and ACE.

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

•	Impacts associated with the one-time remeasurement of deferred income taxes in 2017 as a result of the TCJA;

•	Net unrealized losses on NDT funds in 2018 compared to net gains in 2017;

•	Lower realized energy prices;

•	Accelerated depreciation and amortization due to the decision to early retire the Oyster Creek and TMI nuclear facilities;

•	The gain associated with the FitzPatrick acquisition in 2017;

•	Decrease in reserves for uncertain tax positions in 2017 related to the deductibility of certain merger commitments associated with the 2012 Constellation and 2016 PHI acquisitions;

•	Increased mark-to-market losses;

•	The gain recorded upon deconsolidation of EGTP's net liabilities in 2017;

•	The absence of EGTP earnings resulting from its deconsolidation in the fourth quarter of 2017;

---

•	Long-lived asset impairments of certain merchant wind assets in West Texas; and

•	Increased storm costs at PECO and BGE.

•	The impact of the New York and Illinois ZEC revenue (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017);

•	Long-lived asset impairments primarily related to the EGTP assets held for sale in 2017;

•	Increased capacity prices;

•	The impact of lower federal income tax rate as a result of the TCJA at Generation;

•	Net realized gains on NDT funds;

•	The gain on the settlement of a long-term gas supply agreement;

•	Decreased nuclear outage days;

•	Increased electric distribution and energy efficiency formula rate earnings at ComEd;

•	Regulatory rate increases at PECO, BGE and PHI;

•	The impact of favorable weather at PECO, DPL and ACE; and

•	The absences of a 2017 impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.

•	Impacts associated with the one-time remeasurement of deferred income taxes as a result of the TCJA;

•	The gain associated with the FitzPatrick acquisition;

•	Accelerated depreciation and amortization due to the decision to early retire the TMI nuclear facility in 2017 compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities;

•	Higher net unrealized and realized gains on NDT funds;

•	The impact of the New York ZEC revenue;

•	The gain recorded upon deconsolidation of EGTP's net liabilities;

•	Increased capacity prices;

•	Decreased nuclear outage days;

•	Decrease in reserves for uncertain tax positions in 2017 related to the deductibility of certain merger commitments associated with the 2012 Constellation and 2016 PHI acquisitions compared to costs incurred as part of the settlement orders approving the PHI acquisition and a charge related to a 2012 CEG merger commitment in 2016;

•	Increased electric distribution and transmission formula rate earnings at ComEd;

---

•	Regulatory rate increases at BGE and PHI; and

•	Penalties and associated interest expense as a result of a tax court decision on Exelon's like-kind exchange position in 2016.

•	Long-lived asset impairments primarily related to the EGTP assets held for sale;

•	Lower realized energy prices;

•	The conclusion of the Ginna Reliability Support Services Agreement;

•	Increased costs related to the acquisition of the FitzPatrick nuclear facility;

•	Increased mark-to-market losses;

•	The impact of unfavorable weather at ComEd, PECO, DPL and ACE; and

•	The impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.

---

---

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

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

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

(d)

Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2016 and 2017, reflects costs related to the PHI and FitzPatrick acquisitions, partially offset in 2016 at ComEd, and in 2017, at PHI, by the anticipated recovery of previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition. See Note 5 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

(e)	Represents costs incurred as part of the settlement orders approving the PHI acquisition, and in 2016, a charge related to a 2012 CEG merger commitment, and in 2017, primarily 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.

(f)	In 2016, primarily reflects the impairment of upstream assets and certain wind projects at Generation. In 2017, primarily reflects the impairment of the EGTP assets held for sale and PHI District of Columbia sponsorship intangible asset. In 2018, primarily reflects the impairment of certain wind projects at Generation.

(g)

In 2016, primarily reflects accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston generating site. In 2017, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the TMI nuclear facility. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the previous decision to early retire the TMI nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.

(h)	Primarily represents severance and reorganization costs related to a cost management program.

(i)	For Pepco, reflects an increase related to asbestos identified at its Buzzard Point property.

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

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

(l)	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.

(m)	Represents the gain on the settlement of a long-term gas supply agreement at Generation.

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

(o)	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.

(p)

Reflects in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition. In 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the TCJA (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA and changes in forecasted apportionment.

(q)	Reflects benefits related to the favorable settlement of certain income tax positions related to PHI's unregulated business interests.

(r)	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 funds at CENG.

---

---

(a)	Includes the annual ongoing TCJA tax savings further discussed above.

---

(a)	Includes the annual ongoing TCJA tax savings further discussed above.

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

(b)

The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(c)	BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE.

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

(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.

---

(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 and amortization for TMI and Oyster Creek for the year ended December 31, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018.

(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.

---

•

First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 planning years. FERC denied the waiver request on procedural grounds on July 2, 2018 and ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.

•	Second, in accordance with FERC's July 2, 2018 order, on August 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons, which FERC accepted on December 3, 2018.

•

Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs including the cost of procuring fuel. In its July 2, 2018 order, FERC ordered ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. In January 2019, ISO-NE indicated that it intends to seek an extension of the deadline for this filing to November 15, 2019.

---

(a)	PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE.

(b)	Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $27 million, $27 million, $5 million, $1 million and $21 million, respectively.

•	The Utility Registrants 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.

---

---

---

---

---

---

---

---

---

(a)	Excludes any sites in which management has committed to a specific decommissioning approach.

(b)	Excludes any retired site or sites for which an early plant retirement has been announced.

---

---

---

---

(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.

---

(a)

Exelon's charge against OCI (before taxes) consists of up to $2.4 billion, $529 million, $157 million, $413 million, $208 million and $105 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's and ACE's respective portions of the deferred costs associated with Exelon's pension and other postretirement benefit plans. Exelon also has a net regulatory liability of $(47) million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s other postretirement benefit plans that would result in an increase in OCI if reversed.

---

---

---

---

---

•	Impacts associated with the one-time remeasurement of deferred income taxes in 2017 as a result of the TCJA;

•	Net unrealized losses on NDT funds in 2018 compared to net gains in 2017;

•	Lower realized energy prices;

•	Accelerated depreciation and amortization due to the decision to early retire the Oyster Creek and TMI nuclear facilities;

•	The gain associated with the FitzPatrick acquisition in 2017;

•	Increased mark-to-market losses;

•	The gain recorded upon deconsolidation of EGTP's net liabilities in 2017;

---

•	The absence of EGTP earnings resulting from its deconsolidation in the fourth quarter of 2017; and

•	Long-lived asset impairments of certain merchant wind assets in West Texas.

•	The impact of the New York and Illinois ZEC revenue (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017);

•	Long-lived asset impairments primarily related to the EGTP assets held for sale in 2017;

•	Increased capacity prices;

•	The impact of lower federal income tax rate as a result of the TCJA at Generation;

•	Net realized gains on NDT funds; and

•	Decreased nuclear outage days.

•	Impacts associated with the one-time remeasurement of deferred income taxes as a result of the TCJA;

•	The gain associated with the FitzPatrick acquisition;

•	Accelerated depreciation and amortization due to the decision to early retire the TMI nuclear facility in 2017 compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities;

•	Higher net unrealized and realized gains on NDT funds;

•	The impact of the New York ZEC revenue;

•	The gain recorded upon deconsolidation of EGTP's net liabilities;

•	Increased capacity prices; and

•	Decreased nuclear outage days.

•	Long-lived asset impairments primarily related to the EGTP assets held for sale;

•	Lower realized energy prices;

•	The conclusion of the Ginna Reliability Support Services Agreement;

•	Increased costs related to the acquisition of the FitzPatrick nuclear facility; and

•	Increased mark-to-market losses.

---

(a)	Includes results of transactions with PECO and BGE in the Mid-Atlantic region and results of transactions with ComEd in the Midwest region. As a result of the PHI merger, includes results of transactions with Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016.

(b)

Other represents activities not allocated to a region. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a $54 million decrease to RNF and a $57 million decrease to RNF for the years ended December 31, 2017 and 2016, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements, as discussed in Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements, of $57 million, $12 million and $60 million for the years ended December 31, 2018, 2017 and 2016, respectively, and gain on the settlement of a long-term gas supply agreement of $75 million for the year ended December 31, 2018.

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

---

(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.

---

---

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

(b)	Primarily reflects the impairment of certain wind projects in 2018 and charges to earnings related to impairments as a result of the EGTP assets in 2017.

(c)	Primarily reflects merger and integration costs associated with the PHI and FitzPatrick acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities.

(d)	Primarily represents the announcement to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO compared to the previous decision to early retire the TMI nuclear facility in 2017.

(e)	Primarily reflects decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business.

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

---

(a)	Includes the ownership of the FitzPatrick nuclear facility 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 nuclear decommissioning obligation related to the non-regulatory units in 2017 compared to 2016.

(d)	Primarily represents the announcement of the early retirement of the TMI nuclear facility in 2017 compared to the previous decision to early retire the 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 merger 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)	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.

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

---

---

---

(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. 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 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.

---

(a)	Includes costs associated with mutual assistance provided to other utilities in 2018. An equal and offsetting increase has been recognized in Operating revenues for the period presented.

(b)	ComEd is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues for the periods presented.

(c)	For the year ended December 31, 2017, primarily reflects increased information technology support services from BSC and 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 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.

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

(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 and 2017. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

(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.

---

---

---

(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.

(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.

---

---

---

---

(a)	See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on Smart Meter and Smart Grid Investments.

(b)	Reflects increased storm restoration costs incurred from storms in Q1 2018 and Q3 2018.

(c)	See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

---

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

(b)

Regulatory asset amortization decreased for the year ended December 31, 2018 compared to the same period in 2017, primarily due to certain regulatory assets that became fully amortized as of December 31, 2017 and increased for the year ended December 31, 2017 compared to the same period in 2016, primarily due 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 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

---

(a)	Primarily includes eliminating and consolidating adjustments, PHI’s corporate operations, shared service entities and other financing activities. Not included for 2016 due to PHI Predecessor periods not being comparable.

---

---

---

(a)	Reflects an increase primarily related to asbestos identified at the Buzzard Point property. See Note 15 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

(b)	Decrease in 2017 primarily due to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily due to a deferral of accumulated merger integration costs as regulatory assets in 2017.

(c)	Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016.

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

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

---

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

(b)	Regulatory asset amortization increased due to additional regulatory assets related to rate case activity.

(c)	Regulatory required programs increased as a result of higher amortization of the DC PLUG regulatory asset.

---

---

---

(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.

(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.

---

---

(a)	Decrease in 2017 primarily due to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily due to a deferral of accumulated merger integration costs as regulatory assets in 2017.

(b)	Related to EmPower Maryland energy efficiency customer credits.

(c)	Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016.

(d)	Decrease in 2017 primarily related to a review of capital projects in 2016.

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

(b)	Regulatory asset amortization increased due to additional regulatory assets related to rate case activity.

(c)	Regulatory required programs decreased primarily due to an EmPower Maryland surcharge rate decrease effective January 2018 and 2017.

---

---

---

(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.

---

(a)	Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016.

(b)	Decrease in 2017 primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily related to a deferral of accumulated merger integration costs as regulatory assets in 2017.

(c)	ACE is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues for the periods presented.

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

(b)	Regulatory asset amortization increased due to additional regulatory assets related to rate case activity.

(c)	Regulatory required programs decreased due to rate decreases effective October 2017 and 2016 respectively for the ACE Transition Bonds.

---

---

---

(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, gain on sale of assets and businesses and other non-cash charges. See Note 23 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information 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.

---

•	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

---

•	During 2018, 2017 and 2016, Generation had net (payments) collections of approximately $(43) million, $28 million and $(66) 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 2016, Exelon had expenditures of $6.6 billion related to the PHI merger.

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

•	During 2018, Exelon and Generation had expenditures of $81 million and $57 related to the acquisitions of the Everett Marine Terminal and the Handley generating station, respectively.

•	During 2018, Exelon and Generation had proceeds of $85 million relating to the sale of Generation’s interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution services.

•	During 2017, Exelon and Generation had additional expenditures of $23 million and $178 million related to the acquisitions of ConEdison Solutions and the FitzPatrick nuclear generating station, respectively.

•	During 2017, Exelon and Generation had proceeds of $218 million from sales of long-lived assets, primarily related to the sale back of turbine equipment.

---

•	During 2016, Exelon and Generation had expenditures of $235 million and $58 million related to the acquisitions of ConEdison Solutions and the FitzPatrick nuclear generating station, respectively.

(a)	Total projected capital expenditures do not include adjustments for non-cash activity. Amounts are rounded to the nearest $25 million.

(b)	Includes corporate operations, BSC and PHISCO.

(c)	Includes PHISCO.

---

---

(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.

---

(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 additional information 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. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

---

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

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

---

(a)	See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information 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. See Note 5 — Mergers, Acquisitions and Dispositions for additional information.

---

(a)	See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information 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. See Note 5 — Mergers, Acquisitions and Dispositions for additional information.

---

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

(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.

---

(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.

---

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

---

(a)

Includes approximately $390 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.

---

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

---

(b)	ComEd had $440 million available in long-term debt refinancing authority and $1,093 million available in new money long-term debt financing authority from the ICC as of December 31, 2018 and has an expiration date of June 1, 2019 and August 1, 2021, respectively.

(c)	ACE is currently in the process of requesting its long-term debt financing authority.

•

ComEd is subject to restrictions in the event that (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.

•

PECO is subject to restrictions in the event that (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued.

•	BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade.

•

Pepco, DPL and ACE are subject to certain dividend restrictions established by settlements approved in the District of Columbia, Maryland, Delaware, and New Jersey. Pepco, DPL and ACE are prohibited from paying a dividend on their common shares if (a) after the dividend payment, Pepco's, DPL's or ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the DCPSC, MDPSC, DPSC, and NJBPU or (b) Pepco's, DPL's or ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%.

---

(a)	Includes $390 million due after 2024 to ComEd and PECO financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 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, 2018. Includes estimated interest payments due to ComEd and PECO financing trusts.

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

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

(e)

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, 2018. 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 $126 million, $56 million, $35 million, $26 million, $20 million and $155 million for 2019, 2020, 2021, 2022, 2023 and thereafter, respectively.

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

(g)	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.

(h)

Represents the future estimated value at December 31, 2018 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.

---

(i)	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 4 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(j)	Represents commitments for Generation's ongoing investments in new natural gas generation construction.  As of December 31, 2018, 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 2019.

(k)	Under their operating agreements with PJM, ComEd, PECO, BGE, DPL and ACE are committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd, PECO, BGE, DPL and ACE’s expected portion of the costs to pay for the completion of the required construction projects.

(l)	See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding SNF obligations.

(m)	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.

(n)

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 until all the qualified plans are fully funded on an ABO basis, and the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions. These amounts represent estimates that are based on assumptions that are subject to change. Qualified pension contributions for years after 2024 are not included. See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding estimated future pension benefit payments.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 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, 2018.

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

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

(d)

Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts represent Generation’s expected payments under these arrangements at December 31, 2018. 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 $126 million, $56 million, $35 million, $26 million, $20 million and $155 million for 2019, 2020, 2021, 2022, 2023 and thereafter, respectively.

(e)	Primarily represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG.

(f)

Represents the future estimated value at December 31, 2018 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.

(g)	Represents commitments for Generation's ongoing investments in new natural gas generation construction.  As of December 31, 2018, 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 2019.

---

(h)	See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding SNF obligations.

(a)	Includes $206 million due after 2024 to a ComEd financing trust.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 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, 2018. Includes estimated interest payments due to the ComEd financing trust.

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

(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.

(e)

Represents the future estimated value at December 31, 2018 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.

(g)	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 2024 to PECO financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

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

(d)

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

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

(f)

Represents the future estimated value at December 31, 2018 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.

(g)	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.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

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

---

(c)

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 2019 - 2023, was $1 million. 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 table above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million, and $14 million related to years 2019 - 2022, respectively.

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

(g)

Represents the future estimated value at December 31, 2018 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.

(h)	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.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

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

(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, 2018 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)	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 4 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(f)	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.

---

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

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

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

(d)

Represents the future estimated value at December 31, 2018 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)	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 4 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

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

(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, 2018 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.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

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

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

(d)

Represents the future estimated value at December 31, 2018 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, 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.

•	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.

•	operating leases and rate relief commitments, see Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

•	the nuclear decommissioning and SNF obligations, see Note 15 — Asset Retirement Obligations and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

•	regulatory commitments, see Note 4 — 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 22 — 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.

---

---

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

(b)

For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2017 and 2018, ComEd recorded a regulatory liability of $256 million and $249 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $18 million of decreases in fair value and an increase for realized losses due to settlements of $20 million in purchased power expense associated with floating-to-fixed energy swap suppliers for the year ended December 31, 2017. ComEd recorded $24 million of decreases in fair value

---

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

(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 fair value from contracts received at acquisition of the Everett Marine Terminal.

(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 $357 million at December 31, 2018.

(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 $357 million at December 31, 2018.

---

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

---

(a)	As of December 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $17 million of cash and $35 million of letters of credit.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

(a)

Exelon’s consolidated assets include $9,667 million and $9,597 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,548 million and $3,618 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities for additional information.

---

---

---

---

---

(a)

Generation’s consolidated assets include $9,634 million and $9,556 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,480 million and $3,516 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities for additional information.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

(a)

PHI’s consolidated total assets include $33 million and $41 million at December 31, 2018 and 2017, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $69 million and $102 million at December 31, 2018 and 2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities for additional information.

---

(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 5 — Mergers, Acquisitions and Dispositions.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

(a)

ACE’s consolidated assets include $23 million and $29 million at December 31, 2018 and 2017, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $59 million and $90 million at December 31, 2018 and 2017, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 - Variable Interest Entities for additional information.

---

---

---

---

---

---

---

•	requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest,

•	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.

---

---

---

---

---

---

---

---

---

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

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

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

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

•	Evaluated the transition practical expedients available under the standard.

•	Identified, assessed and documented technical accounting issues, policy considerations and financial reporting implications.

•	Identified and implemented changes to processes and controls to ensure all impacts of the new standard are effectively addressed.

---

---

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

---

---

•

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 RSSA, through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017. (see Note 4 — Regulatory Matters for additional details),

•	Generation provided a $400 million loan to CENG. As of December 31, 2018, the remaining obligation is $196 million, including accrued interest. The remaining balance was fully paid by CENG in January 2019.

•

Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 22 — Commitments and Contingencies for more details),

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

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

---

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

---

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

---

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

(b)

These items represent amounts in 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 $9 million and $39 million as of December 31, 2018 and December 31, 2017, respectively; offset by payables to ZionSolutions LLC of $9 million and $37 million as of December 31, 2018 and December 31, 2017, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE.

---

---

---

---

---

(a)	Includes the annual ongoing TCJA tax savings further discussed below.

(b)

Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1st, 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 from the year (annual reconciliation).

---

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

(d)	On September 7, 2018, Pepco submitted an updated filing for an increase of $4 million to the customer base rate credit established in connection with the merger between Exelon and PHI for residential customers, representing the TCJA benefits for the period January 1, 2018 through August 12, 2018.

(e)	The DPL Maryland base rate case proceeding was resolved through a settlement agreement, which did not specify an overall ROE. The settlement agreement included an ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs.

(a)	Requested increase is before New Jersey sales and use tax and includes $40 million of higher depreciation expense related to its updated depreciation study and the annual ongoing TCJA tax savings further discussed below.

(b)	ACE plans to put interim rates in effect on or around May 21, 2019, subject to refund, as allowed by the regulation.

---

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

(b)

The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See further discussion below.

(c)	The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE.

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

(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.

---

(a)

On May 17, 2018, the PAPUC issued an order directing Pennsylvania utility companies without an existing base rate case, including PECO’s gas distribution business, to start passing back the savings from January 1, 2018 onward through a negative surcharge mechanism to be effective on July 1, 2018. Pursuant to that order, PECO filed a negative surcharge mechanism and began on July 1, 2018, to return the estimated annual 2018 tax savings above to its natural gas distribution customers.

---

(a)

ComEd’s 2018 approved revenue requirement above reflects an increase of $41 million for the initial year revenue requirement for 2018 and 2019 and an increase of $1 million related to the annual reconciliation for 2017. The revenue requirement for 2018 and 2019 and the annual reconciliation for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.

---

---

---

---

(a)	Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018.

---

---

---

---

---

---

---

---

(a)	Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.

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

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

---

---

---

---

(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 22-Commitments and Contingencies for additional information regarding SNF obligations to the DOE.

---

---

---

(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 as regulatory assets of $24 million, $8 million, $8 million, and $8 million at PHI, Pepco, DPL and ACE, respectively. For the year ended December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $8 million, $6 million, $11 million and $4 million at ComEd, BGE, Pepco and DPL, respectively. For the Successor period March 24, 2016 to December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $16 million at PHI. See Note 4 - Regulatory Matters for additional information.

---

(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.

---

---

(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,004 million and $1,196 million at December 31, 2018 and 2017, respectively.

(b)

Includes Generation’s buildings under capital lease with a net carrying value of $5 million and $7 million at December 31, 2018 and 2017, respectively. The original cost basis of the buildings was $47 million as of both December 31, 2018 and 2017, and total accumulated amortization was $42 million and $40 million, as of December 31, 2018 and 2017, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2018 and 2017 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, 2018 and 2017. Includes land held for future use and non-utility property at ComEd, PECO, BGE, Pepco, DPL and ACE of $39 million, $19 million, $25 million, $61 million, $17 million and $28 million, respectively, at December 31, 2018.

(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,969 million and $3,159 million as of December 31, 2018 and 2017, respectively.

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

---

(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,004 million and $1,196 million at December 31, 2018 and 2017, respectively.

(b)	Includes buildings under capital lease with a net carrying value of $5 million and $7 million at December 31, 2018 and 2017, respectively. The original cost basis of the buildings was $47 million as of both December 31, 2018 and 2017, and total accumulated amortization was $42 million and $40 million, as of December 31, 2018 and 2017, respectively.

(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,969 million and $3,159 million as of December 31, 2018 and 2017, respectively.

---

(a)	Includes buildings under capital lease with a net carrying value at both December 31, 2018 and 2017 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, 2018 and 2017.

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

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

---

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

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

---

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

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

---

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

---

(a)	Includes interest expense to affiliates.

---

---

---

(a)	Reflects incremental accelerated depreciation for TMI and Oyster Creek. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018.

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

(c)

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.

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

(e)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments. Excludes the charge to Operating and maintenance expense from the ARO remeasurement due to the announced sale of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions for additional information.

(f)	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.

(g)

For Quad Cities based on the regulatory agreement with the ICC, 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.

---

•

First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 capacity commitment periods. FERC denied the waiver request on procedural grounds on July 2, 2018 and ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.

---

•	Second, in accordance with FERC's July 2, 2018 order, on August 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons, which FERC accepted on December 3, 2018.

•

Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs, including the cost of procuring fuel. In its July 2, 2018 order, FERC ordered ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. In January 2019, ISO-NE has indicated that it intends to seek an extension of the deadline for this filing to November 15, 2019.

---

(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, 2018 and 2017.

(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 of the Salem generating plant substation. 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 substation.

(d)	Generation, DPL and ACE own a 44.24%, 11.91% and 4.83% 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 and general plant.

---

(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).

(b)	Reflects goodwill recorded in 2016 from the PHI merger.

---

---

(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 in 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.

(a)	At Exelon and Generation, amortization of unamortized energy contracts totaling $14 million, $35 million and $35 million for the years ended December 31, 2018, 2017 and 2016, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.

---

(b)	At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.

---

---

---

---

---

•	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.

---

---

---

---

---

(a)

Generation excludes cash of $283 million and $259 million at December 31, 2018 and 2017 and restricted cash of $39 million and $127 million at December 31, 2018 and 2017.  Exelon excludes cash of $458 million and $389 million at December 31, 2018 and 2017 and restricted cash of $80 million and $145 million at December 31, 2018 and 2017 and includes long-term restricted cash of $185 million and $85 million at December 31, 2018 and 2017, which is reported in Other deferred debits in the Consolidated Balance Sheets.

(b)	Includes $50 million and $77 million of cash received from outstanding repurchase agreements at December 31, 2018 and 2017, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes derivative instruments of $44 million and less than $1 million, which have a total notional amount of $1,432 million and $811 million at December 31, 2018 and 2017, 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 $130 million and $82 million at December 31, 2018 and 2017, 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)	Excludes net assets of less than $1 million at December 31, 2018 and 2017. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(f)	The amount of unrealized gains/(losses) at Generation totaled less than $1 million and $1 million for the years ended December 31, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the years ended December 31, 2018 and 2017, respectively.

(g)

Collateral posted/(received) from counterparties totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2018. 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.

(h)	Of the collateral posted/(received), $(94) million and $(117) million represents variation margin on the exchanges as of December 31, 2018 and 2017, respectively.

---

---

(a)

ComEd excludes cash of $93 million and $45 million at December 31, 2018 and 2017 and restricted cash of $28 million at December 31, 2018 and includes long-term restricted cash of $166 million and $62 million at December 31, 2018 and December 31, 2017, which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $24 million and $47 million at December 31, 2018 and 2017.  BGE excludes cash of $7 million and $17 million at December 31, 2018 and 2017 and restricted cash of $2 million and $1 million at December 31, 2018 and December 31, 2017.

(b)	The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the years ended December 31, 2018 and December 31, 2017.

(c)	The Level 3 balance consists of the current and noncurrent liability of $26 million and $223 million, respectively, at December 31, 2018, and $21 million and $235 million, respectively, at December 31, 2017, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

---

---

(a)

PHI excludes cash of $39 million and $12 million at December 31, 2018 and 2017 and includes long term restricted cash of $19 million and $23 million at December 31, 2018 and 2017 which is reported in Other deferred debits in the Consolidated Balance Sheets.  Pepco excludes cash of $15 million and $4 million at December 31, 2018 and 2017. DPL excludes cash of $8 million and $2 million at December 31, 2018 and 2017. ACE excludes cash of $7 million and $2 million at December 31, 2018 and 2017 and includes long-term restricted cash of $19 million and $23 million at December 31, 2018 and 2017 at December 31, 2018 and 2017 which is reported in Other deferred debits in the Consolidated Balance Sheets.

(b)	The amount of unrealized gains/(losses) at PHI totaled $1 million for the years ended December 31, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Pepco totaled less than $1 million for the years ended December 31, 2018 and 2017, respectively.

---

---

(a)	Includes a reduction for the reclassification of $265 million and $352 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2018 and 2017, respectively.

(b)

Includes $24 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2018. 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.

(c)	The amounts represented are life insurance contracts at Pepco.

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

(e)	Includes $(19) million of fair value from contracts acquired as a result of the Everett Marine Terminal acquisition

---

---

---

---

---

(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 $76 million as of December 31, 2018.

(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.

---

(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 $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.

---

---

(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 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 $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018.

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

(d)	Of the collateral posted/(received), $(94) million represents variation margin on the exchanges.

---

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

---

---

---

(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.

---

(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.

---

(a)	On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. The table excludes amounts of $800 million of fixed-to-floating hedges that were previously designated as fair value hedges by Exelon and $636 million of floating-to-fixed hedges that were previously designated as cash flow hedges by Exelon and Generation as of December 31, 2017.

---

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

---

(a)	As of December 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $17 million of cash and $35 million of letters of credit. The credit collateral does not include non-liquid collateral.

---

---

(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.

---

---

(a)	Excludes $545 million and $480 million in bilateral credit facilities at December 31, 2018 and 2017, respectively, and $159 million and $179 million in credit facilities for project finance at December 31, 2018 and 2017, respectively. These credit facilities do not back Generation's commercial paper program.

(b)

At December 31, 2018, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. At December 31, 2017, excludes $128 million of credit facility agreements arranged at minority and community banks at 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.

(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.

---

(a)

Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. As of December 31, 2018, letters of credit issued under these facilities totaled $5 million and $2 million for Generation and BGE, respectively.

---

---

---

---

---

(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 $36 million and $53 million at December 31, 2018 and 2017, respectively. Lease payments of $21 million, $5 million, $1 million, $1 million, less than $1 million, and $8 million will be made in 2019, 2020, 2021, 2022, 2023, 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.

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

(e)	In January 2019, $300 million of ComEd long-term debt due within one year was paid in full.

(f)	Excludes interest on CEU Upstream nonrecourse debt, see discussion below.

---

(a)	Includes Generation’s capital lease obligations of $14 million and $18 million at December 31, 2018 and 2017, respectively. Generation will make lease payments of $7 million, $5 million, $1 million, and $1 million in 2019, 2020, 2021, and 2022, respectively. Lease payments of less than $1 million annually will be made from 2023 through expiration of the final capital lease in 2024.

(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.

(c)	Excludes interest on CEU Upstream nonrecourse debt, see discussion below.

---

(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, 2018 and 2017, respectively. Lease payments of less than $1 million annually will be made from 2019 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.

(d)	In January 2019, the $300 million balance was paid in full.

(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.

---

(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 $14 million and $27 million at December 31, 2018 and 2017, respectively.

---

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

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

(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.

(b)	Maturities of ACE's Transition Bonds outstanding at December 31, 2018 are $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.

---

---

---

(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 remained in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA.

---

(a)

Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO was 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.

---

(a)	Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. Components of income tax expense or benefit are recast to reflect the impact of the new standard.

---

---

(a)	Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. The effective income tax rates are recast to reflect the impact of the new standard.

(b)	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 Note 4 - Regulatory Matters for additional information.

(c)	Included are impacts for TCJA 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.

(d)	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.

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

(f)	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.

---

---

(a)	Includes remeasurement impacts related to the TCJA.

---

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

(b)	Exelon’s and Generation's state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2019.

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

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

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

(f)	Pepco's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2033.

(g)	DPL's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2030.

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

---

---

---

---

---

(a)	Includes $22 million and $13 million as the current portion of the ARO at December 31, 2018 and 2017, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

(b)	Includes $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 5 — Mergers, Acquisitions and Dispositions for additional information.

---

---

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

(b)	Net unrealized (losses) gains 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.

---

(a)	Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized gains and losses associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.

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

---

---

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

(b)	In 2018, Pepco recorded an increase of $22 million in Operating and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of an annual ARO study. Buzzard Point is a waterfront property in the District of Columbia occupied by an active substation and former Pepco operated steam plant building, which Pepco retired and closed in 1981.

---

---

---

(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.

---

(a)	The pension actuarial gain in 2018 primarily reflects an increase in the discount rate. The OPEB actuarial gain in 2018 primarily reflects an increase in the discount rate and favorable health care claims experience. The pension and OPEB actuarial losses in 2017 primarily reflect a decrease in the discount rate.

(b)	Exelon recorded pension and OPEB obligations associated with its acquisition of Fitzpatrick on March 31, 2017.

---

(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.

---

---

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

---

(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, 2018. Certain benefit plans used individual rates ranging from 4.13% - 4.36% and 4.27% - 4.38% 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, 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.

(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, 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.

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

---

(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 for the PHI predecessor for the period from January 1, 2016, to March 23, 2016.

(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, 2018. 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 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.

(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, 2016. Certain benefit plans used the individual rates ranging from 3.68%-4.14% and 4.32%-4.43% for pension and other postretirement plans, respectively.

---

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

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

(f)	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.

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

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

(a)	Exelon's and Generation's pension contributions include $21 million and $25 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 and 2016, respectively. There were no pension contributions for the year ended December 31, 2018.

(b)	Includes $2 million, $4 million, and $6 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2018, 2017, and 2016, 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.

---

---

(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.

---

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

---

---

(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 less than $1 million and $6 million, which have a total notional amount of $5,991 million and $3,606 million at December 31, 2018 and 2017, 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)	Prior year amounts reflect a reclassification from Not subject to leveling into Level 3.

(e)	Excludes net liabilities of $44 million and net assets of $2 million at December 31, 2018 and 2017, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable.

---

(a)	Prior year amounts reflect a reclassification from Not subject to leveling into Level 3.

(b)	Represents cash settlements only.

---

---

(a)	Includes $13 million related to CENG for the year ended December 31, 2016.

(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.

---

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

(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.

---

---

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

---

(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, 2018 and 2017 was not material.

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

---

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

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

---

(a)	Excludes 1,131,487 and 1,488,383 of restricted stock units issued to retirement-eligible employees as of December 31, 2018 and 2017, respectively, as they are fully vested.

(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2018.

---

(a)	Excludes 3,586,259 and 2,723,440 of performance share awards issued to retirement-eligible employees as of December 31, 2018 and 2017, respectively, as they are fully vested.

(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2018.

(a)	As of December 31, 2018, $33 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years.

---

(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.

---

---

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

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

(c)

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

(d)

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

---

---

(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 information.

---

---

(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 $61 million, $19 million of which is a guarantee by Pepco, $26 million by DPL and $16 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)	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)	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)	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 $61 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 $19 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 Pepco 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 $26 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 DPL 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 ACE 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 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements.

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

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

(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 $493 million, $508 million and $604 million during 2018, 2017 and 2016, respectively. Excludes contract amortization associated with purchase accounting and contract acquisitions.

---

---

(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.

---

(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.

•	ComEd has identified 42 sites, 21 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 21 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2023.

---

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

•	BGE has identified 13 sites, 9 of which have been remediated and approved by the MDE and 4 that require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2019.

•	DPL has identified 3 sites, 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.

---

---

---

---

---

---

(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 in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

---

---

---

---

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

(b)	Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of net 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.

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

---

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

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

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

---

(a)	Includes the elimination of decommissioning-related activities 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 5 - Mergers, Acquisitions and Dispositions for additional information.

(d)	Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 4 — Regulatory Matters for additional information.

---

---

(a)	Includes the elimination of decommissioning-related activities 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 5 - Mergers, Acquisitions and Dispositions for additional information.

(d)	Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 4 — Regulatory Matters for additional 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 additional information on the like-kind exchange tax position.

---

(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 5 - Mergers, Acquisitions and Dispositions for additional 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 4 — Regulatory Matters for additional 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 additional information on 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 5 - Mergers, Acquisitions and Dispositions for additional information.

---

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

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

(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 a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate.

---

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

(b)	The Registrants’ debt and equity security investments are recorded at fair market value.

---

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

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

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

---

•	New England represents operations within ISO-NE.

•	New York represents operations within ISO-NY.

•	ERCOT represents operations within Electric Reliability Council of Texas.

•	Other Power Regions:

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

•	West represents operations in the WECC, including California ISO.

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

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

•	West represents operations in the WECC, including California ISO.

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

•	New England represents operations within ISO-NE.

---

---

---

(a)	See Note 25 — Related Party Transactions for additional information on intersegment revenues.

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

(c)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.

(d)

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory authoritative 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, 2018.

---

---

---

(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.

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

(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $38 million and $52 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value in 2017 and 2016, respectively, unrealized mark-to-market losses of $262 million, $131 million, and $500 million in 2018, 2017, and 2016, respectively, and elimination of intersegment revenues.

---

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

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $54 million and $57 million decrease in RNF for the amortization of intangible assets and liabilities related to commodity contracts in 2017 and 2016, respectively, unrealized mark-to-market losses of $319 million, $175 million, and $41 million in 2018, 2017, and 2016, respectively, accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 8 - Early Plant Retirements of $57 million, $12 million and $60 million for the year ended December 31, 2018, 2017, and 2016 and the elimination of intersegment RNF.

---

---

---

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

(b)

Includes operating revenues from affiliates of $27 million, $7 million, $8 million, $15 million, $6 million, $8 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018, $15 million, $6 million, $5 million, $3 million, $6 million, $8 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, in 2017, and $15 million, $7 million, $7 million, $2 million, $5 million, $7 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2016.

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

(d)	Includes operating revenues from affiliates of $1 million and $21 million at PECO and BGE, respectively, in 2018, $1 million and $11 million at PECO and BGE, respectively, in 2017, and $1 million and $14 million at PECO and BGE, respectively, in 2016.

(e)	Includes late payment charge revenues.

(f)	Includes operating revenues from affiliates of $47 million and $43 million at PHI in 2017 and 2016, respectively.

---

(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 authoritative guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations. See Note 4—Regulatory Matters for additional information.

---

---

---

(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.

(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.

(c)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.

(d)	Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

(e)	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.

(f)	Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.

(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 for additional information.

(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 affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets.

---

(a)	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs and ZECs from Generation.

---

(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)	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.

---

(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.

(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.

---

(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.

(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.

---

(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.

---

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

(b)	Pepco procures a portion of its electricity supply requirements from Generation under its MDPSC and DCPSC approved market based SOS commodity programs.

(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 performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco.

---

(e)	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018.

---

(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.

(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 performed underground transmission construction services, including services that are treated as capital costs, for DPL.

(d)	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018.

(a)	ACE purchases electric supply from Generation under contracts executed through its competitive procurement process.

---

(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.

(c)	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018.

---

---

---

---

---

---

---

(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. Unvested performance shares are subject to performance metrics ranging from 0% to 150% of target award values and to a total shareholder return modifier. For performance shares granted in 2016, 2017 and 2018, the total includes the number of shares that could be issued pursuant to the terms of the Exelon LTIP plan, which provides that final payouts are made 50% in shares of stock and 50% in cash, and if the performance and total shareholder return modifier metrics were both at maximum, representing a best case performance scenario, for a total of 4,942,100 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 2,471,000. The deferred stock units granted to directors includes 433,400 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon Board of Directors. Conversion of the deferred stock units to shares occurs after a director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 19 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans.

(2)	The weighted-average price reported in column B does not take the performance shares and shares credited to deferred compensation plans into account.

(3)	Includes 18,410,700 shares remaining available for issuance from the employee stock purchase plan.

---

---

---

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

---

---

---

---

---

---

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

---

---

(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 affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets.

---

(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $13 million, $15 million, and $23 million for the years ended December 31, 2018, 2017 and 2016, 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)	Primarily reflects the reclassification of assets as held for sale.

(e)	Write-off of individual accounts receivable.

---

---

(a)	Primarily reflects the reclassification of assets as held for sale.

---

---

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

(b)	Write-off of individual accounts receivable.

---

---

(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $13 million, $15 million, and $23 million for the years ended December 31, 2018, 2017, and 2016, respectively.

(b)	Primarily charges for late payments.

(c)	Write-off of individual accounts receivable.

---

---

(a)	Write-off of individual accounts receivable.

---

---

(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

---

---

(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

---

---

(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

---

---

(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

*	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.

---

---

---

---

---

---

---

---

---

---