News Column

EXELON CORP - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

July 31, 2014

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

Exelon Corporation

General

Exelon, a utility services holding company, operates through the following principal subsidiaries:

Generation, whose integrated business consists of owned, contracted and

investments in electric generating facilities managed through customer

supply of electric and natural gas products and services, including

renewable energy products, risk management services and natural gas exploration and production activities. As a result of the Constellation merger, Generation owns a 50.01% interest in CENG. On April 1, 2014, Generation assumed the operating licenses and corresponding operational control of CENG's nuclear fleet. As a result, Exelon and Generation consolidate CENG's financial position and results of operations into their businesses.



ComEd, whose business consists of the purchase and regulated retail sale

of electricity and the provision of distribution and transmission services

in northern Illinois, including the City of Chicago. PECO, whose business consists of the purchase and regulated retail sale



of electricity and the provision of distribution and transmission services

in southeastern Pennsylvania, including the City of Philadelphia, and the

purchase and regulated retail sale of natural gas and the provision of

distribution services in the Pennsylvania counties surrounding the City of

Philadelphia. BGE, whose business consists of the purchase and regulated retail sale of



electricity and the provision of distribution and transmission services in

central Maryland, including the City of Baltimore, and the purchase and

regulated retail sale of natural gas and the provision of distribution

services in central Maryland, including the City of Baltimore.

Exelon has nine reportable segments consisting of Generation's six power marketing reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and other regions in Generation), ComEd, PECO and BGE. See Note 20 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's reportable segments. Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon's corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities. Exelon's consolidated financial information includes the results of its four separate operating subsidiary registrants, Generation, ComEd, PECO and BGE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management's Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO and BGE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. 155



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Executive Overview

Financial Results. The following consolidated financial results reflect the results of Exelon for the three and six months ended June 30, 2014 compared to the corresponding periods in 2013. All amounts presented below are before the impact of income taxes, except as noted. Three Months Ended June 30, Favorable 2014 2013 (Unfavorable) Generation(a) ComEd PECO BGE Other Exelon Exelon Variance Operating revenues $ 3,789 $ 1,128$ 656$ 653$ (202 )$ 6,024$ 6,141 $ (117 ) Purchased power and fuel 1,835 269 241 268 (201 ) 2,412 2,419 7 Revenue net of purchased power and fuel(b) 1,954 859 415 385 (1 ) 3,612 3,722 (110 ) Other operating expenses Operating and maintenance 1,413 355 184 188 26 2,166 1,892 (274 ) Depreciation and amortization 254 174 59 89 14 590 533 (57 ) Taxes other than income 118 72 38 53 7 288 271 (17 ) Total other operating expenses 1,785 601 281 330 47 3,044 2,696 (348 ) Equity in losses of unconsolidated affiliates (1 ) - - - 1 - (21 ) 21 Gain on consolidation of CENG 261 - - - - 261 - 261 Operating income (loss) 429 258 134 55 (47 ) 829 1,005 (176 ) Other income and (deductions) Interest expense, net (86 ) (80 ) (28 ) (27 ) (17 ) (238 ) (252 ) 14 Other, net 228 5 1 5 4 243 (17 ) 260 Total other income and (deductions) 142 (75 ) (27 ) (22 ) (13 ) 5 (269 ) 274 Income (loss) before income taxes 571 183 107 33 (60 ) 834 736 98 Income taxes (benefit) 199 72 23 14 (31 ) 277 239 (38 ) Net income (loss) 372 111 84 19 (29 ) 557 497 60 Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends 32 - - 3 - 35 7 (28 ) Net income (loss) attributable to common shareholders $ 340 $ 111$ 84$ 16$ (29 )$ 522$ 490 $ 32 156



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Table of Contents Six Months Ended June 30, Favorable 2014 2013 (Unfavorable) Generation(a) ComEd PECO BGE Other Exelon Exelon Variance Operating revenues $ 8,179 $ 2,262 $



1,649 $ 1,707$ (536 )$ 13,261$ 12,223 $ 1,038 Purchased power and fuel

5,191 589 705 797 (530 ) 6,752 5,400



(1,352 )

Revenue net of purchased power and fuel(b) 2,988 1,673 944 910 (6 ) 6,509 6,823



(314 )

Other operating expenses Operating and maintenance 2,499 681 464 376 4 4,024 3,656 (368 ) Depreciation and amortization 466 347 117 197 27 1,154 1,076 (78 ) Taxes other than income 223 149 80 113 15 580 548 (32 ) Total other operating expenses 3,188 1,177 661 686 46 5,758 5,280 (478 ) Equity in earnings (loss) of unconsolidated affiliates (20 ) - - - - (20 ) (30 ) 10 Gain on consolidation of CENG 261 - - - - 261 - 261 Operating income (loss) 41 496 283 224 (52 ) 992 1,513



(521 )

Other income and (deductions) Interest expense, net (172 ) (160 ) (56 ) (55 ) (22 ) (465 ) (876 ) 411 Other, net 318 10 3 9 8 348 155 193 Total other income and (deductions) 146 (150 ) (53 ) (46 ) (14 ) (117 ) (721 ) 604 Income (loss) before income taxes 187 346 230 178 (66 ) 875 792 83 Income taxes (1 ) 137 57 72 (41 ) 224 294 70 Net income (loss) 188 209 173 106 (25 ) 651 498 153 Net (loss) income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends 33 - - 6 - 39 12 (27 ) Net income (loss) attributable to common shareholders $ 155 $ 209$ 173$ 100$ (25 )$ 612$ 486 $ 126



(a) Includes the operations of CENG from April 1, 2014 through June 30, 2014.

(b) The Registrants' evaluate operating performance using the measure of revenue

net of purchased power and fuel expense. The Registrants' believe that

revenue net of purchased power and fuel expense is a useful measurement

because it provides information that can be used to evaluate its operational

performance. Revenue net of purchased power and fuel expense is not a

presentation defined under GAAP and may not be comparable to other companies'

presentations or deemed more useful than the GAAP information provided

elsewhere in this report.

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. Exelon's net income attributable to common shareholders was $522 million for the three months ended June 30, 2014 as compared to $490 million for the three months ended June 30, 2013, and diluted earnings per average common share were $0.60 for the three months ended June 30, 2014 as compared to $0.57 for the three months ended June 30, 2013. 157



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Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $110 million for the three months ended June 30, 2014 as compared to the same period in 2013. The quarter-over-quarter decrease in operating revenue net of purchased power and fuel expense was primarily due to the following unfavorable factors:



Decrease in Generation's revenue net of purchased power and fuel expense

of $442 million due to mark-to-market losses of $14 million in 2014 from

economic hedging activities compared to $428 million in mark-to-market

gains in 2013; and

The quarter-over-quarter decrease in operating revenue net of purchased power and fuel expense was partially offset by the following favorable factors:

Increase in Generation's electric revenue net of purchased power and fuel

expense of $184 million, primarily due to the inclusion of CENG's results

for the full quarter ended June 30, 2014 and increased capacity prices

related to the Reliability Pricing Model (RPM) for the PJM

Interconnection, LLC (PJM) market, partially offset by lower realized

energy prices, and lower generation volumes (excluding CENG); Decrease in Generation's amortization expense for the acquired energy contracts recorded at fair value at the date of the merger with Constellation and the integration with CENG of $117 million;



Increase in BGE's revenue net of purchased power and fuel expense of $20

million, primarily due to increased distribution revenue as a result of

2013 electric and natural gas distribution rate case orders issued by the

Maryland PSC; and



Increase in ComEd's revenue net of purchased power expense of $27 million

primarily due to higher electric distribution revenue resulting from

increased capital investment and increased cost recovery associated with

energy efficiency programs, partially offset by lower distribution formula

rate revenue due to decreased pension and non-pension postretirement

expense.

Operating and maintenance expense increased by $274 million for the three months ended June 30, 2014 as compared to the same period in 2013 primarily due to the following unfavorable factors:



Increase in Generation's labor, contracting and materials costs of $126

million primarily due to the inclusion of CENG's results for the second

quarter ended June 30, 2014; An increase of $61 million as a result of an increase in the number of



planned nuclear refueling outage days at Generation during the second

quarter; Long lived asset impairments of $110 million in 2014 compared to $106

million in 2013; An increase of $16 million in Generation's reserve for future asbestos-related bodily injury claims; Increased uncollectible accounts expense at BGE of $10 million; and



Increase at ComEd of $18 million primarily relating to increased spend on

energy and efficiency programs.

The year-over-year increase in operating and maintenance expense was partially offset by the following favorable factor:

A decrease in pension and non-pension postretirement benefits expense of

$57 million as a result of cost savings primarily at Exelon, Generation,

and ComEd for plan design changes for certain OPEB plans, and the

favorable impact of higher actuarially assumed pension and OPEB discount

rates for 2014, partially offset by the inclusion of CENG's results for

the second quarter of 2014.

Depreciation and amortization expense increased by $57 million primarily due to the inclusion of CENG's results for the full quarter ended June 30, 2014 and increased capital expenditures across all operating companies. 158



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A $261 million gain recorded upon consolidation of CENG resulting from the difference in the fair value of CENG's net assets as of April 2014, and the equity method investment previously recorded on Generation's and Exelon's books and the settlement of pre-existing transactions between Generation and CENG.

Other, net increased by $260 million primarily as a result of the change in realized and unrealized gains and losses on NDT funds.

Exelon's effective income tax rates for the three months ended June 30, 2014 and 2013 were 33.2% and 32.5%, respectively. See Note 11 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. Exelon's net income attributable to common shareholders was $612 million for the six months ended June 30, 2014 as compared to net income attributable to common shareholders of $486 million for the six months ended June 30, 2013, and diluted earnings per average common share were $0.71 for the six months ended June 30, 2014 as compared to $0.57 for the six months ended June 30, 2013.



Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $314 million for the six months ended June 30, 2014 as compared to the same period in 2013. The year-over-year decrease in operating revenue net of purchased power and fuel expense was primarily due to the following unfavorable factors:

Decrease in Generation's revenue net of purchased power and fuel expense

of $769 million due to mark-to-market losses of $744 million in 2014 from

economic hedging activities compared to $25 million in mark-to-market

gains in 2013.

The year-over-year decrease in operating revenue net of purchased power and fuel expense was partially offset by the following unfavorable factors:

Increase in Generation's electric revenue net of purchased power and fuel

expense of $22 million primarily due to inclusion of CENG's results for

the quarter ended June 30, 2014 and increased capacity prices related to

the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM)

market, partially offset by lower realized energy prices, higher

procurement costs for replacement power, increased fossil fuel expense due

to extreme cold weather during the first quarter of 2014, and lower generation volumes (excluding CENG); Decrease in Generation's amortization expense for the acquired energy contracts recorded at fair value at the date of the merger with Constellation and the integration with CENG of $249 million;



Increase in BGE's revenue net of purchased power and fuel expense of $90

million, primarily due to increased distribution revenue as a result of

the 2013 electric and natural gas distribution rate case orders issued by

the Maryland PSC and increased cost recovery for energy efficiency and

demand response programs;



Increase in ComEd's revenue net of purchased power expense of $64 million

primarily due to increased distribution revenue due to recovery of

increased capital investments pursuant to ComEd's performance-based rate

formula, favorable weather conditions in the first quarter of 2014, and

increased cost recovery associated with energy efficiency programs,

partially offset by lower distribution formula rate revenue due to decreased pension and non-pension postretirement expense; and



Increase in PECO's revenue net of purchased power and fuel expense of $41

million, primarily due to favorable weather conditions in the first quarter of 2014. 159



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Operating and maintenance expense increased by $368 million for the six months ended June 30, 2014 as compared to the same period in 2013 primarily due to the following unfavorable factors:



Increase in Generation's labor, contracting and materials costs of $121

million primarily due to the inclusion of CENG's results for the second

quarter ended June 30, 2014; An increase of $75 million as a result of an increase in the number of

planned nuclear refueling outage days at Generation; An increase of $16 million in Generation's reserve for future asbestos-related bodily injury claims.



An increase in storm costs at PECO and BGE of $84 million and $13 million,

respectively; Increase at ComEd of $27 million primarily relating to increased spend on

energy and efficiency programs; and Increased uncollectible accounts expense at BGE of $13 million.



The year-over-year increase in operating and maintenance expense was partially offset by the following unfavorable factors:

A decrease in pension and non-pension postretirement benefits expense of

$72 million as a result of cost savings primarily at Exelon, Generation,

and ComEd for plan design changes for certain OPEB plans, and the

favorable impact of higher actuarially assumed pension and OPEB discount

rates for 2014, partially offset by the inclusion of CENG's results for

the second quarter of 2014; and Long-lived asset impairments of $110 million in 2014 compared to $127



million in 2013.

Depreciation and amortization expense increased by $78 million primarily as a result of the inclusion of CENG's results for a full quarter in 2014, increased depreciation expense across the operating companies for ongoing capital expenditures, and higher costs related to energy efficiency and demand response program expenditures.



A $261 million gain recorded upon consolidation of CENG resulting from the difference in the fair value of CENG's net assets as of April 2014, and the equity method investment previously recorded on Generation's and Exelon's books and the settlement of pre-existing transactions between Generation and CENG.

Interest expense decreased by $411 million primarily as a result of a favorable settlement in 2014 of certain income tax positions on Constellation's 2009-2012 tax returns and the impacts of a 2013 unfavorable franchise tax settlement.



Other, net increased by $193 million primarily as a result of the change in realized and unrealized gains and losses on NDT funds.

Exelon's effective income tax rates for the six months ended June 30, 2014 and June 30, 2013 were 25.6% and 37.1%, respectively. See Note 11 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. For further detail regarding the financial results for the three and six months ended June 30, 2014, including explanation of the non-GAAP measure revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below. Adjusted (non-GAAP) Operating Earnings. Exelon's adjusted (non-GAAP) operating earnings for the three months ended June 30, 2014 were $ 440 million, or $ 0.51 per diluted share, compared with adjusted (non-GAAP) operating earnings of $ 454 million, or $ 0.53 per diluted share, for the same period in 2013. Exelon's adjusted (non-GAAP) operating earnings for the six months ended June 30, 2014 were $970 million, or $1.12 per diluted share, compared with adjusted (non-GAAP) operating earnings of $1,056 million, or $1.23 per diluted share, for the same period in 2013. In addition to net income attributable to common shareholders, Exelon 160



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evaluates its operating performance using the measure of adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor's overall understanding of year-to-year operating results and provide an indication of Exelon's baseline operating performance. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The following table provides a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and six months ended June 30, 2014 as compared to the same period in 2013. The footnotes below the table provide tax expense (benefit) impacts: Three Months Ended June 30, 2014 2013 Earnings per Earnings per (All amounts after tax) Diluted Share Diluted Share Net Income Attributable to Common Shareholders $ 522 $ 0.60 $ 490 $ 0.57 Mark-to-Market Impact of Economic Hedging Activities (a) 8 0.01 (253 ) (0.30 ) Unrealized (Gains) Losses Related to NDT Fund Investments (b) (76 ) (0.09 ) 22 0.03 Merger and Integration Costs (c) 19 0.02 15 0.02 Amortization of Commodity Contract Intangibles (d) 23 0.03 115 0.13 Long-Lived Asset Impairment (e) 68 0.08 69 0.08 Gain on CENG integration (f) (159 ) (0.18 ) - - PHI Acquisition Costs (g) 12 0.01 - - Non-Controlling Interest (h) 23 0.03 - - Amortization of the Fair Value of Certain Debt (i) - - (4 ) - Adjusted (non-GAAP) Operating Earnings $ 440 $ 0.51 $ 454 $ 0.53 Six Months Ended June 30, 2014 2013 Earnings per Earnings per (All amounts after tax) Diluted Share Diluted Share Net Income Attributable to Common Shareholders $ 612 $ 0.71 $ 486 $ 0.57 Mark-to-Market Impact of Economic Hedging Activities(a) 451 0.52 (18 ) (0.02 ) Unrealized Gains Related to NDT Fund Investments(b) (84 ) (0.10 ) (14 ) (0.02 ) Merger and Integration Costs(c) 28 0.03 43 0.05 Amortization of Commodity Contract Intangibles(d) 54 0.06 232 0.27 Long-Lived Asset Impairment(e) 68 0.08 82 0.10 Tax Settlements(j) (35 ) (0.04 ) - - Gain on CENG integration(f) (159 ) (0.18 ) - - PHI Acquisition Costs(g) 12 0.01 - - Non-Controlling Interest(h) 23 0.03 - - Plant Retirement and Divestitures(k) - - (13 ) (0.02 ) Amortization of the Fair Value of Certain Debt(i) - - (7 ) (0.01 ) Remeasurement of Like-Kind Exchange Tax Position(l) - - 265 0.31 Adjusted (non-GAAP) Operating Earnings $ 970 $ 1.12 $ 1,056 $ 1.23 161



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(a) Reflects the impact of losses (gains) for the three months ended June 30,

2014 and June 30, 2013 (net of taxes of $(6) million and $163 million,

respectively), and six months ended June 30, 2014 and June 30, 2013 (net of

taxes of $(293) million and $13 million, respectively), on Generation's

economic hedging activities. See Note 9 - Derivative Financial Instruments of

the Combined Notes to Consolidated Financial Statements for additional detail

related to Generation's hedging activities.

(b) Reflects the impact of unrealized (gains) losses for the three months ended

June 30, 2014 and June 30, 2013 (net of taxes of $41 million and $(41)

million, respectively), and six months ended June 30, 2014 and June 30, 2013

(net of taxes of $47 million and $27 million, respectively), on Generation's

NDT fund investments for Non-Regulatory Agreement Units. See Note 12 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation's NDT fund investments.



(c) Reflects certain costs incurred for the three months ended June 30, 2014 and

June 30, 2013 (net of taxes of $3 million and $(10) million, respectively)

and for the six months ended June 30, 2014 and June 30, 2013 (net of taxes of

$(2) million and $(4) million, respectively), associated with the Constellation merger and CENG integration, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) integration initiatives and certain pre-acquisition contingencies.



(d) Reflects the non-cash impact for the three months ended June 30, 2014 and

2013 (net of taxes of $(26) million and $(73) million, respectively), and six

months ended June 30, 2014 and June 30, 2013 (net of taxes of $(46) million

and $(148) million, respectively), of the amortization of intangible assets,

net, related to commodity contracts recorded at fair value at the

Constellation merger date and at the CENG integration date.

(e) Reflects the 2014 charge to earnings for the three and six months ended

June 30, 2014 primarily related to the impairment of certain wind generating

assets (net of taxes of $(42) million). For the three and six months ended

June 30, 2013, reflects a charge to earnings (net of taxes of $(44) million

and $(53) million, respectively) related to Generation's cancellation of

previously capitalized nuclear uprate projects.

(f) Reflects the non-cash gain recorded upon consolidation of CENG in accordance

with the execution of the NOSA on April 1, 2014 (net of taxes of $103 million

for the three and six months ended June 30, 2014).

(g) Reflects certain costs incurred associated with the Pepco Holdings Inc.

acquisition, including professional fees and upfront credit facility fees

(net of taxes of $(8) million).

(h) Represents adjustments to account for the CENG interest not owned by

Generation, where applicable.

(i) Reflects the non-cash amortization of certain debt for the three and six

months ended June 30, 2013 (net of taxes of $3 million and $5 million,

respectively) recorded at fair value at the Constellation merger date which

was retired in the second quarter of 2013.

(j) Reflects a benefit for the six months ended June 30, 2014, related to the

favorable settlement in 2014 of certain income tax positions on

Constellation's 2009-2012 tax returns (net of tax of $(18) million).

(k) Reflects the impact associated with the sale or retirement of generating

stations (net of taxes of $5 million for the six months ended June 30, 2013).

(l) Reflects a non-cash charge to earnings resulting from the first quarter 2013

remeasurement of a like-kind exchange tax position taken on ComEd's 1999 sale

of fossil generating assets (net of taxes of $(102) million for the six

months ended June 30, 2013).

As discussed above, Exelon has incurred and will continue to incur costs associated with the Constellation merger, CENG transaction and PHI acquisition including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives, and certain pre-acquisition contingencies.



For the three and six months ended June 30, 2014 and 2013, expense has been recognized for costs incurred to achieve the Constellation merger, CENG transaction and PHI acquisition as follows:

Pre-tax Expense Three Months Ended June 30, 2014 Merger, Integration and Acquisition Costs: Generation ComEd PECO BGE Exelon Employee-Related(a) $ 1 $ - $ - $ - $ 1 Other(b) 15 - - - 35 Total $ 16 $ - $ - $ - $ 36 162



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Pre-tax Expense Three Months Ended June 30,



2013

Merger and Integration Costs: Generation ComEd PECO BGE Exelon Employee-Related(a) $ 7 $ - $ - $ - $ 7 Other(b) 13 - 2 1 18 Total $ 20 $ - $ 2$ 1$ 25 Pre-tax Expense Six Months Ended June 30, 2014 Merger, Integration and Acquisition Costs: Generation ComEd PECO BGE Exelon Employee-Related(a) $ 5 $ - $ - $ - $ 5 Other(b) 25 - - - 45 Total $ 30 $ - $ - $ - $ 50 Pre-tax Expense Six Months Ended June 30, 2013 Merger and Integration Costs: Generation ComEd PECO BGE Exelon Employee-Related(a) 13 - 1 - 14 Other(b) 30 - 4 (5 )(c) 32 Total $ 43 $ - $ 5$ (5 )$ 46



(a) Costs primarily for employee severance, pension and OPEB expense, and

retention bonuses. ComEd established a regulatory asset of $1 million during

the six months ended June 30, 2013. The majority of these costs are expected

to be recovered over a five-year period. These costs are not included in the

table above.

(b) Costs to integrate CENG and Constellation processes and systems into Exelon

and to terminate certain Constellation debt agreements. For the three months

ended June 30, 2014, includes professional fees at Exelon Corporate and

upfront credit facility fees incurred at Exelon Corporate to acquire PHI.

ComEd established a regulatory asset of $4 million and $7 million during the

three and six months ended June 30, 2013, for certain other merger and

integration costs, which are not included in the table above. BGE established

a regulatory asset of $2 million during the six months ended June 30, 2013

for certain other merger integration costs, which are not included in the

table above.

(c) BGE established a regulatory asset of $6 million at June 30, 2013 for certain

2012 other merger transaction costs as part of the 2013 electric and gas

distribution rate case order which are not included in the table above.

As of June 30, 2014, Exelon projects incurring total additional PHI acquisition and integration related expenses of $265 million and $239 million, respectively, over the next five years. Exelon expects to incur total additional CENG and integration related costs of $35 million, primarily in 2014. Pursuant to the conditions set forth by the MDPSC in its approval of the merger transaction, Exelon committed to provide a package of benefits to BGE customers, and make certain investments in the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion. The direct investment estimate includes $95 million to $120 million for the requirement to cause construction of a headquarters building in Baltimore for Generation's competitive energy businesses. On March 20, 2013, Generation signed a twenty-year lease agreement that was contingent upon the developer obtaining all required approvals, permits and financing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014 when these outstanding contingencies were met by the developer. The building is expected to be ready for occupancy in approximately 2 years. See Note 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information related to the lease commitments. 163



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Exelon's Strategy and Outlook for the remainder of 2014 and Beyond

Exelon's value proposition and competitive advantage come from its scope and scale across the energy value chain and its core strengths of operational excellence and financial discipline.

Generation's electricity generation strategy is to pursue opportunities that provide generation to load matching and that diversify the generation fleet by expanding Generation's regional and technological footprint. Generation leverages its energy generation portfolio to ensure delivery of energy to both wholesale and retail customers under long-term and short-term contracts, and in wholesale power markets. Generation's customer facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets. Exelon's utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of best practices to achieve improved operational and financial results. Combined, the utilities plan to invest approximately $15 billion over the next five years in smart meter technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company. Exelon's financial priorities are to maintain investment grade credit metrics at each of Exelon, Generation, ComEd, PECO and BGE, and to return value to Exelon's shareholders with a sustainable dividend throughout the energy commodity market cycle and through earnings growth from attractive investment opportunities. In pursuing its strategies, Exelon has exposure to various market and financial risks, including the risk of price fluctuations in the power 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 prices of natural gas and coal, which drive the market prices that Generation can obtain for the output of its power plants, (2) the rate of expansion of subsidized low-carbon generation in the markets in which Generation's output is sold, (3) the effects on energy demand due to factors such as weather, economic conditions and implementation of energy efficiency and demand response programs, and (4) the impacts of increased competition in the retail channel. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these market pricing issues.



Proposed Merger with Pepco Holdings, Inc. (Exelon)

On April 29, 2014, Exelon and Pepco Holdings, Inc. (PHI) signed an agreement and plan of merger (as subsequently amended and restated as of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Under the Merger Agreement, PHI's shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. Exelon intends to fund the all-cash transaction using a combination of approximately $3.5 billion of debt, up to $1 billion cash from asset sales primarily at Generation, and the remainder through issuance of equity (including mandatory convertible securities). In addition, Exelon entered into a 364-day $7.2 billion senior unsecured bridge credit facility to support the contemplated transaction and provide flexibility for timing of permanent financing, which has subsequently been reduced to $4.2 billion as a result of the equity issuances. In connection with the Merger Agreement, Exelon entered into a subscription agreement under which it purchased $90 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities in PHI, in the second quarter of 2014, with additional investments of $18 million to be made quarterly up to a maximum aggregate investment of $180 million.



The transaction must be approved by the shareholders of PHI. Completion of the transaction is also conditioned upon approval by the FERC, the District of Columbia Public Service Commission and several state

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commissions including Delaware Public Service Commission, MDPSC, the New JerseyBoard of Public Utilities and the Virginia Department of Public Utilities. In addition, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), the transaction cannot be completed until Exelon has made required notifications and given certain information and materials to the Federal Trade Commission (FTC) and/or the Antitrust Division of the United States Department of Justice (DOJ) and until specified waiting period requirements have expired. To date, Exelon and PHI have filed applications seeking approval of the proposed merger with the FERC, the Virginia State Corporation Commission, the Delaware Public Service Commission, the Public Service Commission of the District of Columbia, and the New Jersey Board of Public Utilities. Exelon plans to make its filing under the HSR Act and the companies plan to file for merger approval with the MDPSC in August 2014. PHI has filed a preliminary proxy statement for a special meeting of shareholders to approve the proposed merger; a meeting date has not yet been set. Through June 30, 2014, Exelon has incurred approximately $25 million of expense associated with the transaction, primarily related to fees incurred as part of the acquisition. Exelon currently estimates the total costs directly related to the closing of the transaction to be $265 million. As part of the applications for approval of the merger, Exelon and PHI have proposed a package of benefits to PHI utilities' customers which results in a direct investment of more than $100 million. The Merger Agreement also provides for termination rights on behalf of both parties. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to pay Exelon a termination fee ranging from $259 million to $293 million plus certain expenses. If the Merger Agreement does not close due to a regulatory failure, Exelon may be required to pay PHI a termination fee equal to the amount of purchased nonvoting preferred securities (described above), by means of PHI redeeming the outstanding nonvoting preferred securities for no consideration other than the nominal par value of the stock. Exelon has listed various potential risks relating to the pending merger with PHI (see Item 1A. Risk Factors), including difficulties that may be encountered in satisfying the conditions to completion of the merger and the potential for developments that might have an adverse effect on Exelon and the ability to realize the expected benefits of the merger. Exelon is taking steps to manage these risks and expects that the merger can be completed on a basis favorable to the company's shareholders and customers. Accordingly, Exelon anticipates closing the transaction in the second or third quarter of 2015. Refer to Note 4-Mergers, Acquisitions, and Dispositions for additional information on the merger transaction.



Power Markets

Price of Fuels. The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon's revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development). Subsidized Generation. The rate of expansion of subsidized generation, including low-carbon generation such as wind and solar energy, in the markets in which Generation's output is sold can negatively impact wholesale power prices, and in turn, Generation's results of operations. Various states have attempted to implement or propose legislation, regulations or other policies to subsidize new generation development which may result in artificially depressed wholesale energy and capacity prices. For example, the New Jersey legislature enacted in to law in January 2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between the price eligible generators receive in the capacity market and the price guaranteed under the 15-year contract. New Jersey ultimately selected three proposals to participate in LCAPP and build new generation in the state. In addition, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under 165



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which CPV will construct an approximately 700 MW combined cycle gas turbine in Waldorf, Maryland, that it projected will be in commercial operation by June 1, 2015. CPV has subsequently sought to extend that date. The CfD mandated that utilities (including BGE) pay (or receive) the difference between CPV's contract price and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity market. Exelon and others filed a complaint in federal district court challenging the constitutionality and other aspects of the New Jersey legislation. Similarly, Exelon and others also challenged the selection of the three generation developers. On October 25, 2013, the U.S. District Court in New Jersey issued a judgment order finding that the New Jersey legislation violates the Supremacy Clause of the United States Constitution and the New Jersey (SOCA) contract is unenforceable. The non-prevailing parties have sought appeals in federal appellate court in the New Jersey proceeding. On October 23, 2013, the New Jersey state court dismissed the New Jersey state proceeding without prejudice, subject to the final outcome of the New Jersey federal litigation. Similarly, on October 24, 2013, the U.S. District Court in Maryland issued a judgment order finding that the MDPSC's Order directing BGE and two other Maryland electric distribution companies to enter into a CfD violates the Supremacy Clause of the United States Constitution, as described in Note 5 - Regulatory Matters of the combined Notes to Consolidated Financial Statements. However, on October 1, 2013, a Maryland State Circuit Court upheld the MDPSC Orders as being within the MDPSC's statutory authority under Maryland state law. This decision is separate from the judgment in the federal litigation that the MDPSC Order is unconstitutional and the CfD unenforceable under federal law. The federal judgment was affirmed on June 2, 2014, by the U.S Court of Appeals for the Fourth Circuit, and Exelon believes this judgment would prevent enforcement of the CfD even if the Maryland State Circuit Court decision stands. CPV filed for en banc review of the Fourth Circuit decision but its request was denied. CPV, one of the sellers under both a New Jersey and a Maryland contract, filed its two contracts at the FERC. Exelon believes such contracts to be void and is seeking to ensure that such contracts are not accepted by the FERC. As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offered and cleared in PJM's capacity market auctions held in May 2012, 2013 and 2014. In addition, CPV has announced its intention to move forward with construction of its New Jersey plant, with or without the challenged state subsidy. Nonetheless to the extent that the state-required customer subsidies are included under their respective contracts, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in these auctions and may continue to do so in future auctions to the detriment of Exelon's market driven position. While the U.S. District Court decisions in New Jersey and Maryland are positive developments, continuation of these state efforts, if successful and unabated by an effective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish programs, which could substantially impact Exelon's market driven position and could have a significant effect on Exelon's financial results of operations, financial position and cash flows. PJM's capacity market rules include a MOPR, which is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. However, as described above, Exelon does not believe that the existing MOPR will work effectively with respect to generator developers who have a state-sponsored subsidy and has concerns with certain other aspects of PJM's rules related to the capacity auction. Accordingly, Exelon continues to work with other market stakeholders and through the FERC process to implement several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sponsored subsidy contracts and capacity market speculators) cannot inappropriately affect capacity auction prices in PJM.



See Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Maryland Order.

Exelon remains active in advocating for competitive markets, while opposing policies that require taxpayers and/or consumers to subsidize or give preferential treatment to specific generation providers or technologies, or that would threaten the reliability and value of the integrated electricity grid.

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Energy Demand. Modest economic growth partially offset by energy efficiency initiatives is resulting in positive growth for electricity for ComEd and PECO, and no projected growth for electricity for BGE. ComEd, PECO and BGE are projecting load volumes to increase by 0.8%, 0.7% and 0.0%, respectively, in 2014 compared to 2013. Retail Competition. Generation's retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. Recently, sustained low forward natural gas and power prices and low market volatility have caused retail competitors to aggressively pursue market share, and wholesale generators (including Generation) to use their retail operations to hedge generation output. These factors have adversely affected overall gross margins and profitability in Generation's retail operations.



Strategic Policy Alignment

Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades. Exelon's board of directors declared the second quarter 2014 dividend of $0.31 per share on Exelon's common stock. The second quarter dividend was paid on June 10, 2014 to shareholders of record on May 16, 2014. All future quarterly dividends require approval by Exelon's board of directors. Exelon's board of directors declared the third quarter 2014 dividend of $0.31 per share on Exelon's common stock. The third quarter dividend is payable on September 10, 2014 to shareholders of record on August 15, 2014. Exelon and Generation evaluate the economic viability of each of their generating units on an ongoing basis. Decisions regarding the future of economically challenged generating assets will be based primarily on the economics of continued operation of the individual plants. If Exelon and Generation do not see a path to sustainable profitability in any of their plants, Exelon and Generation will take steps to retire those plants to avoid sustained losses. Retirement of plants could materially affect Exelon's and Generation's results of operations, financial position, and cash flows through, among other things, potential impairment charges, accelerated depreciation and decommissioning expenses over the plants remaining useful lives, and ongoing reductions to operating revenues, operating and maintenance expenses, and capital expenditures.



Hedging Strategy

Exelon's policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2014 and 2015. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of June 30, 2014, the percentage of expected generation hedged for the major reportable segments was 92%-95%, 75%-78% and 46%-49% for 2014, 2015, and 2016, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation's sales of energy to ComEd, PECO and BGE relating to their respective retail load obligations. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well. 167



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Generation procures coal, oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation's procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 60% of Generation's uranium concentrate requirements from 2014 through 2018 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon's and Generation's results of operations, cash flows and financial position.



ComEd, PECO and BGE mitigate such exposure through regulatory mechanisms that allow them to recover procurement costs from retail customers.

Growth Opportunities

Exelon is currently pursuing growth in both the utility and generation businesses focused primarily on smart meter and smart grid initiatives at the utilities and on renewables development and the nuclear uprate program at Generation. The utilities also anticipate making significant future investments in infrastructure modernization and improvement initiatives. Management continually evaluates growth opportunities aligned with Exelon's existing businesses in electric and gas distribution, electric transmission, generation, customer supply of electric and natural gas products and services, and natural gas exploration and production activities, leveraging Exelon's expertise in those areas.



Smart Meter and Smart Grid Initiatives.

ComEd's Smart Meter and Smart Grid Investments. ComEd plans to invest approximately $1.3 billion on smart meters and smart grid under EIMA, including $1.0 billion through the AMI Deployment Plan. On June 11, 2014, the ICC approved ComEd's request to accelerate the deployment, which allows for the installation of more than four million smart meters throughout ComEd's service territory by 2018, three years in advance of the originally scheduled 2021 completion date. To date, nearly 350,000 smart meters have been installed in the Chicago area by ComEd. PECO's Smart Meter and Smart Grid Investments. In 2010, the PAPUC approved PECO's Smart Meter Procurement and Installation Plan, under which PECO will install more than 1.6 million smart meters. PECO plans to spend up to a total of $595 million and $120 million on its smart meter infrastructure and smart grid investments, respectively, of which $200 million will be funded by SGIG. BGE Smart Grid Initiative. In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million electric and gas smart meters at an expected total cost of approximately $480 million, before considering the $200 million SGIG for smart grid and other related initiatives.



See Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Initiatives.

Generation Renewable Development. On September 30, 2011, Exelon announced the completion of its acquisition of all of the interests in Antelope Valley, a 230-MW solar PV project under development in northern Los Angeles County, California, from First Solar, Inc., which is developing, building, operating, and maintaining 168



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the project. The first portion of the project began operations in December 2012, with six additional blocks coming online in 2013 and the final two blocks coming online in 2014 making the facility fully operational. The acquisition supports the Exelon commitment to renewable energy as part of Exelon 2020. The project has a 25-year PPA with Pacific Gas & Electric Company for the full output of the plant, which has been approved by the CPUC. Total capitalized costs for the facility are expected to be approximately $1.1 billion. Total capitalized costs incurred through June 30, 2014 were approximately $1.0 billion. In addition, Generation constructed and placed into service 400 MWs of additional wind generation in 2012 at a cost of $710 million and another 90 MW will be added to Generation's wind portfolio in 2014 with the 50 MW expansion of the Beebe project in Michigan, the output of which is fully contracted under a 20-year PPA, and the construction of the 40 MW Fourmile Wind project in Maryland to partially satisfy the Exelon-Constellation merger commitments to the State of Maryland. Nuclear Uprate Program. Generation is engaged in individual projects as part of a planned power uprate program across its nuclear fleet. When economically viable, the projects take advantage of new production and measurement technologies, new materials and application of expertise gained from a half-century of nuclear power operations. Under the nuclear uprate program, Generation has placed into service projects representing 393 MWs of new nuclear generation at a cost of $1,021 million, which has been capitalized to property, plant and equipment on Exelon's and Generation's consolidated balance sheets. At June 30, 2014, Generation has capitalized $184 million to construction work in progress within property, plant and equipment for nuclear uprate projects expected to be placed in service by the end of 2016, consisting of 139 MWs of new nuclear generation, that are in the installation phase at two nuclear stations; Peach Bottom in Pennsylvania and Dresden in Illinois. The remaining spend associated with these projects is expected to be approximately $225 million through the end of 2016. Generation believes that it is probable that these projects will be completed. If a project is expected not to be completed as planned, previously capitalized costs will be reversed through earnings as a charge to operating and maintenance expense and interest. See Note 7 - Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for further information.



Liquidity

Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements. Exelon, Generation, ComEd, PECO and BGE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.5 billion, $5.3 billion, $1.0 billion, $0.6 billion and $0.6 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources - Credit Matters - Exelon Credit Facilities below. Exposure to Worldwide Financial Markets. Exelon has exposure to worldwide financial markets including European banks. Disruptions in the European markets could reduce or restrict the Registrants' ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of June 30, 2014, approximately 29%, or $2.5 billion, of the Registrants' aggregate total commitments were with European banks. The credit facilities include $8.4 billion in aggregate total commitments of which $6.3 billion was available as of June 30, 2014, due to outstanding letters of credit and commercial paper. There were no borrowings under the Registrants' credit facilities as of June 30, 2014, with the exception of CENG. See Note 10 - Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for additional information on the credit facilities.



Tax Matters

See Note 11 of the Combined Notes to Consolidated Financial Statements for additional information.

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Environmental Legislative and Regulatory Developments.

Exelon supports the promulgation of certain environmental regulations by the U.S. EPA, including air, water and waste controls for electric generating units. See discussion below for further details. The air and waste regulations will have a disproportionate adverse impact on fossil-fuel power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and will likely result in the retirement of older, marginal facilities. Due to their low emission generation portfolios, Generation and CENG will not be significantly directly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants. Various bills have been introduced in the U.S. Congress that would prohibit or impede the U.S. EPA's rulemaking efforts. The timing of the consideration of such legislation is unknown. Air Quality. In recent years, the U.S. EPA has been implementing a series of increasingly stringent regulations under the Clean Air Act relating to NAAQS for conventional air pollutants (e.g., NOx, SO2 and particulate matter) as well as stricter technology requirements to control HAPs (e.g., acid gases, mercury and other heavy metals) from electric generation units. The U.S. EPA continues to review and update its NAAQS with a tightened particulate matter NAAQS issued in December 2012 and a review of the current 2008 ozone NAAQS that is expected to result in a proposed revision of the ozone NAAQS sometime in fall 2014. These updates will potentially result in more stringent emissions limits on fossil-fuel electric generating stations. There continues to be opposition among fossil-fuel generation owners to the potential stringency and timing of these air regulations. In July 2011, the U.S. EPA published CSAPR and in June 2012, it issued final technical corrections. CSAPR requires 28 upwind states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in downwind states. On August 21, 2012, a three-judge panel of the D.C. Circuit Court held that the U.S. EPA had exceeded its authority in certain material aspects with respect to CSAPR and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. Until the U.S. EPA re-issues CSAPR, Exelon cannot determine the impacts of the rule, including any that would impact power prices. In June 2013, the U.S. Supreme Court granted the U.S. EPA's petition to review the D.C. Circuit Court's CSAPR decision, and on April 29, 2014, the U.S. Supreme reversed the D.C. Circuit Court decision and upheld CSAPR, and remanded the case to the D.C. Circuit Court to resolve the remaining implementation issues. On June 26, 2014, the U.S. EPA filed a motion with the D.C. Circuit Court seeking to have the stay of the CSAPR lifted, and proposed a three-year tolling of the effective dates under the rule so that the first phase of emission budgets would be implemented on January 1, 2015. The U.S. EPA believes that this would allow sufficient time to complete the remaining aspects of the rulemaking before the implementation of the more stringent second phase of emission budgets that, under the tolling proposal, would begin on January 1, 2017. On December 16, 2011, the U.S. EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that owners of smaller, older, uncontrolled coal units will retire the units rather than make these investments. Coal units with existing controls that do not meet the MATS rule may need to upgrade existing controls or add new controls to comply. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies, or retire the units. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. On April 15, 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On July 14, 2014, three petitions for certiorari were filed with the U.S. Supreme Court seeking review of the D.C. Circuit Court decision upholding MATS. 170



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The cumulative impact of these air regulations could be to require power plant operators to expend significant capital to install pollution control technologies, including wet flue gas desulfurization technology for SO2 and acid gases, and selective catalytic reduction technology for NOx. Generation, along with the other co-owners of Conemaugh Generating Station have improved the existing scrubbers and installed Selective Catalytic Reduction (SCR) controls to meet the requirements of MATS. In addition, Keystone already has SCR and Flue-gas desulfurization (FGD) controls in place. On January 15, 2013, EPA issued a final rule for NSPS and National Emissions Standards for Hazardous Air Pollutants (NESHAP) for reciprocating internal combustion engines (RICE NESHAP/NSPS). The final rule allows diesel backup generators to operate for up to 100 hours annually under certain emergency circumstances without meeting emissions limitations, but requires units that operate over 15 hours to burn low sulfur fuel and report key engine information. The final rule eliminates after May 2014 the 50 hour exemption for peak shaving and other non-emergency demand response that was included in the proposed rule and, therefore, is not expected to result in additional megawatts of demand response to be bid into the PJM capacity auction. In the absence of Federal legislation, the U.S. EPA is also moving forward with the regulation of GHG emissions under the Clean Air Act. The U.S. EPA is addressing the issue of carbon dioxide (CO2) emissions regulation for new and existing electric generating units through the New Source Performance Standards (NSPS) under Section 111 of the Clean Air Act. Pursuant to President Obama's June 25, 2013 memorandum to U.S. EPA, the Agency re-proposed a Section 111(b) regulation for new units in September 2013 that may result in material costs of compliance for CO2 emissions for new fossil-fuel electric generating units, particularly coal-fired units. The Climate Action Plan also required the U.S. EPA to propose by June 2014 GHG emission regulations for existing stationary sources under Section 111(d) of the Clean Air Act, and to issue final regulations by June 2015. That proposed rule was published in the Federal Register on June 16, 2014 and is open for public comment until October 16, 2014. The proposed rule establishes emission reduction targets for each state and provides flexibility for each state to determine how to achieve its required reductions, including heat rate improvements at coal-fired power plants, fuel switching from coal to gas, renewable generation and new nuclear facilities, demand side energy efficiency, and the use of market-based instruments. While the nature and impact of the final regulations is not yet known, to the extent that the rule results in emission reductions from fossil fuel fired plants, imposing some form of direct or indirect price of carbon in competitive electricity markets, Exelon's overall low-carbon generation portfolio results would benefit.



Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions.

Water Quality. Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. On May, 19 2014, the U.S. EPA released the final Section 316(b) rule. The rule has not been published in the Federal Register, and will become effective 60 days after publication. The rule requires that a series of studies and analyses be performed at each facility to determine the best technology available, followed by an implementation period. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director. Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, the impact of compliance with the final rule is unknown. Should a state permitting director determine that a facility is required to install cooling towers to comply with the rule, that facility's economic viability would be called into question. However, the likely impact of the rule has been significantly decreased since the final rule does not mandate cooling towers as a national standard, and the state permitting director is required to apply a cost-benefit test and take into consideration site-specific factors. 171



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Hazardous and Solid Waste. Under proposed U.S. EPA rules issued on June 21, 2010, coal combustion residuals (CCR) would be regulated for the first time under the RCRA. The U.S. EPA is considering several options, including classification of CCR either as a hazardous or non-hazardous waste, under RCRA. Under either option, the U.S. EPA's intention is the ultimate elimination of surface impoundments as a waste treatment process. For plants affected by the proposed rules, this would result in significant capital expenditures and variable operating and maintenance expenditures to convert to dry handling and disposal systems and installation of new waste water treatment facilities. Generation's plants that would be affected by the proposed rules are the Keystone and Conemaugh generating stations in Pennsylvania, which have on-site landfills that meet the requirements of Pennsylvania solid waste regulations for non-hazardous waste disposal. However, until the final rule is adopted, the impact on these facilities is unknown. The U.S. EPA has entered into a Consent Decree which requires that a final rule be issued by December 19, 2014.



See Note 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.

Other Regulatory and Legislative Actions

Japan Earthquake and Tsunami and the Industry's Response. On March 11, 2011, Japan experienced a 9.0 magnitude earthquake and ensuing tsunami that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co. In July 2011, an NRC Task Force formed in the aftermath of the Fukushima Daiichi events issued a report of its review of the accident, including tiered recommendations for future regulatory action by the NRC to be taken in the near and longer term. The Task Force's report concluded that nuclear reactors in the United States are operating safely and do not present an imminent risk to public health and safety. The NRC and its staff have issued orders and implementation guidance for commercial reactor licensees operating in the United States. The NRC and its staff are continuing to evaluate additional requirements. Generation has assessed the impacts of the Tier 1 orders and information requests and will continue monitoring the additional recommendations under review by the NRC staff, both from an operational and a financial impact standpoint. A comprehensive review of the NRC Tier 1 orders and information requests, as well as preliminary engineering assumptions and analysis, indicate that the financial impact of compliance for the period from 2014 through 2018 is expected to be between approximately $500 million and $525 million of capital (including approximately $150 million for the CENG plants) and $75 million of operating expense (including approximately $25 million for the CENG plants). As Generation completes the design and installation planning for its actions, Generation will update these estimates. Further, Generation estimates incremental costs of $15 to $20 million per unit at thirteen Mark 1 and II units (including two CENG units) for the installation of filtered vents, if ultimately required by the NRC. Generation's current assessments are specific to the Tier 1 recommendations as the NRC has not taken specific action with respect to the Tier 2 and Tier 3 recommendations. Exelon and Generation are unable to conclude at this time to what extent any actions to comply with the requirements of Tier 2 and Tier 3 will impact their future financial position, results of operations, and cash flows. Generation will continue to engage in nuclear industry assessments and actions and stakeholder input. See Item 1A. Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview of the Exelon 2013 Form 10-K, for additional information. Financial Reform Legislation. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted in July 2010. Although the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for a new regulatory regime for over-the-counter swaps (Swaps), including mandatory clearing for certain categories of Swaps, incentives to shift swap activity to exchange trading, margin and capital requirements, and other obligations designed to promote transparency. The Dodd-Frank Act, however, also preserves the ability of end users in the energy industry to hedge their risks without being subject to mandatory clearing. Exelon is conducting its commercial business in a manner that does not require registration as a swap dealer or major swap participant. There are additional rulemakings that have 172



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not yet been issued, however, including the capital and margin rules, which will potentially have an impact on the Registrants' business. Depending on the substance of these final rules, the Registrants could be subject to additional new obligations.



In particular, the proposed regulations addressing collateral and capital requirements and exchange margin cash postings, when final, could require Generation to have increased collateral requirements or cash postings. Exelon had previously estimated that it could be required to make up to $1 billion of additional collateral postings under its bilateral credit lines.

Nonetheless, given that Generation is not a swap dealer or major swap participant and the majority of its wholesale portfolio is not comprised of Swaps, the actual amount of additional collateral postings that might be required as a direct result of Dodd-Frank could be lower than Exelon's previous expectations. The actual level of collateral required at any time will depend also on many other factors, including but not limited to market conditions, the extent of its trading activity in Swaps, and Generation's credit ratings. In addition, there will be minimal incremental costs associated with Generation's positions that are currently cleared and subject to exchange margin. Finally, as an end-user, Generation will not be subject to any of the proposed capital requirements that will apply to swap dealers and major swap participants.



Nonetheless, to the extent collateral costs increase as a result of the Dodd-Frank Act, Generation has adequate credit facilities and flexibility in its hedging program to meet any increase, including an increase of $1 billion.

Exelon and Generation continue to monitor the rulemaking procedures and cannot predict the ultimate outcome that the financial reform legislation will have on their results of operations, cash flows or financial position. ComEd, PECO and BGE could also be subject to some additional Dodd-Frank Act requirements to the extent they were to enter into Swap transactions. However, at this time, management of ComEd, PECO and BGE continue to expect that their companies will not be materially affected by this legislation. Energy Infrastructure Modernization Act. Since 2011, ComEd's distribution rates are established through a performance-based rate formula, pursuant to EIMA. Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in January of the following year. This annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior year and actual costs incurred for that year. In addition, ComEd's earned rate of return on common equity is required to be within plus or minus 50 basis points ("the collar") of the target rate of return determined as the annual average rate on 30-year treasury notes plus 580 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on distribution revenue. Throughout each year, ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement(s) in effect and ComEd's best estimate of the revenue requirement expected to be approved by the ICC for that year's reconciliation. Formula Rate Tariff and Annual Reconciliation. On April 16, 2014, ComEd filed its annual distribution formula rate update with the ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 2015 after the ICC's review and approval, which is due by December 2014. The revenue requirement requested is based on 2013 actual costs plus projected 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2013 to the actual costs incurred that year. ComEd's 2014 filing request includes a total increase to the net revenue requirement of $269 million, reflecting an increase of $174 million for the initial revenue requirement for 2014 and an increase of $95 million related to the annual reconciliation for 2013. The revenue requirement for 2014 provides for a weighted average debt and equity return on distribution rate base of 7.06% inclusive of an allowed return on common equity of 9.25%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2013 provided for a 173



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weighted average debt and equity return on distribution rate base of 7.04% inclusive of an allowed return on common equity of 9.20%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points. FERC Ameren Order. In July 2012, FERC issued an order to Ameren Corporation (Ameren) finding that Ameren had improperly included acquisition premiums/ goodwill in its transmission formula rate, particularly in its capital structure and in the application of AFUDC. FERC also directed Ameren to make refunds for the implied increase in rates in prior years. Ameren filed for rehearing of the July 2012 order, which was denied in June 2014. FERC and Ameren are in the process of determining the amount of any potential refund. ComEd believes that the FERC order authorizing its transmission formula rate is distinguishable from the circumstances that led to the July 2012 FERC order in the Ameren case. However, if ComEd were required to exclude acquisition premiums/ goodwill from its transmission formula rate, the impact could be material to ComEd's results of operations and cash flows. FERC Order No. 1000 Compliance (ComEd, PECO and BGE). In FERC Order No. 1000, the FERC required public utility transmission providers to enhance their transmission planning procedures and their cost allocation methods applicable to certain new regional and interregional transmission projects. As part of the changes to the transmission planning procedures, the FERC required removal from all FERC-approved tariffs and agreements of a right of first refusal to build certain new transmission facilities. In compliance with the regional transmission planning requirements of Order No. 1000, PJM as the transmission provider submitted a compliance filing to FERC on October 25, 2012. On the same day, certain of the PJM transmission owners, including ComEd, PECO and BGE (collectively, the PJM Transmission Owners), submitted a filing asserting that their contractual rights embodied in the PJM governing documents continue to justify their right of first refusal to construct new reliability (and related) transmission projects and that the FERC should not be allowed to override such rights absent a showing that it is in the public interest to do so under the FERC's "Mobile-Sierra" standard of review. This is a heightened standard of review which the PJM Transmission Owners argued could not be satisfied based on the facts applicable to them. On March 22, 2013, FERC issued an order on the PJM Compliance Filing and the filing of these PJM Transmission Owners (1) rejecting the arguments of those PJM Transmission Owners that changes to the PJM governing documents were entitled to review under the Mobile-Sierra standard, (2) accepting most of the PJM filing, removing the right-of-first refusal from the PJM tariffs, and (3) directing PJM to remove certain exceptions that it included in its compliance filing that FERC found did not comply with Order No. 1000. FERC's order could enable third parties to seek to build certain regional transmission projects that had previously been reserved for the PJM Transmission Owners, potentially reducing ComEd's, PECO's and BGE's financial return on new investments in energy transmission facilities. Numerous parties sought rehearing of the FERC's March 22, 2013 order, including the PJM Transmission Owners who sought rehearing of the FERC's rejection of their Mobile-Sierra and related arguments. PJM's compliance filing was made on July 22, 2013. On May 15, 2014, FERC denied the rehearing requests except with respect to one issue on when PJM could consider state and local laws in evaluating projects. FERC generally accepted the July 22, 2013, Compliance Filing but required several minor additional changes. FirstEnergy and at least one other party filed an appeal of the May 15, 2014, Order upholding PJM's right of first refusal language in the DC Circuit. Exelon has intervened in the FirstEnergy appeal. Several parties have filed requests for rehearing or clarification concerning the changes set forth in the May 15, 2014, Order. FERC Transmission Complaint. On February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE and the PHI companies relating to their respective transmission formula rates. BGE's formula rate includes a 10.8% base rate of return on common equity (ROE) for most investments included in its rate base and 11.3% for the remaining transmission investment (the latter of which is conditioned upon crediting the first 50 basis points of any incentive ROE adders). The parties seek a reduction in the base return on equity to 8.7% and changes to the formula rate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, the revenues subject to refund are limited to a fifteen month period, and the earliest date from which the base return on equity 174



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could be adjusted and refunds required is the date of the complaint. On March 19, 2013, BGE filed a motion to dismiss or sever the complaint. On June 19, 2014, FERC issued an order in another case involving New England Transmission Owners (NETOs), changing its methodology to determine ROE rates for public utilities. The result was a reduction in the ROE from 11.14% to 10.57% for the NETOs, with a possible further adjustment in either direction based on additional paper hearing submissions. On July 21, 2014, the NETOs filed a Request for Rehearing and Clarification with FERC of the June 19, 2014 order. Among other things, the NETOs request on rehearing that the 11.14% is reasonable based on the new methodology. As of June 30, 2014, BGE believes it is probable that BGE's base ROE rate will be subject to the revised methodology and may result in a potential refund to customers of transmission revenue for a maximum fifteen month period. In evaluating FERC's revised methodology, management believes it is reasonably possible no refunds will be required for BGE, and as such, no refund liability has been recorded as of June 30, 2014. If FERC were to order a reduction of BGE's base return on equity to 8.7% (while retaining the 50 basis points of any incentives that were credited to the base return on equity for certain new transmission investment), the result would be a refund to customers of approximately $13 million, as well as estimated ongoing annual reduction in revenues of approximately $10 million. See Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. The Maryland Strategic Infrastructure Development and Enhancement Program. In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. Under the new law, following a proceeding before the MDPSC and with the MDPSC's approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On March 26, 2014, the MDPSC approved as filed BGE's proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge becoming effective April 1, 2014. In February 2014, the residential consumer advocate in Maryland filed an appeal with the Baltimore City Circuit Court to the decision issued by the MDPSC on BGE's infrastructure replacement plan. The residential consumer advocate filed its related legal memorandum on July 7, 2014, claiming that the MDPSC did not apply the appropriate consideration in approving BGE's infrastructure replacement plan and associated surcharge. BGE has until August 7, 2014 to submit a response, and a hearing has been scheduled for September 5, 2014. BGE cannot predict the outcome of this appeal. See Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Employees IBEW Local 15's collective bargaining agreements (CBAs) were set to expire in 2013 but were extended by agreement to February 28, 2014. A tentative agreement was reached prior to the expiration and on March 31, 2014, two CBA's with IBEW Local 15 (which represents approximately 5,250 of Exelon's employees) were ratified. The CBA's, one with ComEd and BSC and the other with Generation, extend through September 30, 2019 and April 30, 2019, respectively.



Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates" in the Exelon's, Generation's, ComEd's, PECO's and BGE's combined 2013 Form 10-K for a discussion of the estimates and judgments necessary in the Registrants' accounting for AROs, purchase accounting, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies and revenue recognition. At June 30, 2014, the Registrants' critical accounting policies and estimates had not changed significantly from December 31, 2013. 175



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Results of Operations

Net Income Attributable to Common Shareholders by Registrant

Three Months Ended Favorable Six Months Ended Favorable June 30, (Unfavorable) June 30, (Unfavorable) 2014 2013 Variance 2014 2013 Variance Exelon $ 522$ 490 $ 32 $ 612$ 486 $ 126 Generation 340 330 10 155 311 (156 ) ComEd 111 96 15 209 14 195 PECO 84 72 12 173 193 (20 ) BGE 16 22 (6 ) 100 100 -



Results of Operations - Generation

Three Months Ended Favorable Six Months Ended Favorable June 30, (Unfavorable) June 30, (Unfavorable) 2014(a) 2013 Variance 2014(a) 2013 Variance Operating revenues $ 3,789$ 4,070



$ (281 ) $ 8,179$ 7,603 $ 576 Purchased power and fuel expense

1,835 1,946 111 5,191 4,114



(1,077 )

Revenue net of purchased power and fuel(b) 1,954 2,124 (170 ) 2,988 3,489 (501 ) Other operating expenses Operating and maintenance 1,413 1,189 (224 ) 2,499 2,302 (197 ) Depreciation and amortization 254 210 (44 ) 466 424 (42 ) Taxes other than income 118 101 (17 ) 223 194 (29 ) Total other operating expenses 1,785 1,500 (285 ) 3,188 2,920 (268 ) Equity in losses of unconsolidated affiliates (1 ) (21 ) 20 (20 ) (30 ) 10 Gain on consolidation of CENG 261 - 261 261 - 261 Operating income 429 603 (174 ) 41 539 (498 ) Other income and (deductions) Interest expense (86 ) (93 ) 7 (172 ) (176 ) 4 Other, net 228 (33 ) 261 318 95 223 Total other income and (deductions) 142 (126 ) 268 146 (81 ) 227 Income before income taxes 571 477 94 187 458 (271 ) Income taxes (benefit) 199 149 (50 ) (1 ) 148 149 Net income 372 328 44 188 310 (122 ) Net income (loss) attributable to noncontrolling interests 32 (2 ) (34 ) 33 (1 ) (34 ) Net income attributable to membership interest $ 340 $ 330 $ 10 $ 155 $ 311 $ (156 )



(a) Includes the operations of CENG from April 1, 2014, through June 30, 2014.

(b) Generation evaluates its operating performance using the measure of revenue

net of purchased power and fuel expense. Generation believes that revenue net

of purchased power and fuel expense is a useful measurement because it

provides information that can be used to evaluate its operational

performance. Revenue net of purchased power and fuel expense is not a

presentation defined under GAAP and may not be comparable to other companies'

presentations or deemed more useful than the GAAP information provided elsewhere in this report. 176



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Net Income Attributable to Membership Interest

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. Generation's net income attributable to membership interest for the three months ended June 30, 2014 increased compared to the same period in 2013 primarily due to the gain recognized as a result of the consolidation of CENG, and the increase in other income; partially offset by decreased revenue net of purchased power and fuel, increased operating and maintenance expense and increased depreciation and amortization expense. The decrease in revenue net of purchased power and fuel primarily relates to mark-to-market losses from economic hedging activities, lower realized energy prices, and, excluding CENG, generation volumes were lower, partially offset by the consolidation of CENG, higher capacity revenues, and a decrease in amortization expense for the acquired energy contracts recorded at fair value at the merger date with Constellation and consolidation of CENG. The increase in operating and maintenance expense is primarily related to the inclusion of CENG's results for a full quarter in 2014, and an increase in planned nuclear refueling outage days in 2014. The increase in other, net is primarily due to an increase in realized NDT fund gains. Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. Generation's net income attributable to membership interest for the six months ended June 30, 2014 decreased compared to the same period in 2013 primarily due to decreased revenue net of purchased power and fuel expense, and increased operating and maintenance expense; partially offset by the gain recognized as a result of the consolidation of CENG and an increase in other operating income. The decrease in revenue net of purchased power and fuel primarily relates to mark-to-market losses from economic hedging activities, lower realized energy prices, higher procurement costs for replacement power, increased fossil fuel expense due to extreme cold weather during the first quarter of 2014 and, excluding CENG, generation volumes were lower, partially offset by the consolidation of CENG, higher capacity revenues, and a decrease in amortization expense for the acquired energy contracts recorded at fair value at the merger date with Constellation and consolidation of CENG. The increase in operating and maintenance expense is primarily related to the inclusion of CENG's results for a full quarter in 2014, and an increase in planned nuclear refueling outage days in 2014. The increase in other, net income is primarily due to an increase in realized NDT fund gains.



Revenue Net of Purchased Power and Fuel Expense

The foundation of Generation's six reportable segments is based on the geographic location of its assets, and are largely representative of the footprints of an ISO / RTO and/or NERC region. Descriptions of each of Generation's six reportable segments are as follows:

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. Midwest represents operations in the western half of PJM, which includes



portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee, and

the United States footprint of MISO excluding MISO's Southern Region,

which covers all or most of North Dakota, South Dakota, Nebraska,

Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana,

Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and

Kentucky. New England represents the operations within ISO-NE covering the states of

Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.



New York represents operations within New York ISO, which covers the state

of New York in its entirety. ERCOT represents operations within Electric Reliability Council of Texas,

covering most of the state of Texas. Other Regions not considered individually significant: 177



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South represents operations in the FRCC, MISO's Southern Region, and

the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas.



Generation's South

region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.



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

and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota. Canada represents operations across the entire country of Canada and includes the AESO, OIESO and the Canadian portion of MISO. The following business activities are not allocated to a region, and are reported under Other: retail and wholesale gas, investments in natural gas exploration and production activities, proprietary trading, energy efficiency and demand response, heating, cooling, and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems and investments in energy-related proprietary technology. Further, the following activities are not allocated to a region, and are reported in Other: unrealized mark-to-market impact of economic hedging activities; amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the merger with Constellation and the consolidation of CENG; and other miscellaneous revenues. Generation evaluates the operating performance of its power marketing activities using the measure of revenue net of purchased power and fuel expense which is a non-GAAP measurement. Generation's operating revenues include all sales to third parties and affiliated sales to ComEd, PECO and BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for internally generated energy and fuel costs associated with tolling agreements.



For the three and six months ended June 30, 2014 and 2013, Generation's revenue net of purchased power and fuel expense by region were as follows:

Three Months Ended June 30, 2014(a) 2013 Variance % Change Mid-Atlantic(b) $ 920 $ 768$ 152 19.8 % Midwest(c) 605 684 (79 ) (11.5 %) New England 64 50 14 28.0 % New York 148 14 134 n.m. ERCOT 59 112 (53 ) (47.3 %) Other Regions(d) 75 59 16 27.1 % Total electric revenue net of purchased power and fuel expense 1,871 1,687 184 10.9 % Proprietary Trading 7 3 4 n.m. Mark-to-market gains (losses) (14 ) 428 (442 ) (103.3 %) Other(e) 90 6 84 n.m. Total revenue net of purchased power and fuel expense $ 1,954$ 2,124$ (170 ) (8.0 %) 178



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Table of Contents Six Months Ended June 30, 2014(a) 2013 Variance % Change Mid-Atlantic(b) $ 1,615$ 1,612$ 3 0.2 % Midwest(c) 1,161 1,401 (240 ) (17.1 %) New England 200 80 120 n.m. New York 127 (8 ) 135 n.m. ERCOT 142 213 (71 ) (33.3 %) Other Regions(d) 180 105 75 71.4 % Total electric revenue net of purchased power and fuel expense 3,425 3,403 22 0.6 % Proprietary Trading 20 12 8 66.7 % Mark-to-market gains (losses) (744 ) 25 (769 ) n.m. Other(e) 287 49 238 n.m. Total revenue net of purchased power and fuel expense $ 2,988$ 3,489$ (501 ) (14.4 %)



(a) Includes the operations of CENG from April 1, 2014, through June 30, 2014

(b) Results of transactions with PECO and BGE are included in the Mid-Atlantic

region.

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

(d) Other Regions includes South, West and Canada, which are not considered

individually significant.

(e) Other represents activities not allocated to a region. See text above for a

description of included activities. Also includes amortization of intangible

assets related to commodity contracts recorded at fair value at the date of

the merger with Constellation and the consolidation of CENG in purchase

accounting of $50 million and $92 million pre-tax for the three and six

months ended June 30, 2014, and $167 million and $341 million pre-tax for the

three and six months ended June 30, 2013. 179



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Generation's supply sources by region are summarized below:

Three Months Ended June 30, Supply source (GWh) 2014 2013 Variance % Change Nuclear generation Mid-Atlantic(a) 14,912 11,794 3,118 26.4 % Midwest 22,719 22,807 (88 ) (0.4 %) New York(a) 3,766 - 3,766 n.m. Total nuclear generation 41,397 34,601 6,796



19.6 %

Fossil and renewables(a)

Mid-Atlantic 3,165 2,796 369 13.2 % Midwest 319 318 1 0.3 % New England 1,299 3,132 (1,833 ) (58.5 %) New York 1 - 1 n.m. ERCOT 1,553 1,617 (64 ) (4.0 %) Other Regions(c) 2,041 1,431 610 42.6 % Total fossil and renewables 8,378 9,294 (916 ) (9.9 %) Purchased power Mid-Atlantic(b) 810 2,616 (1,806 ) (69.0 %) Midwest 520 1,503 (983 ) (65.4 %) New England 2,290 1,365 925 67.8 % New York(b) - 3,073 (3,073 ) (100.0 %) ERCOT 2,518 4,269 (1,751 ) (41.0 %) Other Regions(c) 3,654 4,998 (1,344 ) (26.9 %) Total purchased power 9,792 17,824 (8,032 ) (45.1 %)



Total supply/sales by region(d)

Mid-Atlantic(e) 18,887 17,206 1,681 9.8 % Midwest(e) 23,558 24,628 (1,070 ) (4.3 %) New England 3,589 4,497 (908 ) (20.2 %) New York 3,767 3,073 694 22.6 % ERCOT 4,071 5,886 (1,815 ) (30.8 %) Other Regions(c) 5,695 6,429 (734 ) (11.4 %)



Total supply/sales by region 59,567 61,719 (2,152 ) (3.5 %)

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Table of Contents Six Months Ended June 30, Supply source (GWh) 2014 2013 Variance % Change Nuclear generation Mid-Atlantic(a) 27,048 24,556 2,492 10.1 % Midwest 45,844 46,076 (232 ) (0.5 %) New York(a) 3,766 - 3,766 n.m. Total nuclear generation 76,658 70,632 6,026 8.5 % Fossil and renewables(a) Mid-Atlantic 6,373 5,956 417 7.0 % Midwest 736 899 (163 ) (18.1 %) New England 3,033 5,524 (2,491 ) (45.1 %) New York 2 - 2 n.m. ERCOT 3,208 2,350 858 36.5 % Other Regions(c) 3,670 3,685 (15 ) (0.4 %) Total fossil and renewables 17,022 18,414 (1,392 ) (7.6 %) Purchased power Mid-Atlantic(b) 4,043 5,849 (1,806 ) (30.9 %) Midwest 1,231 3,203 (1,972 ) (61.6 %) New England 4,360 2,872 1,488 51.8 % New York(b) 2,857 6,584 (3,727 ) (56.6 %) ERCOT 5,958 8,468 (2,510 ) (29.6 %) Other Regions(c) 7,009 8,701 (1,692 ) (19.4 %) Total purchased power 25,458 35,677 (10,219 ) (28.6 %) Total supply/sales by region(d) Mid-Atlantic(e) 37,464 36,361 1,103 3.0 % Midwest(e) 47,811 50,178 (2,367 ) (4.7 %) New England 7,393 8,396 (1,003 ) (11.9 %) New York 6,625 6,584 41 0.6 % ERCOT 9,166 10,818 (1,652 ) (15.3 %) Other Regions(c) 10,679 12,386 (1,707 ) (13.8 %) Total supply/sales by region 119,138 124,723 (5,585 ) (4.5 %)



(a) Includes the proportionate share of output where Generation has an undivided

ownership interest in jointly-owned generating plants and includes the total

output of plants that are fully consolidated (e.g. CENG). Nuclear generation

for the three months and six months ended June 30, 2014 includes physical

volumes of 3,780 GWh in Mid-Atlantic and 3,766 GWh in New York for CENG.

(b) Purchased power for the three months and six months ended June 30, 2014

includes physical volumes of 0 GWh and 2,489 GWh in the Mid-Atlantic and 0

GWh and 2,857 GWh in New York as a result of the PPA with CENG. Purchased

power for the three months and six months ended June 30, 2013 includes

physical volumes of 3,114 GWh and 5,702 GWh in the Mid-Atlantic and 2,655 GWh

and 5,868 GWh in New York as a result of the PPA with CENG. As of the integration date of April 1, 2014, CENG volumes are included in nuclear generation.



(c) Other Regions includes South, West and Canada, which are not considered

individually significant.

(d) Excludes physical proprietary trading volumes of 2,629 GWh and 1,995 GWh for

the three months ended June 30, 2014 and 2013, respectively, and 5,123 GWh

and 3,567 GWh for the six months ended June 30, 2014 and 2013, respectively.

(e) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and

affiliate sales to ComEd in the Midwest region.

Mid-Atlantic

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. The $152 million increase in revenue net of purchased power and fuel expense in the Mid-Atlantic was primarily due to the consolidation of CENG, higher capacity revenues, and the cancellation of the DOE spent nuclear fuel disposal fee, partially offset by lower realized energy prices and lower generation volumes, excluding CENG.

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Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. The $3 million increase in revenue net of purchased power and fuel expense in the Mid-Atlantic was primarily due to the consolidation of CENG, higher capacity revenues, and the cancellation of the DOE spent nuclear fuel disposal fees, partially offset by lower realized energy prices, higher procurement costs for replacement power, an increase in generation fuel prices, and lower generation volumes, excluding CENG. Midwest



Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. The $79 million decrease in revenue net of purchased power and fuel expense in the Midwest was primarily due to lower realized energy prices, partially offset by increased capacity revenue and the cancellation of the DOE spent nuclear fuel disposal fee.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. The $240 million decrease in revenue net of purchased power and fuel expense in the Midwest was primarily due to lower realized energy prices, partially offset by increased capacity revenue and the cancellation of the DOE spent nuclear fuel disposal fee. New England Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. The $14 million increase in revenue net of purchased power and fuel expense in New England was primarily due to higher realized energy prices and favorable impacts from the restructuring of a fuel supply contract, partially offset by lower generation volume. Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. The $120 million increase in revenue net of purchased power and fuel expense in New England was driven by higher realized energy prices and favorable impacts from the restructuring of a fuel supply contract, partially offset by lower generation volume.



New York

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. The $134 million increase in revenue net of purchased power and fuel expense in New York was primarily due to the consolidation of CENG.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. The $135 million increase in revenue net of purchased power and fuel expense in New York was primarily due to the consolidation of CENG.



ERCOT

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. The $53 million decrease in revenue net of purchased power and fuel expense in ERCOT was primarily due to higher procurement costs for replacement power and the termination of an energy supply contract with a retail power supply company that was previously a consolidated variable interest entity. As a result of the termination, Generation no longer has a variable interest in the retail supply company and ceased consolidation of the entity during the third quarter of 2013. Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. The $71 million decrease in revenue net of purchased power and fuel expense in ERCOT was primarily due to increased generation fuel costs, higher procurement costs for replacement power in the second quarter of 2014, and the termination of an energy supply contract with a retail power supply company that was previously a consolidated variable interest 182



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entity. As a result of the termination, Generation no longer has a variable interest in the retail supply company and ceased consolidation of the entity during the third quarter of 2013. The decreases were partially offset by higher realized energy prices and higher generation volume in the first quarter of 2014.



Other Regions

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. The $16 million increase in revenue net of purchased power and fuel expense in Other Regions was primarily due to higher generation volumes and higher realized energy prices, partially offset by increased generation fuel costs.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. The $75 million increase in revenue net of purchased power and fuel expense in Other Regions was primarily due to higher realized energy prices, partially offset by increased generation fuel costs.



Mark-to-market

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations. Mark-to-market losses on economic hedging activities were $14 million for the three months ended June 30, 2014 compared to gains of $428 million for the three months ended June 30, 2013. See Notes 8 - Fair Value of Financial Assets and Liabilities and 9 - Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives. Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations. Mark-to-market losses on economic hedging activities were $744 million for the six months ended June 30, 2014 compared to gains of $25 million for the six months ended June 30, 2013. See Notes 8 - Fair Value of Financial Assets and Liabilities and 9 - Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.



Other

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. The $84 million increase in other revenue net of purchased power and fuel expense was driven by the reduction of amortization of the acquired energy contracts recorded at the date of merger with Constellation and the consolidation of CENG.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. The $238 million increase in other revenue net of purchased power and fuel was driven by the reduction of amortization of the acquired energy contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG.

Nuclear Fleet Capacity Factor and Production Costs

The following table presents nuclear fleet operating data for the three and six months ended June 30, 2014 as compared to the same periods in June 30, 2013, for the Generation-operated plants. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Nuclear fleet production cost is defined as the costs to produce one MWh of energy, including fuel, materials, labor, contracting and other miscellaneous costs, but excludes depreciation and certain other non-production related overhead costs. Generation considers capacity factor and production costs useful measures comparatively to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a 183



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complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies' presentations or be more useful than the GAAP information provided elsewhere in this report. Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 Nuclear fleet capacity factor(a) 91.8 % 92.8 % 92.9 % 94.6 % Nuclear fleet production cost per MWh(a) $ 20.31$ 18.86$ 20.50$ 19.27



(a) Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership

percentage of stations operated by Exelon. As of April 1, 2014, CENG is

included.

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. The nuclear fleet capacity factor decreased primarily due to the inclusion of the ownership share of CENG. In addition, there were more refueling and non-refueling outage days, excluding Salem outages, during the three months ended June 30, 2014 compared to the same period in 2013. For the three months ended June 30, 2014 and 2013, non-refueling outage days totaled 44 and 31, respectively. During the same periods, refueling outage days totaled 108 and 47, respectively. Inclusion of the ownership share of CENG resulted in higher production costs per MWh for the three months ended June 30, 2014 as compared to the same period in June 30, 2013. Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. The nuclear fleet capacity factor decreased primarily due to the inclusion of the ownership share of CENG. In addition, there were more refueling and non-refueling outage days, excluding Salem outages, during the six months ended June 30, 2014 compared to the same period in 2013. For the six months ended June 30, 2014 and 2013, non-refueling outage days totaled 64 and 37, respectively. During the same periods, refueling outage days totaled 160 and 96, respectively. Inclusion of the ownership share of CENG resulted in higher production costs per MWh for the six months ended June 30, 2014 as compared to the same period in June 30, 2013.



Operating and Maintenance Expense

The changes in operating and maintenance expense for the three and six months ended June 30, 2014 compared to the same period in 2013, consisted of the following: Three Months Ended Six Months Ended June 30, June 30, Increase Increase (Decrease)(a) (Decrease)(a) Labor, other benefits, contracting, materials $ 126 $ 121 Impairment of certain wind generating assets(b) 86 86 Nuclear refueling outage costs, including the co-owned Salem plants(c) 61 75 Accretion expense 25 28 Regulatory fees and assessment 20 17 Increase in asbestos reserve 16 16 Nuclear uprate project cancellation(d) (92 ) (113 ) Pension and non-pension postretirement benefits expense (31 ) (40 ) Merger and integration cots (5 ) (12 ) Other 18 19 Increase in operating and maintenance expense $ 224 $ 197



(a) Includes the operations of CENG, from April 1, 2014 through June 30, 2014.

(b) Reflects the impact of the charge to earnings related to the impairment of

certain wind generating assets.

(c) Reflects the impact of increased planned refueling outage days in 2014.

(d) Reflects the impact of the 2013 cancellation of previously capitalized

nuclear uprate projects. 184



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Depreciation and Amortization

The increase in depreciation and amortization expense for the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 was primarily due the inclusion of CENG's results for a full quarter in 2014 and an increase in ongoing capital expenditures.



Taxes Other Than Income

The increase in taxes other than income for the three and six months ended June 30, 2014 as compared to the three and six months ended June 30, 2013 was primarily due to an increase in payroll taxes and real estate taxes.

Equity in Losses of Unconsolidated Affiliates

The favorable increase in Equity in losses of unconsolidated affiliates for the three and six months ended June 30, 2014 as compared to the three and six months ended June 30, 2013 was due to the decrease in non-cash amortization as a result of the second quarter 2013 non-cash amortization of the fair value basis difference recorded at the Constellation merger date, offset by equity in losses in CENG in 2013 which is now consolidated in 2014.



Interest Expense

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013.

Interest expense for three months ended June 30, 2014 compared to same period in 2013 remained relatively level.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013.

The decrease in interest expense primarily reflects a benefit recorded in 2014 related to the favorable settlement of certain income tax positions on Constellation's 2009-2012 tax returns.

Other, Net

The increase in Other, net for the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 primarily reflects the change in the realized and unrealized gains and losses related to the NDT funds of its Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $46 million and $(13) million for the three months ended June 30, 2014 and 2013, respectively, and $66 million and $30 million for the six months ended June 30, 2014 and 2013, respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. Refer to Note 12 - for additional information regarding NDT funds. The following table provides unrealized and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for the three and six months ended June 30, 2014 and 2013: Three Months Ended Six Months Ended June 30, June 30, 2014(a) 2013 2014(a) 2013 Net unrealized gains (losses) on decommissioning trust funds $ 128$ (40 )$ 141$ 24 Net realized gains on sale of decommissioning trust funds $ 12 $ - $ 25$ 2



(a) Includes results of CENG from April 1, 2014 through June 30, 2014.

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Effective Income Tax Rate

The effective income tax rate was 34.9% and (0.5)% for the three and and six months ended June 30, 2014, respectively, compared to 31.2% and 32.3% for the same periods during 2013. See Note 11 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.



Results of Operations - ComEd

Three Months Ended Favorable Six Months Ended Favorable June 30, (Unfavorable) June 30, (Unfavorable) 2014 2013 Variance 2014 2013 Variance Operating revenues $ 1,128$ 1,080 $ 48 $ 2,262$ 2,239 $ 23 Purchased power expense 269 248 (21 ) 589 630 41 Revenue net of purchased power expense(a) 859 832 27 1,673 1,609 64 Other operating expenses Operating and maintenance 355 359 4 681 687 6 Depreciation and amortization 174 170 (4 ) 347 337 (10 ) Taxes other than income 72 71 (1 ) 149 145 (4 ) Total other operating expenses 601 600 (1 ) 1,177 1,169 (8 ) Operating income 258 232 26 496 440 56 Other income and (deductions) Interest expense, net (80 ) (76 ) (4 ) (160 ) (429 ) 269 Other, net 5 6 (1 ) 10 11 (1 ) Total other income and (deductions) (75 ) (70 ) (5 ) (150 ) (418 ) 268 Income before income taxes 183 162 21 346 22 324 Income taxes 72 66 (6 ) 137 8 (129 ) Net income $ 111$ 96 $ 15 $ 209$ 14 $ 195



(a) ComEd evaluates its operating performance using the measure of revenue net of

purchased power expense. ComEd believes that revenue net of purchased power

expense is a useful measurement because it provides information that can be

used to evaluate its operational performance. In general, ComEd only earns

margin based on the delivery and transmission of electricity. ComEd has

included its discussion of revenue net of purchased power expense below as a

complement to the financial information provided in accordance with GAAP.

However, revenue net of purchased power expense is not a presentation defined

under GAAP and may not be comparable to other companies' presentations or

deemed more useful than the GAAP information provided elsewhere in this

report. Net Income



Three Months Ended June 30, 2014, Compared to Three Months Ended June 30, 2013. ComEd's net income for the three months ended June 30, 2014, was higher than the same period in 2013, primarily due to higher electric distribution revenue resulting from increased capital investment.

Six Months Ended June 30, 2014, Compared to Six Months Ended June 30, 2013. ComEd's net income for the six months ended June 30, 2014, was higher than the same period in 2013, primarily due to the interest expense and related income tax effects of the remeasurement of Exelon's like-kind exchange tax position in the first quarter of 2013, as well as increased distribution revenue resulting from increased capital investment in 2014. See Note 11 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the like-kind exchange tax position. 186



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Operating Revenues Net of Purchased Power Expense

There are certain drivers of revenue that are fully offset by their impact on purchased power expense, such as commodity procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity procurement costs from retail customers without mark-up. Therefore, fluctuations in electricity procurement costs have no impact on revenue net of purchased power expense. See Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on ComEd's electricity procurement process. All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact ComEd's volume of deliveries, but do affect ComEd's operating revenue related to supplied energy, which is fully offset in purchased power expense. Therefore, customer choice programs have no impact on revenue net of purchased power expense. The number of retail customers participating in customer choice programs was 2,550,114 and 2,593,064 at June 30, 2014, and 2013, respectively, representing 66% and 68% of total retail customers, respectively. Retail energy purchased from competitive electric generation suppliers represented 81% and 80% of ComEd's retail kWh sales for the three months and six months ended June 30, 2014, respectively, as compared to 81% and 78% for the three and six months ended June 30, 2013, respectively. The changes in ComEd's revenue net of purchased power expense for the three months and six months ended June 30, 2014, compared to the same periods in 2013 consisted of the following: Three Months Ended Six Months Ended June 30, June 30, Increase Increase (Decrease) (Decrease) Weather $ 1 $ 16 Volume - 6 Electric distribution revenues (1 ) 39 Transmission revenues 3 2 Regulatory required programs 18 27 Uncollectible accounts recovery, net 7 (12 ) Pricing and customer mix 14 4 Revenue subject to refund (9 ) (9 ) Other (6 ) (9 ) Increase in revenue net of purchased power expense $ 27 $ 64 Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as "favorable weather conditions" because these weather conditions result in increased customer usage. Conversely, mild weather reduces demand. For the three months ended June 30, 2014, weather conditions were relatively consistent with the same period in 2013. During the six months ended June 30, 2014 compared to the same period in 2013, operating revenues net of purchased power expense were higher due to the impact of favorable 2014 winter weather conditions in ComEd's service territory. 187



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Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in ComEd's service territory with cooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd's service territory for the three and six months ended June 30, 2014, and 2013, consisted of the following: % Change Heating and Cooling Degree-Days 2014 2013 Normal From 2013 From Normal Three Months Ended June 30, Heating Degree-Days 695 778 765 (10.7 )% (9.2 )% Cooling Degree-Days 259 240 218 7.9 % 18.8 % Six Months Ended June 30, Heating Degree-Days 4,569 4,037 3,929 13.2 % 16.3 % Cooling Degree-Days 259 240 218 7.9 % 18.8 % Volume. Revenue net of purchased power expense increased as a result of higher delivery volume, exclusive of the effects of weather, reflecting increased average usage per residential customer as compared to the same six month period in 2013. Electric Distribution Revenue. EIMA provides for a performance-based rate formula, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Distribution revenue varies from year to year based on fluctuations in the underlying costs, investments being recovered and other billing determinants. In addition, ComEd's earned rate of return on common equity is required to be within plus or minus 50 basis points ("the collar") of the target rate of return determined as the annual average rate on 30-year treasury notes plus 580 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on distribution revenue. During the three months ended June 30, 2014, ComEd recorded decreased electric distribution revenue primarily due to the one-time reduction for decreased expenses associated with OPEB plan design changes, mostly offset by increased costs and capital investment. During the six months ended June 30, 2014, ComEd recorded increased electric distribution revenue primarily due to increased costs and capital investment, partially offset by the one-time reduction for decreased expenses associated with OPEB plan design changes. See Operating and Maintenance Expense below, and Note 5 - Regulatory Matters and Note 13 - Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on ComEd's rate formula pursuant to EIMA and the OPEB plan design changes. Transmission Revenues. ComEd's transmission rates are established based on a FERC-approved formula. ComEd's most recent annual formula rate update, filed in April 2014, reflects 2013 actual costs plus forecasted 2014 capital additions. Transmission revenue net of purchased power expense vary from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing determinants, such as the highest daily peak load from the previous calendar year. See Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Regulatory Required Programs. Revenues related to regulatory required programs represents the recoveries from customers for costs of various legislative and regulatory programs on a full and current basis through approved regulated rates. Programs include ComEd's energy efficiency and demand response and purchased power administrative costs. An equal and offsetting amount has been reflected in operating and maintenance expense during the periods presented. 188



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Uncollectible Accounts Recovery, Net. Represents recoveries under ComEd's uncollectible accounts tariff. See the operating and maintenance expense discussion below for additional information on this tariff.

Pricing and Customer Mix. The increase in revenue net of purchased power as a result of pricing and customer mix is primarily attributable to higher overall effective rates due to decreased usage across all major customer classes and change in customer mix for the three and six months ended June 30, 2014, as compared to the same periods in 2013. Revenue Subject to Refund. ComEd records revenues subject to refund based upon its best estimate of customer collections that may be required to be refunded. As of the three and six months ended June 30, 2014 ComEd recorded $9 million of revenue subject to refund. Other. Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, revenue from other utilities for mutual assistance programs and recoveries of environmental costs associated with MGP sites, for which an equal and offsetting amount is reflected in depreciation and amortization expense during the periods presented.



Operating and Maintenance Expense

Three Months Ended Six Months Ended June 30, Increase June 30, Increase 2014 2013 (Decrease) 2014 2013 (Decrease) Operating and maintenance expense - baseline $ 281$ 304$ (23 )$ 559$ 593$ (34 ) Operating and maintenance expense - regulatory required programs(a) 74 55 19 122 94 28 Total operating and maintenance expense $ 355$ 359 $ (4 ) $ 681$ 687 $ (6 )



(a) Operating and maintenance expenses for regulatory required programs are costs

for various legislative and/or regulatory programs that are recoverable from

customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenues. 189



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The changes in operating and maintenance expense for the three and six months ended June 30, 2014 compared to the same periods in 2013, consisted of the following: Three Months Ended Six Months Ended June 30, June 30, Increase Increase (Decrease) (Decrease) Baseline Labor, other benefits, contracting and materials $ 4 $ 10 Pension and non-pension postretirement benefits expense (27 ) (38 ) Storm-related costs (11 ) (6 ) Uncollectible accounts expense - provision(a) 1 2 Uncollectible accounts expense - recovery, net(a) 6 (14 ) Other 4 12 (23 ) (34 ) Regulatory required programs Energy efficiency and demand response programs 18 27 Purchased power administrative costs 1 1 19 28 Decrease in operating and maintenance expense $ (4 ) $ (6 )



(a) ComEd is allowed to recover from or refund to customers the difference

between the utility's annual uncollectible accounts expense and the amounts

collected in rates annually through a rider mechanism. During the three and

six months ended June 30, 2014, ComEd recorded a net increase and reduction,

respectively, in operating and maintenance expense related to uncollectible

accounts due to the timing of regulatory cost recovery and customers

purchasing electricity from competitive electric generation suppliers as a

result of municipal aggregation. An equal and offsetting increase and

reduction, respectively, has been recognized in operating revenues for the

periods presented.

Depreciation and Amortization

Depreciation and amortization expense increased during the three and six months ended June 30, 2014, compared to the same periods in 2013, primarily due to ongoing capital expenditures and increased regulatory asset amortization related to higher MGP remediation expenditures. An equal and offsetting amount for the amortization expense related to the MGP remediation expenditures is reflected in operating revenues during the periods presented.



Taxes Other Than Income

Taxes other than income taxes, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes remained relatively flat for the three and six months ended June 30, 2014, compared to the same periods in 2013. 190



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Interest Expense, Net

The changes in interest expense, net for the three and six months ended June 30, 2014, compared to the same period in 2013, consisted of the following:

Three Months Ended Six Months Ended June 30, June 30, Increase Increase (Decrease) (Decrease) Interest expense related to uncertain tax positions(a) $ - $ 275 Interest expense on debt (including financing trusts) (4 ) (6 ) Decrease in interest expense, net $ (4 ) $ 269



(a) Primarily reflects the remeasurement of Exelon's like-kind exchange tax

position in the first quarter of 2013. See Note 11 - Income Taxes of the

Combined Notes to Financial Statements for additional information.

Effective Income Tax Rate

The effective income tax rate was 39.3% for the three months ended June 30, 2014 compared to 40.7% for the same period during 2013. The effective income tax rate was 39.6% for the six months ended June 30, 2014 compared to 36.4% for the same period during 2013. See Note 11 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 191



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ComEd Electric Operating Statistics and Revenue Detail

Three Months Ended Weather- June 30, Normal Retail Deliveries to Customers (in GWhs) 2014 2013 % Change % Change Retail Deliveries(a) Residential 6,177 6,090 1.4 % 1.1 % Small commercial & industrial 7,759 7,832 (0.9 )% (1.3 )% Large commercial & industrial 6,769 6,711 0.9 % 0.5 % Public authorities & electric railroads 304 294 3.4 % 5.7 % Total Retail Deliveries 21,009 20,927 0.4 % 0.0 % Six Months Ended Weather- June 30, Normal % Retail Deliveries to Customers (in GWhs) 2014 2013 % Change Change Retail Deliveries(a) Residential 13,587 12,966 4.8 % 1.5 % Small commercial & industrial 16,090 15,705 2.5 % 0.5 % Large commercial & industrial 13,864 13,551 2.3 % 0.8 % Public authorities & electric railroads 701 667 5.1 % 5.5 % Total Retail Deliveries 44,242 42,889 3.2 % 0.9 % As of June 30, Number of Electric Customers 2014 2013 Residential 3,487,337 3,465,712 Small commercial & industrial 367,354 366,153 Large commercial & industrial 2,025 2,006 Public authorities & electric railroads 4,827 4,852 Total 3,861,543 3,838,723 Three Months Ended Six Months Ended June 30, June 30, Electric Revenue 2014 2013 % Change 2014 2013 % Change Retail Sales(a) Residential $ 499$ 476 4.8 % $ 1,007$ 1,060 (5.0 )% Small commercial & industrial 340 315 7.9 % 684 623 9.8 % Large commercial & industrial 113 113 0.0 % 229 215 6.5 % Public authorities & electric railroads 12 12 0.0 % 24 24 0.0 % Total Retail 964 916 5.2 % 1,944 1,922 1.1 % Other Revenue(b) 164 164 0.0 % 318 317 0.3 % Total Electric Revenues $ 1,128$ 1,080 4.4 % $ 2,262$ 2,239 1.0 %



(a) Reflects delivery revenues and volumes from customers purchasing electricity

directly from ComEd and customers purchasing electricity from a competitive

electric generation supplier, as all customers are assessed delivery charges.

For customers purchasing electricity from ComEd, revenue also reflects the

cost of energy and transmission.

(b) Other revenue primarily includes transmission revenue from PJM. Other items

include rental revenue, revenue related to late payment charges, revenue from

other utilities for mutual assistance programs and recoveries of environmental costs associated with MGP sites. 192



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Table of Contents Results of Operations - PECO Three Months Ended Favorable Six Months Ended Favorable June 30, (Unfavorable) June 30, (Unfavorable) 2014 2013 Variance 2014 2013 Variance Operating revenues $ 656$ 672 $ (16 ) $ 1,649$ 1,567 $ 82 Purchased power and fuel 241 258 17 705 664 (41 ) Revenue net of purchased power and fuel(a) 415 414 1 944 903 41 Other operating expenses Operating and maintenance 184 181 (3 ) 464 369 (95 ) Depreciation and amortization 59 56 (3 ) 117 113 (4 ) Taxes other than income 38 39 1 80 80 - Total other operating expenses 281 276 (5 ) 661 562 (99 ) Operating income 134 138 (4 ) 283 341 (58 ) Other income and (deductions) Interest expense, net (28 ) (28 ) - (56 ) (57 ) 1 Other, net 1 - 1 3 3 - Total other income and (deductions) (27 ) (28 ) 1 (53 ) (54 ) 1 Income before income taxes 107 110 (3 ) 230 287 (57 ) Income taxes 23 32 9 57 87 30 Net income 84 78 6 173 200 (27 ) Preferred security dividends and redemption - 6 6 - 7 7 Net income attributable to common shareholders $ 84$ 72 $ 12 $ 173$ 193 $ (20 )



(a) PECO evaluates its operating performance using the measures of revenue net of

purchased power expense for electric sales and revenue net of fuel expense

for gas sales. PECO believes revenue net of purchased power expense and

revenue net of fuel expense are useful measurements of its performance

because they provide information that can be used to evaluate its net revenue

from operations. PECO has included the analysis below as a complement to the

financial information provided in accordance with GAAP. However, revenue net

of purchased power expense and revenue net of fuel expense figures are not a

presentation defined under GAAP and may not be comparable to other companies'

presentations or more useful than the GAAP information provided elsewhere in

this report.

Net Income attributable to common shareholders

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. The increase in net income attributable to common shareholders was driven primarily by a decrease to income tax expense and redemption of preferred securities in May 2013, partially offset by an increase in operating expenses.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. The decrease in net income attributable to common shareholders was driven primarily by higher operating and maintenance expenses, partially offset by higher operating revenue net of purchased power and fuel expense and a decrease to income taxes expense and redemption of preferred securities in May 2013.



Operating Revenues, Purchased Power and Fuel Expense

Electric and gas revenues and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. PECO's electric supply and natural gas cost rates charged to customers are subject to adjustments at least quarterly that are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with the PAPUC's GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and gas revenue net of purchased power and fuel expense. 193



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Electric and gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customers have the choice to purchase electricity and gas from competitive electric generation and natural gas suppliers, respectively. The customer's choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer choice program activity has no impact on electric and gas revenue net of purchased power and fuel expense. The number of retail customers purchasing electricity from a competitive electric generation supplier was 538,800 and 523,900 at June 30, 2014 and 2013, respectively. Retail deliveries purchased from competitive electric generation suppliers represented 72% and 70% of PECO's retail kWh sales for the three and six months ended June 30, 2014, respectively, compared to 70% and 68% for the three and six months ended June 30, 2013. The number of retail customers purchasing natural gas from a competitive natural gas supplier was 74,800 and 59,100 at June 30, 2014 and 2013, respectively. Retail deliveries purchased from competitive natural gas suppliers represented 24% and 21% of PECO's mmcf sales for the three and six months ended June 30, 2014, respectively, compared to 21% and 18% for the three and six months ended June 30, 2013. The changes in PECO's operating revenues net of purchased power and fuel expense for the three and six months ended June 30, 2014 compared to the same period in 2013 consisted of the following: Three Months Ended Six Months Ended June 30, June 30, Increase Increase (Decrease) (Decrease) Electric Gas Total Electric Gas Total Weather $ (9 )$ 1$ (8 )$ 10$ 16$ 26 Volume 2 1 3 7 2 9 Pricing (2 ) - (2 ) (6 ) (3 ) (9 ) Regulatory required programs 5 - 5 13 - 13 Other 2 1 3 2 - 2 Total increase (decrease) $ (2 )$ 3$ 1$ 26$ 15$ 41 Weather. The demand for electricity and gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and gas businesses, very cold weather in winter months are referred to as "favorable weather conditions" because these weather conditions result in increased deliveries of electricity and gas. Conversely, mild weather reduces demand. During the three months ended June 30, 2014 compared to the same period in 2013, operating revenues net of purchased power and fuel expense were lower due to unfavorable spring and summer weather conditions in PECO's service territory. During the six months ended June 30, 2014 compared to the same period in 2013, operating revenues net of purchased power and fuel expense were higher due to the impact of favorable 2014 winter weather conditions, offset by unfavorable 2014 spring and summer weather conditions in PECO's service territory. 194



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Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO's service territory. The changes in heating and cooling degree days in PECO's service territory for the three and six months ended June 30, 2014 compared to the same periods in 2013 and normal weather consisted of the following: % Change Heating and Cooling Degree-Days 2014 2013 Normal From 2013 From Normal Three Months Ended June 30, Heating Degree-Days 393 421 463 (6.7 )% (15.1 )% Cooling Degree-Days 375 418 348 (10.3 )% 7.8 % Six Months Ended June 30, Heating Degree-Days 3,237 2,861 2,939 13.1 % 10.1 % Cooling Degree-Days 375 418 348 (10.3 )% 7.8 % Volume. The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and six months ended June 30, 2014 compared to the same period in 2013, primarily reflects the impact of moderate economic and customer growth and a shift in the volume profile across classes from lower priced classes to higher priced classes, partially offset by energy efficiency initiatives on customer usages.



Pricing. The decrease in operating revenues net of purchased power and fuel expense as a result of pricing is primarily attributable to lower overall effective rates due to increased usage per customer across all customer classes.

Regulatory Required Programs. This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as smart meter, energy efficiency and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the operating and maintenance expense discussion below for additional information on included programs.



Operating and Maintenance Expense

Three Months Ended Six Months Ended June 30, Increase June 30, Increase 2014 2013 (Decrease) 2014 2013 (Decrease) Operating and Maintenance Expense - Baseline $ 155$ 155 $ - $ 415$ 329 $ 86 Operating and Maintenance Expense - Regulatory Required Programs(a) 29 26 3 49 40 9 Total Operating and Maintenance Expense $ 184$ 181 $ 3 $ 464$ 369 $ 95



(a) Operating and maintenance expenses for regulatory required programs are costs

for various legislative and/or regulatory programs that are recoverable from

customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenues. 195



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The changes in operating and maintenance expense for the three and six months ended June 30, 2014 compared to the same periods in 2013, consisted of the following: Three Months Ended Six Months Ended June 30, June 30, Increase Increase (Decrease) (Decrease) Baseline Labor, other benefits, contracting and materials $ 5 $ 6 Storm-related costs 5 84 (a) Injuries and Damages (1 ) (3 ) Pension and non-pension postretirement benefits expense (2 ) - Constellation merger and integration costs (2 ) (5 ) Uncollectable Accounts Expense (8 ) 1 Other 3 3 - 86 Regulatory Required Programs Smart Meter 3 6 Energy Efficiency - 3 3 9 Increase (Decrease) in operating and maintenance expense $ 3 $ 95



(a) Total storm-related costs include approximately $70 million of incremental

storm costs incurred from the February 5, 2014 ice storm and other storms

during the first half of 2014.

Depreciation and Amortization Expense

The increase in depreciation and amortization expense for the three and six months ended June 30, 2014 compared to the same periods in 2013 was primarily due to ongoing capital expenditures.

Taxes Other Than Income

The change in taxes other than income for the three and six months ended June 30, 2014 compared to the same period in 2013 remained relatively constant.

Interest Expense, Net

The decrease in interest expense, net for the three and six months ended June 30, 2014 compared to the same periods in 2013 remained relatively constant.

Other, Net

The change in Other, net for the three and six months ended June 30, 2014 remained relatively level compared to the same period in 2013.

Effective Income Tax Rate

PECO's effective income tax rate was 21.5% and 29.1% for the three months ended June 30, 2014 and 2013, respectively.

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The effective income tax rate was 24.8% and 30.3% for the six months ended June 30, 2014 and 2013, respectively. See Note 11 - Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.



PECO Electric Operating Statistics and Revenue Detail

Three Months Weather- Six Months Weather- Ended June 30, % Normal Ended June 30, % Normal Retail Deliveries to Customers (in GWhs) 2014 2013 Change % Change 2014 2013 Change % Change Retail Deliveries(a) Residential 2,801 2,888 (3.0 )% 1.6 % 6,649 6,353 4.7 % 1.5 % Small commercial & industrial 1,947 1,960 (0.7 )% 0.7 % 4,002 3,969 0.8 % 0.1 % Large commercial & industrial 3,741 3,784



(1.1 )% (0.6 )% 7,518 7,430 1.2 %

0.7 % Public authorities & electric railroads 222 238 (6.8 )% (6.8 )% 481 493 (2.4 )% (2.4 )% Total Retail Deliveries 8,711 8,870 (1.8 )% 0.2 % 18,650 18,245 2.2 % 0.8 % As of June 30, Number of Electric Customers 2014 2013 Residential 1,428,080 1,419,977 Small commercial & industrial 149,259 148,723 Large commercial & industrial 3,108 3,109 Public authorities & electric railroads 9,712 9,672 Total 1,590,159 1,581,481 Three Months Six Months Ended June 30, % Ended June 30, % Electric Revenue 2014 2013 Change 2014 2013 Change Retail Sales(a) Residential $ 338$ 354 (4.5 )% $ 782$ 749 4.4 % Small commercial & industrial 101 109 (7.3 )% 212 215 (1.4 )% Large commercial & industrial 54 61 (11.5 )% 117 120 (2.5 )% Public authorities & electric railroads 8 8 0.0 % 16 16 0.0 % Total Retail 501 532 (5.8 )% 1,127 1,100 2.5 % Other Revenue(b) 58 53 9.4 % 109 108 0.9 % Total Electric Revenues $ 559$ 585 (4.4 )% $ 1,236$ 1,208 2.3 %



(a) Reflects delivery volumes and revenues from customers purchasing electricity

directly from PECO and customers purchasing electricity from a competitive

electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.



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

revenues. 197



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PECO Gas Operating Statistics and Revenue Detail

Three Months Ended Weather- Six Months Ended Weather- June 30, Normal June 30, Normal



Deliveries to Customers (in mmcf) 2014 2013 % Change

% Change 2014 2013 % Change % Change Retail Delivery Retail sales(a) 7,424 6,919 7.3 % 3.9 % 40,594 35,357 14.8 % 1.4 % Transportation and other 6,005 5,956 0.8 % (0.8 )% 14,374 14,839 (3.1 )% (4.5 )% Total Gas Deliveries 13,429 12,875 4.3 % 1.4 % 54,968 50,196 9.5 % (1.6 )% As of June 30, Number of Gas Customers 2014 2013 Residential 459,407 455,518 Commercial & industrial 42,042 41,648 Total Retail 501,449 497,166 Transportation 882 903 Total 502,331 498,069 Three Months Ended Six Months Ended June 30, June 30, Gas Revenue 2014 2013 % Change 2014 2013 % Change Retail Sales Retail sales(a) $ 88$ 78 12.8 % $ 390$ 338 15.4 % Transportation and other 9 9 0.0 % 23 21 9.5 % Total Gas Revenues $ 97$ 87 11.5 % $ 413$ 359 15.0 %



(a) Reflects delivery volumes and revenues from customers purchasing natural gas

directly from PECO and customers purchasing natural gas from a competitive

natural gas supplier as all customers are assessed distribution charges. For

customers purchasing natural gas from PECO, revenue also reflects the cost of

natural gas. 198



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Table of Contents Results of Operations - BGE Three Months Ended Favorable Six Months Ended Favorable June 30, (Unfavorable) June 30, (Unfavorable) 2014 2013 Variance 2014 2013 Variance Operating revenues $ 653$ 653 $ - $ 1,707$ 1,533 $ 174 Purchased power and fuel 268 288 20 797 713 (84 ) Revenue net of purchased power and fuel(a) 385 365 20 910 820 90 Other operating expenses Operating and maintenance 188 160 (28 ) 376 303 (73 ) Depreciation and amortization 89 82 (7 ) 197 175 (22 ) Taxes other than income 53 54 1 113 109 (4 ) Total other operating expenses 330 296 (34 ) 686 587 (99 ) Operating income 55 69 (14 ) 224 233 (9 ) Other income and (deductions) Interest expense, net (27 ) (32 ) 5 (55 ) (66 ) 11 Other, net 5 4 1 9 9 - Total other income and (deductions) (22 ) (28 ) 6 (46 ) (57 ) 11 Income before income taxes 33 41 (8 ) 178 176 2 Income taxes 14 16 2 72 70 (2 ) Net income 19 25 (6 ) 106 106 - Preference stock dividends 3 3 - 6 6 - Net income attributable to common shareholder $ 16$ 22 $ (6 ) $ 100$ 100 $ -



(a) BGE evaluates its operating performance using the measure of revenue net of

purchased power expense for electric sales and revenue net of fuel expense

for gas sales. BGE believes revenue net of purchased power and fuel expense

are useful measurements of its performance because they provide information

that can be used to evaluate its net revenue from operations. BGE has

included the analysis below as a complement to the financial information

provided in accordance with GAAP. However, revenue net of purchased power and

fuel expense figures are not a presentation defined under GAAP and may not be

comparable to other companies' presentations or more useful than the GAAP

information provided elsewhere in this report.

Net income attributable to common shareholders

Three Months Ended June 30, 2014, Compared to Three Months Ended June 30, 2013. BGE's net income attributable to common shareholders for the three months ended June 30, 2014, was lower than the same period in 2013, primarily due to increases in operating and maintenance expense and depreciation expense, partially offset by an increase in revenue net of purchased power and fuel expense as a result of the December 2013 electric and gas distribution rate order issued by the MDPSC. Six Months Ended June 30, 2014, Compared to Six Months Ended June 30, 2013. BGE's net income attributable to common shareholders for the six months ended June 30, 2014, was consistent with the same period in 2013, primarily due to an increase in revenue net of purchased power and fuel expense as a result of the 2013 electric and gas distribution rate orders issued by the MDPSC, offset by increases in operating and maintenance expense and depreciation expense. 199



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Operating Revenues, Purchased Power and Fuel Expense

There are certain drivers to operating revenue that are offset by their impact on purchased power expense and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Electric and gas revenues and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE's electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC's market-based SOS and gas commodity programs, respectively. The number of customers electing to select a competitive electric generation supplier affects electric SOS revenues and purchased power expense. The number of customers electing to select a competitive natural gas supplier affects gas cost adjustment revenues and purchased natural gas expense. All BGE customers have the choice to purchase energy from a competitive electric generation supplier. This customer choice of electric generation suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to SOS. The number of retail customers purchasing electricity from a competitive electric generation supplier was 382,600 and 389,400 at June 30, 2014 and 2013, respectively, representing 31% of total retail customers at each date. Retail deliveries purchased from competitive electric generation suppliers represented 63% and 60% of BGE's retail kWh sales for the three and six months ended June 30, 2014, respectively, compared to 63% and 61% for the three and six months ended June 30, 2013, respectively. The number of retail customers purchasing natural gas from a competitive natural gas supplier was 165,500 and 161,900 at June 30, 2014 and 2013, respectively, representing 25% of total retail customers at each date. Retail deliveries purchased from competitive natural gas suppliers represented 64% and 51% of BGE's retail mmcf sales for the three and six months ended June 30, 2014, respectively, compared to 63% and 51% for the three and six months ended June 30, 2013, respectively. The changes in BGE's operating revenues net of purchased power and fuel expense for the three and six months ended June 30, 2014, compared to the same period in 2013, consisted of the following: Three Months Ended Six Months Ended June 30, June 30, Increase Increase (Decrease) (Decrease) Electric Gas Total Electric Gas Total

Distribution rate increase $ 7 $ 3$ 10$ 35$ 20$ 55 Regulatory required programs - - - 10 (1 ) 9 Commodity margin - 1 1 1 8 9 Transmission revenues 3 - 3 8 - 8 Other 6 - 6 6 3 9 Total increase $ 16$ 4$ 20$ 60$ 30$ 90 Revenue Decoupling. The demand for electricity and gas is affected by weather and usage conditions. The MDPSC has allowed BGE to record a monthly adjustment to its electric and gas distribution revenues from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE's electric and gas distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means BGE recognizes revenues at MDPSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. BGE bills or credits customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings. 200



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Heating degree days are quantitative indices that reflect the demand for energy needed to heat a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in BGE's service territory. The changes in heating degree days in BGE's service territory for the three and six months ended June 30, 2014 compared to the same period in 2013 consisted of the following: % Change Heating and Cooling Degree-Days 2014 2013 Normal From 2013 From Normal Three Months Ended June 30, Heating Degree-Days 497 492 513 1.0 % (3.1 )% Cooling Degree-Days 233 263 252 (11.4 )% (7.5 )% Six Months Ended June 30, Heating Degree-Days 3,358 2,943 2,900 14.1 % 15.8 % Cooling Degree-Days 233 264 255 (11.7 )% (8.6 )% Distribution Rate Increase. The increase in distribution rates for the three and six months ended June 30, 2014, compared to the same periods in 2013, was primarily due to the impact of the new electric and natural gas distribution rates charged to customers that became effective in December 2013 in accordance with the MDPSC approved electric and natural gas distribution rate case order. See Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Regulatory Required Programs. This represents the change in revenues collected under approved riders to recover costs incurred for the energy efficiency and demand response programs as well as administrative and commercial and industrial customer bad debt costs for SOS. The riders are designed to provide full recovery, as well as a return in certain instances. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and taxes other than income taxes. The increase in revenues during the six months ended June 30, 2014 compared to the same period in 2013 was primarily due to the recovery of higher energy efficiency program costs. Commodity Margin. The increase in commodity margin under BGE's market-based rate incentive mechanism for the three and six months ended June 30, 2014, compared to the same periods in 2013 was primarily due to the higher gas margins earned by BGE due to the extreme cold weather during the first quarter under BGE's MBR mechanism. See Note 9 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. Transmission Revenues. The increase in transmission rates for the three and six months ended June 30, 2014, compared to the same periods in 2013, was primarily due to the impact of the new transmission rates charged to customers that became effective in June 2014. See Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Other. Other revenues, which can vary from period to period, include miscellaneous revenues such as service application and late payment fees. Other revenues increased during the three and six months ended June 30, 2014 compared to the same periods in 2013. 201



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Operating and Maintenance Expense

The changes in operating and maintenance expense for the three and six months ended June 30, 2014 compared to the same periods in 2013, consisted of the following: Three Months Ended Six Months Ended June 30, June 30, Increase Increase (Decrease) (Decrease) Labor, other benefits, contracting and materials $ 8 $ 25 Pension and non-pension postretirement benefits expense 2 4 Storm-related costs (1 ) 13 Uncollectible accounts expense 10 13 Corporate allocations 5 7 Other 4 11 Increase in operating and maintenance expense $ 28 $ 73



Depreciation and Amortization

The increase in depreciation and amortization expense for the three and six months ended June 30, 2014 compared to the same periods in 2013 was primarily due to higher amortization expense related to energy efficiency and demand response programs, which are fully offset in revenues above, and higher property, plant and equipment balances resulting from ongoing capital expenditures.

Taxes Other Than Income

The increase in taxes other than income for the three and six months ended June 30, 2014 compared to the same periods in 2013 was primarily due to increased gross receipts tax as a result of higher revenues.

Interest Expense, Net

The decrease in interest expense, net for the three and six months ended June 30, 2014 compared to the same periods in 2013 was primarily due to favorable interest rates in 2014 on long-term debt balances.

Effective Income Tax Rate

BGE's effective income tax rate was 42.4% and 39.0% for the three months ended June 30, 2014 and 2013, respectively, and 40.4% and 39.8% for the six months ended June 30, 2014 and 2013, respectively. See Note 11 - Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussion of the change in effective income tax rate. 202



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BGE Electric Operating Statistics and Revenue Detail

Three Months Ended Weather- Six Months Weather- June 30, % Normal% Ended June 30, % Normal% Retail Deliveries to Customers (in GWhs) 2014 2013 Change Change 2014 2013 Change Change Retail Deliveries(a) Residential 2,639 2,757



(4.3 )% n.m 6,732 6,293 7.0 % n.m Small commercial & industrial

704 716



(1.7 )% n.m 1,538 1,492 3.1 % n.m Large commercial & industrial

3,593 3,610



(0.5 )% n.m 7,062 7,164 (1.4 )% n.m Public authorities & electric railroads

79 80



(1.3 )% n.m 157 161 (2.5 )% n.m

Total Electric Retail Deliveries 7,015 7,163 (2.1 )% n.m 15,489 15,110 2.5 % n.m As of June 30, Number of Electric Customers 2014 2013 Residential 1,123,804 1,117,569 Small commercial & industrial 112,827 113,009 Large commercial & industrial 11,660 11,612 Public authorities & electric railroads 290 294 Total 1,248,581 1,242,484 Three Months Ended Six Months June 30, % Ended June 30, % Electric Revenue 2014 2013 Change 2014 2013 Change Retail Sales(a) Residential $ 293$ 302 (3.0 )% $ 729$ 667 9.3 % Small commercial & industrial 64 60 6.7 % 136 125 8.8 % Large commercial & industrial 120 112 7.1 % 243 217 12.0 % Public authorities & electric railroads 8 8 - % 16 15 6.7 % Total Retail 485 482 0.6 % 1,124 1,024 9.8 % Other Revenue 67 61 9.8 % 138 124 11.3 % Total Electric Revenues $ 552$ 543 1.7 % $ 1,262$ 1,148 9.9 %



(a) Reflects delivery volumes and revenues from customers purchasing electricity

directly from BGE and customers purchasing electricity from a competitive

electric generation supplier as all customers are assessed distribution

charges. For customers purchasing electricity from BGE, revenue also reflects

the cost of energy and transmission. 203



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BGE Gas Operating Statistics and Revenue Detail

Three Months Ended Weather- Six Months Ended Weather- June 30, Normal June 30, Normal Deliveries to Customers (in mmcf) 2014 2013 % Change % Change 2014 2013 % Change % Change Retail Deliveries(b) Retail sales 14,834 14,951 (0.8 )% n.m. 61,222 55,212 10.9 % n.m. Transportation and other 875 1,545 (43.4 )% n.m. 7,204 7,195 0.1 % n.m. Total Gas Deliveries 15,709 16,496 (4.8 )% n.m. 68,426 62,407 9.6 % n.m. As of June 30, Number of Gas Customers 2014 2013 Residential 612,202 611,146 Commercial & industrial 44,019 44,059 Total 656,221 655,205 Three Months Ended Six Months Ended June 30, June 30, Gas Revenue 2014 2013 % Change 2014 2013 % Change Retail Sales(b) Retail sales $ 92$ 100 (8.0 )% $ 377$ 345 9.3 % Transportation and other(c) 9 10 (10.0 )% 68 40 70.0 % Total Gas Revenues $ 101$ 110 (8.2 )% $ 445$ 385 15.6 %



(b) Reflects delivery volumes and revenues from customers purchasing natural gas

directly from BGE and customers purchasing natural gas from a competitive

natural gas supplier as all customers are assessed distribution charges. The

cost of natural gas is charged to customers purchasing natural gas from BGE.

(c) Transportation and other gas revenue includes off-system revenue of 875 mmcfs

($5 million) and 1,545 mmcfs ($8 million) for the three months ended June 30,

2014 and 2013, respectively, and 7,204 mmcfs ($58 million) and 7,195 mmcfs

($32 million) for the six months ended June 30, 2014 and 2013, respectively.

Liquidity and Capital Resources

Exelon's and Generation's current year activity presented below includes the activity of CENG from the integration date effective April 1, 2014 through June 30, 2014. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants' operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. The Registrants' businesses are capital intensive and require considerable capital resources. Each Registrant's access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, Exelon Corporate, Generation, ComEd, PECO and BGE have access to unsecured revolving credit facilities with aggregate bank commitments of $0.5 billion, $5.3 billion, $1.0 billion, $0.6 billion and $0.6 billion, respectively. Exelon Corporate, Generation, ComEd, PECO and BGE's revolving credit facilities expire in 2019. In addition, Generation has $0.5 billion in bilateral credit facilities. Generation's bilateral credit facilities have expirations in October 2014, January 2015, December 2015 and March 2016. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and issue letters of credit. See the "Credit Matters" section below for further discussion. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements. 204



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The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd, PECO and BGE operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 10 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further discussion of the Registrants' debt and credit agreements.



Cash Flows from Operating Activities

General

Generation's cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation's future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers. ComEd's, PECO's and BGE's cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO and BGE, gas distribution services. ComEd's, PECO's and BGE's distribution services are provided to an established and diverse base of retail customers. ComEd's, PECO's and BGE's future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, competitive suppliers, and their ability to achieve operating cost reductions. See Notes 5 - Regulatory Matters and 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation.



Pension and Other Postretirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. On July 6, 2012, President Obama signed into law the Moving Ahead for Progress in the Twenty-first Century Act, which contains a pension funding provision that results in lower pension contributions in the near term while increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. Certain provisions of the law were applied in 2012 while the others took effect in 2013. The estimated impacts of the law are reflected in the projected pension contributions below. Exelon expects to make qualified pension plan contributions of $317 million to its qualified pension plans in 2014, of which Generation, ComEd, PECO and BGE will contribute $169 million, $119 million, $11 million and $0 million, respectively. Exelon's and Generation's expected qualified pension plan contributions above include $53 million and $51 million, respectively, related to CENG-sponsored plans for the period April 1, 2014 to December 31, 2014 (the period for which CENG is consolidated). Unlike the qualified pension plans, Exelon's non-qualified pension plans are not funded. Exelon expects to make non-qualified pension plan benefit payments of $18 million in 2014, of which Generation, ComEd, PECO and BGE will make payments of $9 million, $1 million, $0 million and $1 million, respectively. Exelon and Generation's non-qualified expected pension plan benefit payments above include $3 million related to CENG-sponsored plans for the period April 1, 2014 to December 31, 2014. 205



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To the extent interest rates decline significantly or the pension plans do not earn the expected asset return rates, annual pension contribution requirements in future years could increase, especially in years 2017 and beyond. Additionally, the contributions above could change if Exelon changes its pension funding strategy. Unlike qualified pension plans, other postretirement benefit plans are not subject to statutory minimum contribution requirements and certain plans are not funded. Exelon's management has historically considered several factors in determining the level of contributions to its funded other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery). Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $290 million in 2014, of which Generation, ComEd, PECO and BGE expect to contribute $128 million, $121 million, $4 million and $18 million, respectively. Exelon and Generation's expected other postretirement benefit plan payments above include $5 million related to CENG-sponsored plans for the period April 1, 2014 to December 31, 2014 and contemplate reductions related to recent plan design changes. During the first quarter of 2014, the Society of Actuaries issued an exposure draft with a proposed revised mortality table for use by actuaries, insurance companies, governments, benefit plan sponsors and others in setting assumptions regarding life expectancy in the United States for purposes of estimating pension and OPEB obligations, costs and required contribution amounts. The newly proposed mortality tables indicate substantial life expectancy improvements since the last study published in 2000 (RP 2000). Adoption of the new mortality table, if issued in its current form, would result in significantly increased future pension and OPEB plan obligations, costs and required contribution amounts for many plan sponsors, including Exelon. Exelon is currently evaluating the exposure draft and potential impacts to the December 31, 2014 valuation and future expected pension and OPEB plan contributions. The IRS has indicated the RP 2000 should be used for ERISA funding calculations impacting qualified pension plans in 2014 and 2015, meaning the earliest a new table would be required for determining those funding requirements is January 1, 2016.



Tax Matters

The Registrants' future cash flows from operating activities may be affected by the following tax matters:

Exelon, Generation, ComEd, PECO and BGE expect to receive tax refunds of

approximately $360 million, $60 million, $320 million, $10 million and $20

million, respectively, between 2014 and 2015.



Given the current economic environment, state and local governments are

facing increasing financial challenges, which may increase the risk of

additional income tax levies, property taxes and other taxes or the imposition, extension or permanence of temporary tax levies.



In the first quarter of 2014, Exelon entered into an agreement to

terminate its investment in one of the three municipal-owned electric

generation properties in exchange for a net early termination amount of

$335 million. The termination will result in a 2014 tax payment of

approximately $285 million by Exelon and its subsidiaries in 2014,

including approximately $155 million by ComEd. Exelon intends to fund its

portion of the tax payment using a portion of the net early termination

amount. ComEd intends to fund its portion of the tax payment using a

combination of debt and equity contributions from Exelon to substantially

maintain its existing capital structure. See Note 11 - Income Taxes of the

Combined Notes to the Consolidated Financial Statements for additional

information.



Under the Taxpayer Relief Act of 2012, 50% bonus depreciation expired on

December 31, 2013. In the second quarter 2014, the Senate Finance

Committee passed a two year extension of 50% bonus depreciation for 2014

and 2015. Further, on July 11, 2014, the House of Representatives passed

H.R. 4718 permanently extending 50% bonus depreciation beginning with the

2014 tax year. If ultimately enacted for 2014 and 2015, 50% bonus

depreciation legislation would generate incremental cash of approximately

$1,175 million, $575 million, $375 million, $100 million, and $125 million, for Exelon, 206



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Generation, ComEd, PECO, and BGE, respectively, primarily in 2015. The cash generated is an acceleration of tax benefits that Registrants would have received over the normal tax depreciable life of the qualifying property. Additionally, the extension of 50% bonus depreciation would result in a decrease to Generation's Domestic Production Activities



Deduction, reducing cash tax benefits and increasing income tax expense by

approximately $35 million and $25 million for 2014 and 2015, respectively. The potential extension of 50% bonus depreciation is not expected to result in a material impact on ComEd's, PECO's, or BGE's results of operations.



The following table provides a summary of the major items affecting Exelon's cash flows from operations for the six months ended June 30, 2014 and 2013:

Six Months Ended June 30, 2014 2013 Variance Net income $ 651$ 498$ 153 Add (subtract): Non-cash operating activities(a) 3,208 2,025 1,183 Gain on consolidation of CENG (268 ) - (268 ) Pension and other postretirement benefit contributions (499 ) (284 ) (215 ) Income taxes (16 ) 705 (721 ) Changes in working capital and other noncurrent assets and liabilities(b) (740 ) (337 ) (403 ) Option premiums received (paid), net 21 (10 ) 31 Counterparty collateral posted, net (606 ) (259 ) (347 ) Net cash flows provided by operations $ 1,751$ 2,338$ (587 )



(a) Represents depreciation, amortization and accretion, impairment of long-lived

assets, mark-to-market gains and losses on derivative transactions, deferred

income taxes, provision for uncollectible accounts, pension and other

postretirement benefit expense, equity in losses of unconsolidated affiliates

and investments, decommissioning-related items, stock compensation expense

and other non-cash charges.

(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.

Cash flows provided by operations for the six months ended June 30, 2014 and 2013 by Registrant were as follows:

Six Months Ended June 30, 2014 2013 Exelon $ 1,751$ 2,338 Generation 742 1,150 ComEd 429 503 PECO 340 467 BGE 410 366 207



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Changes in Exelon's, Generation's, ComEd's, PECO's and BGE's cash flows provided by operations were generally consistent with changes in each Registrant's respective results of operations, as adjusted by changes in working capital in the normal course of business. In addition, significant operating cash flow impacts for the Registrants for the six months ended June 30, 2014 and 2013 were as follows: Generation



During the six months ended June 30, 2014 and 2013, Generation had net

payments of counterparty collateral of $633 million and $303 million,

respectively. Net payments during the six months ended June 30, 2014 and

2013 were primarily due to market conditions that resulted in changes to

Generation's net mark-to-market position and initial margin requirements

on the exchanges. 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. This collateral may

be in various forms, such as cash, which may be obtained through the issuance of commercial paper, or letters of credit.



During the six months ended June 30, 2014 and 2013, Generation had net

collections (payments) of approximately $21 million and $(10) million,

respectively, related to purchases and sales of options. The level of

option activity in a given period may vary due to several factors,

including changes in market conditions as well as changes in hedging

strategy. ComEd



During the six months ended June 30, 2014 and 2013, ComEd's payables for

Generation energy purchases decreased by $33 million and $14 million,

respectively, and payables to other energy suppliers for energy purchases

increased by $55 million and $31 million, respectively. PECO



During the six months ended June 30, 2014 and 2013, PECO's payables to

Generation for energy purchases decreased by $15 million and $11 million,

respectively, and payables to other electric and gas suppliers for energy purchases (decreased) increased by $(4) million and $26 million, respectively. BGE



During the six months ended June 30, 2014 and 2013, BGE's payables to

Generation for energy purchases increased by $9 million and $2 million,

respectively, and payables to other electric and gas suppliers for energy purchases decreased by $16 million and $30 million, respectively.



Cash Flows from Investing Activities

Cash flows used in investing activities for the six months ended June 30, 2014 and 2013 by Registrant were as follows:

Six Months Ended June 30, 2014 2013 Exelon $ (2,187 )$ (2,549 ) Generation (1,014 ) (1,378 ) ComEd (731 ) (693 ) PECO (302 ) (514 ) BGE (332 ) (257 ) 208



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Capital expenditures by Registrant for the six months ended June 30, 2014 and 2013 and projected amounts for the full year 2014 are as follows:

Projected Six Months Ended Full Year June 30, 2014(d) 2014 2013 Exelon $ 5,775$ 2,501$ 2,518 Generation(a) 2,625 1,103 1,277 ComEd(b) 1,775 747 711 PECO 675 308 254 BGE 600 313 264 Other(c) 100 30 12 (a) Includes nuclear fuel.



(b) The projected capital expenditures include approximately $442 million of

expected incremental spending pursuant to EIMA, ComEd has committed to invest

approximately $2.6 billion over a ten year period to modernize and

storm-harden its distribution system and to implement smart grid technology.

(c) Other primarily consists of corporate operations and BSC.

(d) Total projected capital expenditures do not include adjustments for non-cash

activity.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Generation

Approximately 38% and 10% of the projected 2014 capital expenditures at Generation are for the acquisition of nuclear fuel and investments in renewable energy generation, including Antelope Valley and wind construction costs, respectively, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). ComEd, PECO and BGE Approximately 85%, 78% and 88% of the projected 2014 capital expenditures at ComEd, PECO and BGE, respectively, are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd's reliability related investments required under EIMA, and ComEd's, PECO's and BGE's construction commitments under PJM's RTEP. In addition to the capital expenditure for continuing projects, ComEd's total capital expenditures include smart grid/smart meter technology required under EIMA and for PECO and BGE, total capital expenditures related to their respective smart meter program and SGIG project. In 2010, NERC provided guidance to transmission owners that recommends ComEd, PECO and BGE perform assessments of all their transmission lines. In compliance with this guidance, ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd, PECO and BGE will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd's, PECO's and BGE's forecasted 2014 capital expenditures above reflect capital spending in 2014 for remediation to be completed through 2017. ComEd, PECO and BGE anticipate that they will fund their capital expenditures with internally generated funds and borrowings, including ComEd's capital expenditures associated with EIMA as further discussed in Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements. 209



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Cash Flows from Financing Activities

Cash flows provided by (used in) financing activities for the six months ended June 30, 2014 and 2013 by Registrant were as follows:

Six Months Ended June 30, 2014 2013 Exelon(a) $ 189$ (284 ) Generation(a) (681 ) (221 ) ComEd 304 139 PECO (162 ) (259 ) BGE (94 ) 259



(a) Includes $415 million of distributions to EDF.

Debt

See Note 10 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further details of the Registrants' debt issuances and retirements. Dividends



Cash dividend payments and distributions during the six months ended June 30, 2014 and 2013 by Registrant were as follows:

Six Months Ended June 30, 2014 2013 Exelon(a) $ 948$ 716 Generation(a) 650 474 ComEd 153 110 PECO 160 167 BGE(b) 6 6



(a) Includes $415 million of distributions to EDF.

(b) Relates to dividends paid on BGE's preference stock.

First Quarter 2014 Dividend

On January 28, 2014, the Exelon Board of Directors declared a first quarter 2014 regular quarterly dividend of $0.31 per share on Exelon's common stock payable on March 10, 2014, to shareholders of record of Exelon at the end of the day on February 14, 2014. Second Quarter 2014 Dividend On May 6, 2014, the Exelon Board of Directors declared a second quarter 2014 regular quarterly dividend of $0.31 per share on Exelon's common stock payable on June 10, 2014, to shareholders of record of Exelon at the end of the day on May 16, 2014. Third Quarter 2014 Dividend On July 29, 2014, the Exelon Board of Directors declared a third quarter 2014 regular quarterly dividend of $0.31 per share on Exelon's common stock payable on September 10, 2014 to shareholders of record of Exelon at the end of the day on August 15, 2014. 210



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Short-Term Borrowings

During the six months ended June 30, 2014, ComEd and BGE issued(repaid) $314 million and $(65) million of commercial paper, respectively, and Generation issued $ 31 million in short-term notes payable. During the six months ended June 30, 2013, ComEd issued $374 million of commercial paper and Generation issued $276 million of commercial paper and $12 million in short-term notes payable.



Contributions from Parent/Member

During the six months ended June 30, 2014, ComEd received $112 million from Parent (Exelon). During the six months ended June 30, 2013, there were no contributions from Parent/Member (Exelon).

Distributions from Parent/Member

On April 1, 2014, Generation loaned $400 million to CENG, the proceeds of which were used to make a distribution to EDFI of $400 million. See Note 6 - Investment in Constellation Energy Nuclear Group, LLC for additional information on the integration of CENG.



Other

For the six months ended June 30, 2014, other financing activities primarily consisted of financing costs associated with the acquisition of PHI, other project financing and various debt issuance costs. See Notes 4, 10 and 16 for additional information. Credit Matters The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include $8.5 billion in aggregate total commitments of which $6.5 billion was available as of June 30, 2014, and of which no financial institution has more than 8% of the aggregate commitments. Exelon, Generation, ComEd, PECO and BGE had access to the commercial paper market during the second quarter of 2014 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See Part I. Item 1A. Risk Factors of Exelon's 2013 Annual Report on Form 10-K for further information regarding the effects of uncertainty in the capital and credit markets. The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of June 30, 2014, it would have been required to provide incremental collateral of $2.0 billion to meet collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within its current available credit facility capacities of $4.3 billion. If ComEd lost its investment grade credit rating as of June 30, 2014, it would have been required to provide incremental collateral of $7 million, which is well within its current available credit facility capacity of $500 million, which takes into account commercial paper borrowings as of June 30, 2014. If PECO lost its investment grade credit rating as of June 30, 2014, it would not be required to provide collateral pursuant to PJM's credit policy and would have been required to provide collateral of $26 million 211



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related to its natural gas procurement contracts, which, in the aggregate, are well within PECO's current available credit facility capacity of $599 million. If BGE lost its investment grade credit rating as of June 30, 2014, it would have been required to provide collateral of $4 million pursuant to PJM's credit policy and would have been required to provide collateral of $73 million related to its natural gas procurement contracts, which, in the aggregate, are well within BGE's current available credit facility capacity of $530 million.



Exelon Credit Facilities

Exelon, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Note 10 - Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for further information regarding the Registrants' credit facilities. The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at June 30, 2014: Commercial Paper Programs Average Interest Rate on Commercial Paper Outstanding Borrowings for the Six Maximum Commercial Paper at Months Ended Commercial Paper Issuer Program Size June 30, 2014 June 30, 2014 Exelon Corporate $ 500 $ - - Generation 5,600 - 0.32 % ComEd 1,000 498 0.33 % PECO 600 - - BGE 600 70 0.27 % In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant's credit agreement, a Registrant does not issue commercial paper in an aggregate amount exceeding the available capacity under its credit agreement. Credit Agreements Available Capacity at June 30, 2014 To Support Outstanding Additional Aggregate Bank Facility Letters of Commercial Borrower Facility Type Commitment(a) Draws Credit Actual Paper

Exelon Corporate Syndicated Revolver $ 500 $ - $ 2 $ 498 $ 498 Generation Syndicated Revolver 5,300 - 1,161 4,139 4,139 Generation Bilaterals 375 - 245 1 130 CENG Bilaterals 100 40 - 60 - ComEd Syndicated Revolver 1,000 - 2 998 500 PECO Syndicated Revolver 600 - 1 599 599 BGE Syndicated Revolver 600 - - 600 530



(a) Excludes $123 million of credit facility agreements arranged with minority

and community banks at Generation, ComEd, PECO and BGE. These facilities

expire on October 18, 2014, and are solely utilized to issue letters of

credit. See Note 10 - Debt and Credit Agreements of the Combined Notes to the

Consolidated Financial Statements for further information. 212



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As of June 30, 2014, there were no borrowings under the Registrants' credit facilities, with the exception of CENG, see discussion below.

On March 28, 2014, ComEd extended its unsecured revolving credit facility with aggregate bank commitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The credit agreement expires on March 28, 2019. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to extend the facility for ComEd were not material. On April 1, 2014, as a result of the CENG integration, a $100 million bilateral CENG credit facility expiring October 2014 is now consolidated in Exelon's and Generation's consolidated financial statements. This facility will be utilized by CENG to fund working capital and capital projects and obtain letters of credit. As of June 30, 2014, CENG borrowed $40 million against its credit facility. On May 30, 2014, Exelon, Generation, PECO and BGE extended for an additional year the expiration date of its unsecured revolving credit facility with aggregate bank commitments of $500 million, $5.3 billion, $600 million, $600 million, respectively into May 2019, with the exception of a cumulative amount of $300 million which expires in August 2018. Costs incurred to extend the facility were not material. Borrowings under Exelon Corporate's, Generation's, ComEd's, PECO's and BGE's credit facilities bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the registrants credit rating. Exelon Corporate, Generation, ComEd, PECO and BGE have adders of 27.5, 27.5, 7.5, 0.0 and 0.0 basis points for prime based borrowings and 127.5, 127.5, 107.5, 90.0 and 100.0 basis points for LIBOR-based borrowings. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments under the agreement. The fee varies depending upon the respective credit ratings of the borrower. Each revolving credit agreement for Exelon, Generation, ComEd, PECO and BGE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the six months ended June 30, 2014: Exelon Generation ComEd PECO BGE Credit agreement threshold 2.50 to 1 3.00 to 1 2.00



to 1 2.00 to 1 2.00 to 1

At June 30, 2014, the interest coverage ratios at the Registrants were as follows: Exelon Generation ComEd PECO BGE Interest coverage ratio 10.63 11.73 5.99 7.95 8.53 An event of default under any Registrant's indebtedness will not constitute an event of default under any of the other Registrants' credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation will constitute an event of default under the Exelon Corporate credit facility. Security Ratings The Registrants' access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets. 213



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The Registrants' borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant's securities could increase fees and interest charges under that Registrant's credit agreements. As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 9 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.



Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of June 30, 2014, are presented in the following table: During the three months ended As of June 30, 2014 June 30, 2014 Maximum Maximum Contributed Contributed (borrowed) as of June 30, 2014 Contributed Borrowed (Borrowed) Generation $ - $ 405 $ (190 ) PECO 129 - - BSC - 329 (259 ) Exelon Corporate 563 N/A 449



Investments in Nuclear Decommissioning Trust Funds

Exelon, Generation and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation's NDT fund investment policy. Generation's and CENG's investment policies establish limits on the concentration of holdings in any one company and also in any one industry. See Note 12 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC's minimum funding requirements and related liquidity ramifications.



Shelf Registration Statements

The Registrants have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in May 2017. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.



Regulatory Authorizations

As of June 30, 2014, ComEd had $702 million available in long-term debt refinancing authority and $1.2 billion available in new money long-term debt financing authority from the ICC. As of June 30, 2014, PECO had $1.4 billion available in long-term debt financing authority from the PAPUC. As of June 30, 2014, BGE had $850 million available in long-term financing authority from MDPSC. As of June 30, 2014, ComEd, PECO and BGE had short-term financing authority from FERC, which expires on December 31, 2015, of $2.5 billion, $2.5 billion, and $0.7 billion, respectively. Generation currently has blanket financing authority from FERC, which was granted in connection with its market-based rate authority. 214



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Contractual Obligations and Off-Balance Sheet Arrangements

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for discussion of the Registrants' commitments. Generation, ComEd, PECO and BGE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd, PECO and BGE have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants' respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 - Basis of Presentation of the Combined Notes to Consolidated Financial Statements for further information.



For an in-depth discussion of the Registrant's contractual obligations and off-balance sheet arrangements, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Contractual Obligations and Off-Balance Sheet Arrangements" in the Exelon 2013 Form 10-K.

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