Earnings conference call presentation slides

Cautionary Statements Regarding

Forward-Looking Information

This presentation contains certain forward-looking statements within the meaning of the Private Securities

Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual

results to differ materially from the forward-looking statements made by Exelon Corporation, Commonwealth

Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company,

LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2011

Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data:

Note 18; (2) Constellation Energy Group’s 2011 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b)

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8.

Financial Statements and Supplementary Data: Note 12; (3) the Registrant’s First Quarter 2012 Quarterly

Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information,

ITEM 1. Financial Statements: Note 15; and (4) other factors discussed in filings with the SEC by the Registrants.

Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as

of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any

revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

2012 2Q Earnings Release Slides

2012 2Q Earnings Release Slides

Second Quarter Performance and Full Year Guidance

FY 2012

$2.55 -

$2.85

(2)

$1.75 -

$1.95

$0.30 -

$0.40

$0.40 -

$0.50

$0.05 -

$0.15

HoldCo

ExGen

ComEd

PECO

BGE

2012 Earnings Guidance

•

Another quarter of solid financial and operating

performance

Operating earnings in 2Q of $0.61/share

Nuclear capacity factor in 2Q of 93.4%

Load serving business on course to meet volume and

margin targets

•

Expect FY 2012 earnings of $2.55 -

$2.85/share

On track to achieve $170 million in merger related

synergies for 2012

(1)

On track to meet FY 2012 new business gross margin

targets for “Power”

and “Non Power”

Category

MM)

(1)

2012

(2)

2013

2014

Open Gross Margin

(including South, West & Canada hedged GM)

(3,4)

$4,450

$5,400

$5,850

Mark to Market of Hedges

(5)

$3,100

$1,650

$600

Power New Business / To Go

$100

$550

$850

Non-Power Margins Executed

$250

$100

Non-Power New Business / To Go

$150

$500

Total Gross Margin

$8,050

$8,200

$7,900

(1) Gross margin rounded to nearest $50M.

(2) Stub period calculated by excluding Jan 2012 thru mid-March 2012 for Constellation only.

(3) Excludes Maryland assets to be divested.

Reference

Prices

(6)

2012

2013

2014

Henry Hub Natural Gas ($/MMbtu)

$2.72

$3.58

$3.95

Midwest: NiHub ATC prices ($/MWh)

$27.17

$28.85

$30.57

Mid-Atlantic: PJM-W ATC prices ($/MWh)

$32.35

$36.25

$38.42

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$12.19

$7.44

$6.48

New York: NY Zone A ($/MWh)

$29.55

$31.45

$32.99

New England: Mass Hub ATC Spark Spread($/MWh)

ALQN Gas, 7.5HR, $0.50 VOM

$6.17

$4.93

$4.20

(4) Includes CENG Joint Venture.

(5) Mark to Market of Hedges assumes mid-point of hedge percentages.

(6) Based on June 29, 2012 market conditions.

2012 2Q Earnings Release Slides

ExGen Disclosures

Generation and Hedges

2012

(1)

2013

2014

Exp. Gen (GWh)

(4)

219,600

216,900

209,200

Midwest

101,000

97,600

Mid-Atlantic

(2,3)

71,900

73,600

71,400

ERCOT

19,900

17,800

15,400

New York

(3)

13,400

13,600

10,700

New England

13,400

14,300

14,100

% of Expected Generation Hedged

(5)

99-102%

79-82%

46-49%

Midwest

98-101%

80-83%

47-50%

Mid-Atlantic

(2,3)

102-105%

78-81%

49-52%

ERCOT

96-99%

70-73%

39-42%

New York

(3)

101-104%

85-88%

38-41%

New England

96-99%

79-82%

41-44%

Effective Realized Energy Price ($/MWh)

(6)

Midwest

40.50

39.00

36.00

Mid-Atlantic

(2,3)

53.50

49.00

48.00

ERCOT

9.00

7.00

4.00

New York

(3)

45.00

37.00

37.50

New England

(7)

7.50

7.00

4.00

2012 2Q Earnings Release Slides

(1) Stub period calculated by excluding Jan 2012 thru mid-March 2012 for Constellation only. (2) Excludes Maryland assets to be divested (3) Includes CENG Joint Venture. (4) Expected generation represents

the amount of energy estimated to be generated or purchased through owned or contracted for capacity. Expected generation is based upon a simulated dispatch model that makes assumptions regarding

future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 10 refueling outages in 2012 and 2013 and 11 refueling

outages in 2014 at Exelon-operated nuclear plants and Salem but excludes CENG. Expected generation assumes capacity factors of 93.1%, 93.3% and 93.8% in 2012, 2013 and 2014 at Exelon-operated

nuclear plants excluding Salem and CENG. These estimates of expected generation in 2012, 2013 and 2014 do not represent guidance or a forecast of future results as Exelon has not completed its planning

or optimization processes for those years. (5) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and

retail sales of power, options and swaps. Uses expected value on options. (6) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has

been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs

and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices

used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. (7) Spark spreads shown for ERCOT and New England.

ExGen Hedged Gross Margin Sensitivities

Gross

Margin

Sensitivities

(With

Existing

Hedges)

(1,4)

2012

2013

2014

Henry

Hub

Natural

Gas

($/MMbtu)

(2)

+ $1/Mmbtu

$(65)

$120

$490

$1/Mmbtu

$75

$(100)

$(430)

NiHub ATC Energy Price

+ $5/MWh

$85

$280

$5/MWh

$(5)

$(85)

$(275)

PJM-W ATC Energy Price

(2)

+ $5/MWh

$(15)

$80

$190

$5/MWh

$15

$(80)

$(185)

NYPP Zone A ATC Energy Price

+ $5/MWh

$10

$45

$5/MWh

$(5)

$(10)

$(45)

Nuclear Capacity Factor

(3)

+/-

$15

+/-

$40

+/-

$40

2012 2Q Earnings Release Slides

(1) Based on June 29, 2012 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is updated

periodically. Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant. Due to correlation of the various assumptions, the

hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact calculated when correlations between the various

assumptions are also considered. (2) Excludes Maryland assets to be divested. (3) Includes CENG Joint Venture (4) Sensitivities based on commodity exposure which includes open generation

and all committed transactions.

Exelon Generation Hedged Gross Margin Upside/Risk

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

2014

2013

2012

$8,200

$7,900

$8,700

$7,800

$9,300

$6,900

2012 2Q Earnings Release Slides

(1) Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold

into the spot market. Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential

modeling changes. These ranges of approximate gross margin in 2013 and 2014 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or

optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of June 29, 2012

(2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. (3) Excludes Maryland assets to be divested.

Illustrative Example of Modeling Exelon Generation

2013 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin

$5.4 billion

(B)

Expected Generation (TWh)

97.6

73.6

17.8

13.6

14.3

(C)

Hedge % (assuming mid-point of range)

81.5%

79.5%

71.5%

86.5%

80.5%

(D=B*C)

Hedged Volume (TWh)

79.5

58.5

12.7

11.9

11.7

(E)

Effective Realized Energy Price ($/MWh)

$39.00

$49.00

$7.00

$37.00

$7.00

(F)

Reference Price ($/MWh)

$28.85

$36.25

$7.44

$31.45

$4.93

(G=E-F)

Difference ($/MWh)

$10.15

$12.75

($0.44)

$5.55

$2.07

(H=D*G)

$810 million

$745 million

($5) million

$65 million

$25 million

(I=A+H)

Hedged Gross Margin ($ million)

$7,050 million

(J)

Power New Business / To Go ($ million)

$550 million

(K)

Non-Power Margins Executed ($ million)

$100 million

(L)

Non-Power New Business / To Go ($ million)

$500 million

(N=I+J+K+L)

Total Gross Margin

$8,200 million

(1) Mark-to-market rounded to the nearest $5 million.

2012 2Q Earnings Release Slides

Mark-to-market

value

hedges

million)

(1)

Additional 2012 ExGen Modeling

P&L Item

2012

Stub

(1)

Estimate

2012

Full-Year

(2)

Estimate

O&M

(3)

$4,000M

$4,250M

Taxes Other Than Income (TOTI)

$300M

Depreciation & Amortization

(4)

$650M

$700M

Interest Expense

$300M

$350M

2012 2Q Earnings Release Slides

Stub period represents estimates for March 12 – December 31, 2012 and is reflected as part of ExGen’s 2012 earnings guidance

Full-year estimates provided for modeling purposes.

ExGen O&M does not include CENG O&M of ~$350M in the stub estimate. CENG O&M will be reflected under “Equity earnings of unconsolidated affiliates” in the Income Statement. In

addition, we have removed the impact from O&M related to entities consolidated solely as a result of the application of FIN 46R. Our 2012 earnings guidance (prior or current) is not impacted

by this change to O&M since the application of FIN 46R does not impact net income.

ExGen D&A does not include CENG D&A of ~$100M in the stub estimate. CENG D&A will be reflected under ‘Equity earnings of unconsolidated affiliates” in the Income Statement.

(1)

(2)

(3)

(4)

ComEd Load Trends

4Q12

3Q12

2Q12

1Q12

4Q11

3Q11

2Q11

1Q11

Gross Metro Product

Residential

Large C&I

All Customer Classes

2011

2Q12 2012E

(3)

Average Customer Growth

0.4%

0.3%

Average Use-Per-Customer

(1.7)%

(3.0)%

(1.7)%

Total Residential

(1.3)%

(2.7)% (1.4)%

Small C&I

(0.8)%

(1.8)%

(0.2)%

Large C&I

0.6%

0.4%

(0.4)%

All Customer Classes

(0.5)%

(1.3)%

(0.6)%

Weather-Normalized Electric Load Year-over-Year

Key Economic Indicators

Weather-Normalized Electric Load

(1)

Source: U.S. Dept. of Labor (June 2012) and Illinois

Department of Security (June 2012)

(2)

Source: Global Insight (May 2012)

(3)

Not adjusted for leap year

Chicago

U.S.

Unemployment

rate

(1)

8.6%

8.2%

2012 annualized growth in

gross

domestic/metro

product

(2)

1.7% 2.2%

2012 2Q Earnings Release Slides

-3%

-2%

-1%

Notes: C&I = Commercial & Industrial.

ComEd load activity impacts net income to the extent that it does not result in an ROE outside of the collar, which ensures that the earned ROE is within 0.5% of the allowed ROE.

PECO Load Trends

4Q12

3Q12

2Q12

1Q12

4Q11

3Q11

2Q11

1Q11

Large C&I

All Customer Classes

Gross Metro Product

Residential

Note: C&I = Commercial & Industrial

2011

2Q12 2012E

(3)

Average Customer Growth

0.3%

0.4%

0.5%

Average Use-Per-Customer

1.3%

(1.0)%

(2.1)%

Total Residential

1.7%

(0.7)% (1.7)%

Small C&I

(0.7)%

(1.9)%

(3.2)%

Large C&I

(3.3)%

(4.9)%

(1.8)%

All Customer Classes

(0.9)%

(2.7)%

(2.0)%

Weather-Normalized Electric Load Year-over-Year

Key Economic Indicators

Weather-Normalized Electric Load

(1)

Source:

U.S.

Dept.

Labor

(June

2012)

Dept

Labor

prelim.

data

(June

2012)

Philadelphia

(2)

Source: Global Insight (May 2012)

(3)

Not adjusted for leap year

Philadelphia

U.S.

Unemployment

rate

(1)

7.8%

8.2%

2012

annualized

growth

gross

domestic/metro

product

(2)

1.4%

2.2%

2012 2Q Earnings Release Slides

-8%

-6%

-4%

-2%

Sufficient Liquidity

(1)

Excludes commitments from Exelon’s Community and Minority Bank Credit Facility.

(2)

Available Capacity Under Facilities represents the unused commitments under the borrower’s credit agreements net of outstanding letters of credit and facility draws. The amount of commercial

paper outstanding does not reduce the available capacity under the credit agreements.

(3)

Includes Exelon Corporate’s $500M credit facility and legacy Constellation credit facilities assumed as part of the merger, letters of credit and commercial paper outstanding. Exelon will be

unwinding the $4B in credit facilities assumed from legacy Constellation over the remainder of the year.

(3)

($ in Millions)

Available Capacity Under Bank Facilities as of July 27, 2012

Exelon Corp, ExGen, PECO and BGE facilities will be amended and extended to

to align maturities of Exelon facilities and secure liquidity and pricing through 2017

2012 2Q Earnings Release Slides

Aggregate Bank Commitments

(1)

600

1,000

600

5,600

10,640

Outstanding Facility Draws

Outstanding Letters of Credit

(1)

(1,793)

(2,317)

Available Capacity Under Facilities

(2)

599

999

599

3,807

8,323

Outstanding Commercial Paper

(35)

(256)

(462)

Available Capacity Less Outstanding

Commercial Paper

564

743

599

3,807

7,861

ComEd Distribution Rate Case Update

2011 Formula Rate Filing (Docket # 11-0721 filed 11/8/11; rates eff. June 2012):

•

Based on 2010 calendar year costs and 2011 net plant additions

•

Supported $59M distribution revenue requirement reduction

•

10.05% ROE (2010 Treasury yield of 4.25% + 580 basis point risk premium)

ICC Final Order (issued 5/30/12):

•

$168M revenue requirement reduction; incremental reduction includes:

~$50M related to costs ICC determined should be recovered through

alternative

rate

recovery

tariffs

reflected

reconciliation

proceeding; primarily

delays timing of cash flows

~$35M reflects disallowance of return on pension asset

~$10M reflects incentive compensation related adjustments

~$15M reflects various adjustments for cash working capital, operating reserves

and other technical items

•

ComEd requested and the ICC granted expedited rehearing on the pension, interest

rate, and average rate base issues; Commission Final Order expected by Sept. 19.

2012 Formula Rate Filing (Docket # 12-0321 filed 4/30/12, rates eff. Jan 2013)

•

2012 plan year based on 2011 actual costs and 2012 net plant additions

9.71% ROE (2011 Treasury yield of 3.91% + 580 basis point risk premium)

•

Reconciled 2011 revenue requirements in effect to 2011 actual costs incurred

9.81%

ROE

(3.91%

plus

590

basis

point

risk

premium)

(1)

•

Initial filing supported $106M distribution revenue requirement increase relative to

Dec. 2012 rates as ComEd initially proposed. When factoring in 5/30/12 order for

#11-0721, ComEd proposed a $34M reduction

•

Received staff and intervener testimony on 7/17/12

–

Staff proposes an additional $35M reduction beyond ComEd’s filing

•

ICC order by year end; rates effective January 2013

Summary of Filings

2010

2011

2012

Costs used for filing

Plant additions used for filing

Formula rate filing

Rates in effect

2011

2012

2013

Costs used for filing

Plant additions used for filing

Formula rate filing

Rates in effect

(1) 590 basis point premium applies only to 2011 revenue reconciliation. All subsequent revenue reconciliations will assume a 580 basis point premium.

2012 2Q Earnings Release Slides

ComEd Operating EPS Contribution

Key

Drivers

–

2Q12

vs.

2Q11

(1)

Impacts of the 2012 distribution formula

rate order under the Energy Infrastructure

Modernization Act: $(0.07)

Share differential: $(0.04)

One-time impacts of the 2011 distribution

rate case order: $(0.03)

Weather: $0.01

2Q12

Actual

Normal

Heating Degree-Days 823

544 765

Cooling Degree-Days 237

423 218

2Q11

$0.26

$0.15

$0.17

$0.05

YTD

2012

2011

2012 2Q Earnings Release Slides

(1)

Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

2Q GAAP EPS Reconciliation

Three Months Ended June 30, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.47

$0.05

$0.10

$0.02

$(0.02)

$0.61

Mark-to-market impact of economic hedging activities

0.14

0.00

0.15

Unrealized losses related to nuclear decommissioning trust funds

(0.02)

Plant retirements and divestitures

0.00

Constellation merger and integration costs

(0.07)

(0.00)

(0.01)

(0.08)

Amortization of commodity contract intangibles

(0.33)

Amortization of the fair value of certain debt

0.00

Reassessment of state deferred income taxes

0.00

2Q 2012 GAAP Earnings (Loss) Per Share

$0.19

$0.05

$0.09

$0.01

$(0.02)

$0.33

NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

Three Months Ended June 30, 2011

ExGen

ComEd

PECO

Other

Exelon

2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.79

$0.15

$0.13

$(0.01)

$1.05

Mark-to-market impact of economic hedging activities

(0.12)

Unrealized gains related to nuclear decommissioning trust funds

0.01

Plant retirements and divestitures

(0.02)

Recovery of costs pursuant to the 2011 distribution rate case order

0.03

Constellation merger and integration costs

(0.02)

2Q 2011 GAAP Earnings (Loss) Per Share

$0.67

$0.17

$0.03

$(0.03)

$0.93

2012 2Q Earnings Release Slides

YTD GAAP EPS Reconciliation

NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

Six Months Ended June 30, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.03

$0.17

$0.23

$0.04

$(0.03)

$1.44

Mark-to-market impact of economic hedging activities

0.20

0.01

0.21

Unrealized gains related to nuclear decommissioning trust funds

0.02

Plant retirements and divestitures

(0.01)

Constellation merger and integration costs

(0.13)

(0.00)

(0.01)

(0.00)

(0.09)

(0.23)

Maryland commitments

(0.03)

(0.11)

(0.16)

(0.29)

Amortization of commodity contract intangibles

(0.46)

FERC settlement

(0.22)

Reassessment of state deferred income taxes

0.02

0.14

0.16

Amortization of the fair value of certain debt

0.00

Other acquisition costs

(0.00)

YTD 2012 GAAP Earnings (Loss) Per Share

$0.43

$0.17

$0.22

$(0.07)

$(0.13)

$0.62

Six Months Ended June 30, 2011

ExGen

ComEd

PECO

Other

Exelon

2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.69

$0.26

$0.32

$(0.04)

$2.22

Mark-to-market impact of economic hedging activities

(0.25)

Unrealized gains related to nuclear decommissioning trust funds

0.04

Plant retirements and divestitures

(0.04)

Non-cash charge resulting from health care legislation

(0.03)

(0.01)

(0.04)

Recovery of costs pursuant to the 2011 distribution rate case order

0.03

Constellation merger and integration costs

(0.02)

YTD 2011 GAAP Earnings (Loss) Per Share

$1.41

$0.28

$0.26

$(0.07)

$1.94

2012 2Q Earnings Release Slides

GAAP to Operating Adjustments

•

Exelon’s 2012 adjusted (non-GAAP) operating earnings outlook excludes the earnings effects of the

following:

Mark-to-market adjustments from economic hedging activities

Unrealized gains and losses from nuclear decommissioning trust fund investments to the extent not

offset by contractual accounting as described in the notes to the consolidated financial statements

Financial impacts associated with the planned retirement of fossil generating units

Certain costs related to the Constellation merger and integration initiatives

Costs incurred as part of Maryland commitments in connection with the merger

Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at

the merger date

Costs incurred as part of a March 2012 settlement with the Federal Energy Regulatory Commission

(FERC) related to Constellation’s prior period hedging and risk management transactions

Revenues and operating expenses related to three generation facilities required to be sold within 180

days of the merger

Non-cash benefit associated with a change in state deferred tax rates resulting from a reassessment of

anticipated apportionment of Exelon’s deferred taxes as a result of the merger

Non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in

2013

Certain costs incurred associated with other acquisitions

Significant impairments of assets, including goodwill

Other unusual items

Significant changes to GAAP

•

Operating

earnings

guidance

assumes

normal

weather

for

remainder

the

year

2012 2Q Earnings Release Slides