Commonwealth Edison 8K Reaffirms Full Year Operating Earnings Guidance Range | SEC 26 Oct 11

Earnings Conference Call

Quarter 2011

October 26, 2011

Exhibit 99.2

Cautionary Statements Regarding

Forward-Looking Information

Except for the historical information contained herein, certain of the matters discussed in this communication constitute “forward-looking

statements” within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934, both as amended by the Private

Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,”

“believe,” “target,” “forecast,” and words and terms of similar substance used in connection with any discussion of future plans, actions,

or events identify forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding

benefits of the proposed merger of Exelon Corporation (Exelon) and Constellation Energy Group, Inc. (Constellation), integration plans

and expected synergies, the expected timing of completion of the transaction, anticipated future financial and operating performance

and results, including estimates for growth. These statements are based on the current expectations of management of Exelon and

Constellation, as applicable. There are a number of risks and uncertainties that could cause actual results to differ materially from the

forward-looking statements included in this communication regarding the proposed merger. For example, (1) the companies may be

unable to obtain shareholder approvals required for the merger; (2) the companies may be unable to obtain regulatory approvals

required for the merger, or required regulatory approvals may delay the merger or result in the imposition of conditions that could have

a material adverse effect on the combined company or cause the companies to abandon the merger; (3) conditions to the closing of the

merger may not be satisfied; (4) an unsolicited offer of another company to acquire assets or capital stock of Exelon or Constellation

could interfere with the merger; (5) problems may arise in successfully integrating the businesses of the companies, which may result in

the combined company not operating as effectively and efficiently as expected; (6) the combined company may be unable to achieve

cost-cutting synergies or it may take longer than expected to achieve those synergies; (7) the merger may involve unexpected costs,

unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different from the companies’ expectations;

(8) the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; (9) the businesses

of the companies may suffer as a result of uncertainty surrounding the merger; (10) the companies may not realize the values expected

to be obtained for properties expected or required to be divested; (11) the industry may be subject to future regulatory or legislative

actions that could adversely affect the companies; and (12) the companies may be adversely affected by other economic, business,

and/or competitive factors. Other unknown or unpredictable factors could also have material adverse effects on future results,

performance or achievements of Exelon, Constellation or the combined company.

Cautionary Statements Regarding

Forward-Looking Information (Continued)

Discussions of some of these other important factors and assumptions are contained in Exelon’s and Constellation’s respective

filings with the Securities and Exchange Commission (SEC), and available at the SEC’s website at www.sec.gov, including:

(1) Exelon’s 2010 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) Exelon’s

Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 (to be filed on October 26, 2011) in (a) Part II,

Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of

Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 13;

(3) Constellation’s 2010 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;

and (4) Constellation’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 in (a) Part II, Other Information,

ITEM 1A. Risk Factors and ITEM 5. Other Information, (b) Part I, Financial Information, ITEM 2. Management’s Discussion and

Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Notes

to Consolidated Financial Statements, Commitments and Contingencies. These risks, as well as other risks associated with the

proposed merger, are more fully discussed in the definitive joint proxy statement/prospectus included in the Registration Statement

on Form S-4 that Exelon filed with the SEC and that the SEC declared effective on October 11, 2011 in connection with the proposed

merger. In light of these risks, uncertainties, assumptions and factors, the forward-looking events discussed in this communication

may not occur. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the

date of this communication. Neither Exelon nor Constellation undertake any obligation to publicly release any revision to its forward-

looking statements to reflect events or circumstances after the date of this communication.

In connection with the proposed merger between Exelon and Constellation, Exelon filed with the SEC a Registration Statement on

Form S-4 that included the definitive joint proxy statement/prospectus. The Registration Statement was declared effective by the

SEC on October 11, 2011. Exelon and Constellation mailed the definitive joint proxy statement/prospectus to their respective security

holders on or about October 12, 2011. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE DEFINITIVE JOINT

PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, BECAUSE THEY

CONTAIN IMPORTANT INFORMATION about Exelon, Constellation and the proposed merger. Investors and security holders may

obtain copies of all documents filed with the SEC free of charge at the SEC's website, www.sec.gov. In addition, a copy of the

definitive joint proxy statement/prospectus may be obtained free of charge from Exelon Corporation, Investor Relations, 10 South

Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680-5398, or from Constellation Energy Group, Inc., Investor Relations, 100

Constellation Way, Suite 600C, Baltimore, MD 21202.

Additional Information and Where to Find it

2011 Operating Earnings Guidance

3Q 2011 operating earnings of

$1.12 per share

•

Exceeded guidance range of $1.00 -

$1.10 per share for the quarter

•

Continued operational excellence at

Exelon Nuclear with a 95.8%

capacity factor

•

Texas contributed $0.10 per share to

third quarter earnings

•

$(0.08) per share of incremental

storm costs at ComEd and PECO

compared to 3Q 2010

Reaffirming

operating

earnings

guidance

for

2011

$4.05

$4.25/share

(1)

$4.05 -

$4.25

$2.95 -

$3.10

$0.55 -

$0.65

$0.50 -

$0.60

$1.12

$0.79

$0.16

$0.17

$1.05

$0.79

$0.13

$0.15

$1.17

$0.90

$0.19

$0.11

HoldCo

ExGen

PECO

ComEd

Actual

2011

Guidance

(1)

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

(2)

Earnings guidance for OpCos may not add up to consolidated EPS guidance.

Exelon Texas Performance in Q3

(1)

Includes ERCOT generation from LaPorte, Wolf Hollow, Frontier, Handley and Mountain Creek. PPAs or tolls sold by Exelon are excluded from both generation and capacity.

Intermediate

2,210

Peaking

1,262

ERCOT fossil capacity ~ 3,472 MW

Our Texas generation assets are well positioned from a location and dispatch standpoint to take

advantage of price volatility

Exelon’s portfolio management approach in Texas utilized a mix of forward and spot sales based on

its market views to capture value

2,000

2,600

2,500

2,400

2,300

2,200

2,100

Q3 2011

$107

2,403

Q3 2010

$49

ERCOT North Real Time On Peak Average ($/MWh)

Exelon ERCOT Total Generation

Exelon’s exceptional financial performance in Texas is a result of increased

generation and our ability to capture value through the hedging program

ERCOT Generation and On Peak Power Prices

2011

vs.

2010

(1)

ERCOT Fossil Generation Capacity

by Type (MW)

(1)

1,998

+20%

On Track for Merger Close in Early 2012

New York PSC

FERC

January 5, 2012

Statutory deadline

Shareholder vote

November 17, 2011

Maryland PSC

SEC

NRC

Texas PUC

Secured approval from Texas PUC on August 3, 2011

DOJ

Approvals

Record Date

October 7, 2011

Joint proxy statement declared effective

October 11, 2011

Rebuttal testimony filed

October 12, 2011

Evidentiary hearings begin

October 31, 2011

FERC order expected by

November 16, 2011

Filed merger approval application related filings on

May 20, 2011. Settlement agreement filed with PJM

Market Monitor on October 11, 2011

Filed for indirect transfer of Constellation Energy licenses on May 12, 2011

Submitted HSR filing on May 31, 2011 for review under U.S. antitrust laws and certified

compliance with second request

2012

2011

Regulatory proceedings are progressing as planned and we are on

track to

close in early 2012

Expect decision in Q4 2011

Note : On September 26

2011, the Department of Public Utilities in Massachusetts concluded that it does not have

jurisdiction over the proposed transaction between Exelon and Constellation.

-400

-300

-200

-100

100

200

300

400

2015E

2014E

2013E

2012E

2011E

Antelope Valley Solar Ranch One (AVSR 1)

(1) Based on alternating current (AC).

Net Equity Cash Flows

($ millions)

Equity Payback

Cumulative Equity Cash Flows

Annual Equity Cash Flows

230-MW

(1)

solar

photovoltaic

(PV) facility

in Los Angeles County

First portion of plant to come on line in

October 2012; fully operational in 2013

25-year PPA with Pacific Gas & Electric

ensures certainty in cash flows

Summary

Financials

This investment diversifies ExGen’s portfolio by expanding to a new market,

securing

stable

cash

flows

and

increasing

renewable

energy

under

our

control

All-in cost of up to $1.36B; up to $646M of a non-recourse loan guaranteed by U.S. Department of

Energy’s Loan Programs Office

Exelon

invest

$713M

through

2013

–

funded

with

cash

and

short-term

debt

Free cash flow accretive beginning in 2013; EBITDA run-rate of ~$75M per year once fully operational

Expect to recover investment by 2015, largely driven by investment tax credits and other lax benefits

EPA Regulations Will Move Forward Despite

Delay Attempts

Proposed Rule issued in March 2011

•

Rule provides regulatory certainty to

industry

•

Stakeholder comments provided to EPA in

August 2011

Final Rule expected in December 2011

Compliance starting in late 2014/early 2015

Final Rule issued in July 2011

•

Rule provides template for future NOx

and SO2 reductions

Modest changes proposed in October 2011

•

Some state emission budgets modified

•

Assurance provision moved to 2014

Compliance start remains January 2012

Impact in PJM

~10 GW

Coal Retirements

Announced to date

~15 GW

EXC Estimate of

Coal Retirements

Cost of environmental upgrades and higher net

ACRs influenced supplier bidding behavior in the

PY 2014-2015 auction

~1,800 MW reduction in offered coal capacity vs.

prior year auction

~7,000 MW reduction in cleared coal capacity vs.

prior year auction

(2)

(1) Includes retirements announced by Duke, that will be part of

PJM starting in 2012.

(2) Expected coal retirements through 2015.

(1)

Air Toxics Rule

Cross-State Air Pollution Rule

PJM May 2011 RPM Auction

PJM Retirements

EPA and the industry are moving forward with implementation of forthcoming

environmental regulations

(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.

(2) Outage days exclude Salem.

Note: PPA = Power Purchase Agreement; T&D = Transmission and Distribution

$2.10

$0.75

$2.47

$0.79

YTD

2011

2010

Outage Days

(2)

3Q10

3Q11

Refueling

Non-refueling

Higher margins due to expiration of the

PECO PPA: $0.27

Favorable market/portfolio conditions in the

South: $0.10

Unfavorable capacity pricing: $(0.14)

Higher O&M costs, including planned

nuclear refueling outages: $(0.08)

Higher income tax due to reduced

manufacturing deduction as a result of T&D

repairs: $(0.04)

Higher nuclear fuel costs: $(0.02)

Higher depreciation expense: $(0.02)

Key Drivers –

3Q11 vs. 3Q10

(1)

Exelon Generation

Operating EPS Contribution

Exelon Generation Hedging Program

Exelon

continued

make

sales

during

capture

higher

power

prices

driven

by expanding heat rates and environmental rules

$50.00

$49.00

$48.00

$47.00

$46.00

$45.00

$37.00

$36.00

$32.00

$34.00

$33.00

$35.00

$31.00

$30.00

9/18

8/28

8/7

7/17

6/26

6/5

5/15

4/24

4/1

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2013

2012

2011

NI Hub ATC 2013

NI Hub ATC 2012

West Hub ATC 2013

West Hub ATC 2012

Underlying

Options

Ratable

98%

86%

57%

Physical Hedge %

PJM West Hub & NI Hub ATC Prices

ComEd Operating EPS Contribution

(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.

3Q10

Actual

Normal

Heating Degree-Days 70 147 110

Cooling Degree-Days 854 785 624

3Q11

Increased storm costs: $(0.06)

Electric distribution rates: $0.04

Key Drivers –

3Q11 vs. 3Q10

(1)

YTD

2011

2010

$0.55

$0.18

$0.43

$0.17

(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.

Note: CTC = Competitive Transition Charge; T&D = Transmission and Distribution

$0.51

$0.19

$0.47

$0.16

YTD

2010

2011

3Q10

Actual Actual Normal

Heating Degree-Days 0 18 36

Cooling Degree-Days 1,212 1,109 939

3Q11

2010 CTC collections, net of amortization

expense: $(0.08)

Increased storm costs: $(0.02)

Electric and gas distribution rates: $0.03

Lower income tax due to T&D tax repairs

deduction: $0.04

PECO Operating EPS Contribution

Key Drivers –

3Q11 vs. 3Q10

(1)

2011 Projected Sources and Uses of Cash

(1)

Excludes counterparty collateral activity.

(2)

Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash flows used in investing activities other than capital expenditures.

(3)

Assumes 2011 dividend of $2.10/share. Dividends are subject to declaration by the Board of Directors.

(4)

Includes $375 million in Nuclear Uprates, $250 million for Exelon Wind spend and $200 million for Solar / Antelope Valley Solar Ranch One.

(5)

Represents new business, smart grid/smart meter investment and transmission growth projects.

(6)

Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo. PECO’s A/R Agreement was extended in accordance with its terms through August 31, 2012.

(7)

“Other”

includes proceeds from options and expected changes in short-term debt.

(8) Includes cash flow activity from Holding Company, eliminations, and other corporate entities.

($ millions)

Exelon

(8)

Beginning Cash Balance

(1)

$800

Cash Flow from Operations

(2)

800

725

3,450

4,850

CapEx (excluding Nuclear Fuel, Nuclear Uprates, Exelon

Wind, Utility Growth CapEx and Solar CapEx)

(750)

(350)

(850)

(2,000)

Nuclear Fuel

n/a

(1,050)

Dividend

(3)

(1,400)

Nuclear Uprates, Exelon Wind and Solar

(4)

n/a

(825)

Wolf Hollow Acquisition

n/a

(300)

Antelope Valley Solar Ranch One Acquisition

n/a

(75)

Utility Growth CapEx

(5)

(275)

(125)

n/a

(400)

Net Financing (excluding Dividend):

Debt Issuances

(6)

1,200

Federal Financing Bank Loan

n/a

125

Planned Debt Retirements

(550)

(250)

(800)

Other

(7)

(75)

150

275

Ending Cash Balance

(1)

$400

Investment strategy achieved positive 2011 YTD

returns in a very challenging market environment due

to effectiveness of asset allocations and hedging

strategy :

•

Diversified asset allocation

•

Liability hedge

•

Pension plans are 83% funded as of September 30,

2011

•

Anticipate no substantial changes to contribution plan

S&P 500

Exelon

Pension

Fund Assets

-8.7%

5.3%

Pension Funds Performance

2011 YTD Returns at 9/30/2011

Decreased equity investments and

increased investment in fixed income

securities and alternative investments

The liability hedge has offset more than

50% of the pension liability increase caused

by lower interest rates

Exelon’s pension investment strategy has effectively dampened the volatility

of plan assets and plan funded status

Exelon Generation Hedging Disclosures

(as of September 30, 2011)

Important Information

The following slides are intended to provide additional information regarding the hedging

program at Exelon Generation and to serve as an aid for the purposes of modeling Exelon

Generation’s gross margin (operating revenues less purchased power and fuel expense). The

information on the following slides is not intended to represent earnings guidance or a forecast

of future events. In fact, many of the factors that ultimately will determine Exelon Generation’s

actual gross margin are based upon highly variable market factors outside of our control. The

information on the following slides is as of September 30, 2011. We update this information on a

quarterly basis.

Certain information on the following slides is based upon an internal simulation model that

incorporates assumptions regarding future market conditions, including power and commodity

prices, heat rates, and demand conditions, in addition to operating performance and dispatch

characteristics of our generating fleet. Our simulation model and the assumptions therein are

subject to change. For example, actual market conditions and the dispatch profile of our

generation fleet in future periods will likely differ – and may differ significantly – from the

assumptions underlying the simulation results included in the slides. In addition, the forward-

looking information included in the following slides will likely change over time due to continued

refinement of our simulation model and changes in our views on future market conditions.

Power Team utilizes several product types

and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider: financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

Consider market, credit, operational risk

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio

–

sell

what

own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

Percentage of Expected

Generation Hedged

•

How many equivalent MW have been

hedged at forward market prices; all hedge

products used are converted to an

equivalent average MW volume

•

Takes ALL

hedges into account whether

they are power sales or financial products

Equivalent MWs Sold

Expected Generation

Our normal practice is to hedge commodity risk on a ratable basis

over the three years leading to the spot market

•

Carry operational length into spot market to manage forced outage and load-following

risks

•

using

the

appropriate

product

mix,

expected

generation

hedged

approaches

the

mid-90s percentile as the delivery period approaches

•

Participation in larger procurement events, such as utility auctions, and some flexibility

in the timing of hedging may mean the hedge program is not strictly ratable from

quarter to quarter

Exelon Generation Hedging Program

2011

2012

2013

Estimated Open Gross Margin ($ millions)

(1)(2)

$5,600

$5,150

$5,900

Reference Prices

(1)

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)

ERCOT

North

ATC

Spark

Spread

($/MWh)

(3)

$4.11

$33.61

$45.07

$11.58

$4.24

$33.69

$45.46

$4.32

$4.80

$36.49

$48.45

$4.69

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on September 30, 2011 market conditions.

(2)

Gross margin is defined as operating revenues less fuel expense and purchased power expense, excluding the impact of decommissioning and other incidental revenues. Open

gross margin is estimated based upon an internal model that is developed by dispatching our expected generation to current market power and fossil fuel prices. Open gross margin

assumes

there

hedging

place

other

than

fixed

assumptions

for

capacity

cleared

the

RPM

auctions

and

uranium

costs

for

nuclear power plants. Open gross margin

contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity revenues and payments. The estimation of open

gross margin incorporates management discretion and modeling assumptions that are subject to change.

(3)

ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50 variable O&M.

2011

2012

2013

Expected Generation

(GWh)

(1)

166,300

169,600

166,100

Midwest

98,500

98,300

96,100

Mid-Atlantic

56,500

56,800

56,100

South & West

11,300

14,500

13,900

Percentage of Expected Generation Hedged

(2)

97-100%

85-88%

56-59%

Midwest

97-100

85-88

56-59

Mid-Atlantic

96-99

88-91

57-60

South & West

94-97

68-71

49-52

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$43.00

$41.00

$40.00

Mid-Atlantic

$56.50

$50.00

$50.50

South & West

$6.00

$1.00

$0.00

Generation Profile

(1)

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 12 refueling outages in 2011 and 10 refueling outages in 2012 and 2013 at Exelon-operated nuclear plants and Salem. Expected generation

assumes capacity factors of 93.1%, 93.5% and 93.3% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in 2012 and 2013 do

not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.

(2)

Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation. Includes all hedging products, such as wholesale and retail sales

of power, options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.

(3)

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.

Gross Margin Sensitivities with Existing Hedges ($ millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2011

$(5)

+/-

$10

2012

$65

$(30)

$70

$(50)

$40

$(35)

+/-

$45

2013

$305

$(265)

$210

$(205)

$145

$(140)

+/-

$50

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

Based on September 30, 2011 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.

$5,700

$6,200

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2011

2012

2013

$5,500

$6,900

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

95% case

5% case

$7,150

$7,050

(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 2012 and 2013 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 September 30, 2011.

Midwest

Mid-Atlantic

South & West

Step 1

Start

with

fleetwide

open

gross

margin

$5.60 billion

Step 2

Determine

the

mark-to-market

value

energy hedges

98,500GWh * 98% *

($43.00/MWh-$33.61MWh)

= $0.91 billion

56,500GWh * 97% *

($56.50/MWh-$45.07MWh)

= $0.63 billion

11,300GWh * 95% *

($6.00/MWh-$11.58MWh)

= $(0.06) billion

Step 3

Estimate

hedged

gross

margin

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:

MTM value of energy hedges:

Estimated hedged gross margin:

$5.60 billion

$0.91billion

$0.63billion

$(0.06)

billion

$7.08 billion

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

Market Price Snapshot

Forward NYMEX Natural Gas

PJM-West and Ni-Hub On-Peak Forward Prices

PJM-West and Ni-Hub Wrap Forward Prices

2012

$4.07

2013 $4.62

Rolling

months,

October

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Forward NYMEX Coal

2012

$74.25

2013

$77.25

2012 Ni-Hub $39.86

2013 Ni-Hub

$41.73

2013 PJM-West $53.74

2012 PJM-West

$51.14

2012 Ni-Hub

$26.79

2013 Ni-Hub

$28.24

2013 PJM-West

$40.19

2012 PJM-West

$38.43

4.0

4.5

5.0

5.5

6.0

6.5

7.0

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

10.2

10.4

10.6

10.8

11.0

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

Market Price Snapshot

2013

10.64

2012

10.89

2012

$43.23

2013

$48.04

2012

$3.97

2013

$4.51

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2012

$12.07

2013

$12.96

ERCOT North On Peak Spark Spread

Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder

Rolling

months,

October

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Appendix

Maryland PSC Review Schedule

(Case No. 9271)

Significant Events

Date of Event

Filing of Application

May 25, 2011

Intervention Deadline

June 24, 2011

Prehearing Conference

June 28, 2011

Filing of Staff, Office of People Counsel and Intervenor Testimony

September 16, 2011*

Filing of Rebuttal Testimony

October 12, 2011*

Filing of Surrebuttal Testimony

October 26, 2011

Status Conference

October 28, 2011

Evidentiary Hearings

October 31, 2011 -

November 18, 2011

Public Comment Hearings

November 29, December 1 &

December 5, 2011

Filing of Initial Briefs

December 1, 2011

Filing of Reply Briefs

December 15, 2011

Decision Deadline

January 5, 2012

* Initial

intervenor

testimony

with

respect

market

power

was

due

September

for

all

parties except for the

Independent Market

Monitor

and

rebuttal

testimony

with

respect

market

power

was

due

October

ComEd Load Trends

Weather-Normalized Load Year-over-Year

4Q11

3Q11

2Q11

1Q11

4Q10

3Q10

2Q10

1Q10

Gross Metro Product

Residential

Large C&I

All Customer Classes

Chicago

U.S.

Unemployment rate

(1)

2011 annualized growth in

gross

domestic/metro

product

(2)

Note: C&I = Commercial & Industrial

Key Economic Indicators

Weather-Normalized Load

2010

3Q11 2011E

Average Customer Growth

0.2%

0.5%

Average Use-Per-Customer

(1.4)%

(2.9)%

(1.7)%

Total Residential

(1.2)%

(2.4)% (1.2)%

Small C&I

(0.6)%

(2.2)%

(0.8)%

Large C&I

2.6%

0.1%

All Customer Classes

0.2%

(1.4)%

(0.6)%

(1)

Source: U.S. Dept. of Labor (September 2011) and Illinois

Department of Employment Security (September 2011)

(2) Source: Global Insight (August 2011)

-6%

-4%

-2%

9.1%

1.6%

10.5%

1.0%

PECO Load Trends

Weather-Normalized Load

Note: C&I = Commercial & Industrial

4Q11

3Q11

2Q11

1Q11

4Q10

3Q10

2Q10

1Q10

Gross Metro Product

Residential

Large C&I

All Customer Classes

Philadelphia

U.S.

Unemployment rate

(1)

9.0%

9.1%

2011 annualized growth in

gross domestic/metro product

(2)

0.7% 1.6%

2010

3Q11 2011E

Average Customer Growth

0.3%

Average Use-Per-Customer

0.3%

1.8%

1.9%

Total Residential

0.5%

2.1%

2.3%

Small C&I

(1.9)%

(3.2)%

(1.0)%

Large C&I

0.8%

(0.6)%

(2.7)%

All Customer Classes

0.1%

(0.1)%

(0.5)%

(1)

Source:

U.S.

Dept.

Labor

data

(September

2011)

–

U.S.

Dept.

Labor

prelim.

data

(August

2011)

–

Philadelphia

(2) Source: Global Insight (August 2011)

Weather-Normalized Load Year-over-Year

Key Economic Indicators

-6%

-4%

-2%

Sufficient Liquidity

($ millions)

Exelon

(3)

Aggregate Bank Commitments

(1)

$1,000

$600

$5,600

$7,700

Outstanding Facility Draws

Outstanding Letters of Credit

(1)

(122)

(131)

Available Capacity Under Facilities

(2)

999

599

5,478

7,569

Outstanding Commercial Paper

(28)

(356)

Available Capacity Less Outstanding

Commercial Paper

$999

$599

$5,450

$7,213

Available Capacity Under Bank Facilities as of October 21, 2011

Exelon bank facilities are largely untapped

(1) Excludes commitments from Exelon’s Community and Minority Bank Credit Facility

(2) Available Capacity Under Facilities represents the unused bank 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 Corp’s $500M credit facility, letters of credit and commercial paper outstanding.

Key Credit Metrics

(1)

See slide 32 for reconciliations to GAAP.

(2)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for

ComEd and PECO as of October 14, 2011.

(3)

Moody’s placed Exelon and Generation under review for a possible downgrade after the proposed

merger with Constellation Energy was announced. S&P and Fitch affirmed ratings of Exelon and

subsidiaries after the proposed merger was announced.

(4)

FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt obligations of

Exelon Corp. Range represents FFO/Debt to maintain current ratings at current business risk.

Moody’s Credit

Ratings

(2) (3)

S&P Credit

Ratings

(2) (3)

Fitch Credit

Ratings

(2) (3)

FFO / Debt

Target

Range

Exelon:

Baa1

BBB-

BBB+

ComEd:

Baa1

A-

BBB+

15-18%

PECO:

A-

15-18%

Generation:

BBB

BBB+

30-35%

(4)

Exelon

PECO

ComEd

2011E

2010A

2009A

Exelon

PECO

ComEd

2011E

2010A

2009A

Exelon

PECO

ComEd

2011E

2010A

2009A

FFO/Debt

(1)

Interest Coverage

(1)

Debt to Cap

(1)

40%

50%

60%

70%

80%

10X

12X

10%

20%

30%

40%

50%

ExGen/

Corp

ExGen/

Corp

ExGen/

Corp

Exelon Consolidated Metric Calculations and Ratios

(1)

Includes changes in A/R, Inventories, A/P and other accrued expenses, option premiums,

counterparty collateral and income taxes. Impact to FFO is opposite of impact to cash flow

(2)

Reflects retirement of variable interest entity + change in restricted cash

(3)

Reflects

net

capacity

payment

–

interest

PPAs

(using

weighted

average

cost

debt)

(4)

Reflects

employer

contributions

–

(service

costs

interest

costs

expected

return

assets),

net

taxes at 35%

(5)

Reflects

operating

lease

payments

–

interest

future

operating

lease

payments

(using

weighted average cost of debt)

(6)

Includes AFUDC / capitalized interest

(7)

Reflects PV of net capacity purchases (using weighted average cost of debt)

$ in millions

(8)

Reflects unfunded status, net of taxes at 35%

(9)

Reflects PV of minimum future operating lease payments (using weighted average cost of debt)

(10)

Nuclear decommissioning trust fund balance > asset retirement obligation. No debt imputed

(11)

Includes accrued interest less securities qualifying for hybrid treatment (50% debt / 50% equity)

(12)

Reflects interest on PV of minimum future operating lease payments (using weighted average cost

of debt)

(13)

Reflects interest on PV of PPAs (using weighted average cost of debt)

(14)

Includes

AFUDC

capitalized

interest

and

interest

securities

qualifying

for

hybrid

treatment

(50%

debt / 50% equity)

(15)

Includes interest on securities qualifying for hybrid treatment (50% debt / 50% equity)

FFO / Debt Coverage =

FFO (a)

Adjusted Debt (b)

FFO Interest Coverage =

FFO (a) + Adjusted Interest (c)

Adjusted Interest (c)

Adjusted Capitalization (e) =

Adjusted Debt (b) + Adjusted Equity (d)

32,606

Rating Agency Debt Ratio =

Adjusted Debt (b)

Adjusted Capitalization (e)

32%

7.2x

58%

2010A Credit Metrics

Exelon 2010 YE Adjustments

FFO Calculation

2010 YE

Source -

2010 Form 10-K (.pdf version)

Net Cash Flows provided by Operating Activities

5,244

Pg 159 -

Stmt. of Cash Flows

+/-

Change in Working Capital

644

Pg 159 -

Stmt. of Cash Flows

(1)

PECO Transition Bond Principal Paydown

(392)

Pg 174 -

Stmt. of Cash Flows

(2)

+ PPA Depreciation Adjustment

207

Pg 295 -

Commitments and Contingencies

(3)

+/-

Pension/OPEB Contribution Normalization

448

Pg 268-269 -

Post-retirement Benefits

(4)

+ Operating Lease Depreciation Adjustment

Pg 299 -

Commitments and Contingencies

(5)

+/-

Decommissioning activity

(143)

Pg 159-

Stmt. of Cash Flows

+/-

Other Minor FFO Adjustments

(6)

(54)

= FFO (a)

5,989

Debt Calculation

Long-term Debt (incl. Current Maturities and A/R agreement)

12,828

Pg 161 -

Balance Sheet

Short-term debt (incl. Notes Payable / Commercial Paper)

Pg 161 -

Balance Sheet

PECO Transition Bond Principal Paydown

N/A -

no debt outstanding at year-end

+ PPA Imputed Debt

1,680

295

Commitments

and

Contingencies

(7)

+ Pension/OPEB Imputed Debt

3,825

268

Post-retirement

benefits

(8)

+ Operating Lease Imputed Debt

428

299

Commitments

and

Contingencies

(9)

+ Asset Retirement Obligation

261-267

Asset

Retirement

Obligations

(10)

+/-

Other Minor Debt Equivalents

(11)

= Adjusted Debt (b)

18,845

Interest Calculation

Net Interest Expense

817

158

Statement

Operations

PECO Transition Bond Interest Expense

(22)

182

Significant

Accounting

Policies

+ Interest on Present Value (PV) of Operating Leases

299

Commitments

and

Contingencies

(12)

+ Interest on PV of Purchased Power Agreements (PPAs)

295

Commitments

and

Contingencies

(13)

+/-

Other Minor Interest Adjustments

(14)

= Adjusted Interest (c)

960

Equity Calculation

Total Equity

13,563

Pg 161 -

Balance Sheet

+ Preferred Securities of Subsidaries

Pg 161 -

Balance Sheet

+/-

Other Minor Equity Equivalents

(15)

111

= Adjusted Equity (d)

13,761

3Q 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.

Three Months Ended September 30, 2010

ExGen

ComEd

PECO

Other

Exelon

2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.75

$0.18

$0.19

$(0.01)

$1.11

2007 Illinois electric rate settlement

0.00

Mark-to-market impact of economic hedging activities

0.14

Unrealized gains related to nuclear decommissioning trust funds

0.09

Retirement of fossil generating units

(0.02)

Emission allowances impairment

(0.05)

3Q 2010 GAAP Earnings (Loss) Per Share

$0.91

$0. 18

$0.19

$(0.01)

$1.27

Three Months Ended September 30, 2011

ExGen

ComEd

PECO

Other

Exelon

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

$0.79

$0.17

$0.16

$0.01

$1.12

Mark-to-market impact of economic hedging activities

(0.08)

Unrealized losses related to nuclear decommissioning trust funds

(0.12)

Asset retirement obligation

(0.03)

0.00

(0.02)

Retirement of fossil generating units

(0.00)

Constellation acquisition costs

(0.00)

(0.01)

(0.02)

AVSR 1 acquisition costs

(0.01)

Wolf Hollow acquisition

0.03

3Q 2011 GAAP Earnings (Loss) Per Share

$0.58

$0.17

$0.16

$(0.00)

$0.90

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.

Nine Months Ended September 30, 2010

ExGen

ComEd

PECO

Other

Exelon

2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$2.10

$0.55

$0.51

$(0.06)

$3.10

2007 Illinois electric rate settlement

(0.01)

Mark-to-market impact of economic hedging activities

0.25

Unrealized gains related to nuclear decommissioning trust funds

0.04

Non-cash charge resulting from health care legislation

(0.04)

(0.02)

(0.10)

Non-cash remeasurement of income tax uncertainties

0.10

(0.16)

(0.03)

(0.01)

(0.10)

Retirement of fossil generating units

(0.05)

Emission allowances impairment

(0.05)

YTD 2010 GAAP Earnings (Loss) Per Share

$2.34

$0.37

$0.46

$(0.09)

$3.08

Nine Months Ended September 30, 2011

ExGen

ComEd

PECO

Other

Exelon

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

$2.47

$0.43

$0.47

$(0.03)

$3.34

Mark-to-market impact of economic hedging activities

(0.34)

Unrealized losses related to nuclear decommissioning trust funds

(0.07)

Retirement of fossil generating units

(0.04)

Asset retirement obligation

(0.03)

0.00

(0.02)

Constellation acquisition costs

(0.00)

(0.03)

(0.04)

AVSR 1 acquisition costs

(0.01)

Non-cash charge resulting from Illinois tax rate change legislation

(0.03)

(0.01)

(0.00)

(0.04)

Wolf Hollow acquisition

0.03

Recovery of costs pursuant to distribution rate case order

0.03

YTD 2011 GAAP Earnings (Loss) Per Share

$1.99

$0.44

$0.47

$(0.07)

$2.84

GAAP to Operating Adjustments

Exelon’s 2011 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

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation and asset retirement obligation estimates

•

Non-cash charge to remeasure deferred taxes at higher Illinois corporate tax rates

•

Financial impacts associated with the planned retirement of fossil generating units

•

One-time benefits reflecting ComEd’s 2011 distribution rate case order for the recovery of

previously

incurred

costs

the

2009

restructuring

plan

and

for

the

passage

Federal

health care legislation in 2010

•

Certain costs associated with Exelon’s acquisition of a wind portfolio (now known as Exelon

Wind) and AVSR 1, and Exelon’s proposed merger with Constellation

•

Non-cash

gain

purchase

connection

with

the

acquisition

Wolf

Hollow,

net

acquisition

costs

•

Non-cash charge remeasurement of income tax uncertainties

•

Non-cash charge resulting from passage of Federal health care legislation

•

Costs associated with the 2007 electric rate settlement agreement

•

Impairment of certain emission allowances

•

Other unusual items

•

Significant changes to GAAP

Operating

earnings

guidance

assumes

normal

weather

for

remainder

the

year

Commonwealth Edison 8-KReaffirms Full Year Operating Earnings Guidance Range