Commonwealth Edison 8K Regulation FD Disclosure | SEC 18 Sep 12

Bank of America Merrill Lynch

2012 Power and Gas Leaders

Conference

Bill Von Hoene

Senior EVP & Chief Strategy Officer

September

19th,

2012

Exhibit 99.1

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 Second Quarter 2012 Quarterly

Report on Form 10-Q 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 16; and (4) other factors discussed in filings with the

SEC

the

Registrants.

Readers

are

cautioned

not

place

undue

reliance

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.

Maintaining Strength Under Current Market Conditions

Our business decisions will be reflective of various considerations including

current market views, our internal fundamental views and the method to most

effectively create and return value to shareholders

Current forward power prices do not reflect anticipated recovery

•

Our internal market analysis forecasts $3/MWh upside at PJW-WHUB and $5/MWh

upside at NIHUB

•

Power

markets

not

reflect

tightening

the

supply

stack

from

coal retirements and

MATS compliance costs

Options are available to manage through the downturn

•

Currently reviewing plans to identify additional cost savings

•

Re-evaluating the timing and amount of uprate and renewable spend

Constellation: Electric Retail Business Strategy

Constellation

well

positioned

U.S.

market

where

capacity

available

for

competitive supply has room to grow

Total U.S. Power Market in 2012

Estimated Load ~ 3,700 TWh

(1)

(1) Source: EIA, KEMA and internal estimates.

Through retail and wholesale channels, Constellation

currently serves 170 TWhs, or approximately 5%, of total

U.S. power demand

Expected Total Competitive Market Growth

•

Underlying load growth

–

More than 1% annual load growth across the U.S.

•

Switched market expected to grow by approximately 11% in

C&I from 2011 to 2014

–

Existing markets: PA and OH

–

New markets: MI and AZ

•

Switched market expected to grow by approximately 15% in

residential from 2011 to 2014

Strategy to Grow

•

As existing markets grow and new markets open, serve new

customers

•

Improve market share in existing markets

•

Cross sell suite of products to existing customers

–

Create more value with customers

–

Utilize data and technology to expand product offerings

–

Achieve higher renewal rates

–

Distinguish our brand

•

Leverage operational efficiency

Eligible Non-Switched

16%

Eligible Switched

19%

Muni/Co-Op Market

Other

Ineligible

47%

18%

Exelon Utilities: Rate Case Progress

ComEd –

ICC Rehearing of 2011 Rate Case

•

ICC decision to rehear key elements of ComEd’s rate case is a step in the right direction

•

ComEd’s positions are solidly supported by existing legislation

•

Expect

ICC

Order

September

19th,

2012

•

Reversal of original ICC decision on the rehearing items could improve ComEd earnings by

~$0.10/share in 2012

BGE –

2012 Rate Case Filing

•

July

27th,

BGE

filed

electric

and

gas

rate

case

•

Expect

order

from

Maryland

PSC

February

2013

with

hearings

late

2012

•

Reflects a $204M increase in revenue requirements for both electric and gas

•

New

rates

expected

effect

late

February

2013

Exelon Utilities will deliver on operational and financial performance and utilize

existing rate making frameworks to earn a fair and reasonable return

BGE 2012 Rate Case Request

Electric

Gas

Total

Rate Base (reflects 13 month average)

$2.7 B

$1.0 B

$3.7 B

Rate of Return (10.5% ROE, 48.4% equity)

8.02%

Revenue Increase

$151 M

$53 M

$204M

Modifying the Minimum Offer Price Rules

Regulatory advocacy efforts are designed to improve the functioning of

competitive markets and protect against attempts to undermine price signals

Goal of Advocacy Efforts:

•

Protect competitive markets against attempts to undermine price signals and ensure

uneconomic generation does not distort market

•

Ensure

that

generators

receiving

subsidies

bid

their

appropriate

cost into the RPM auction

Concerns with Existing MOPR:

•

MOPR exemption process allows non-competitive supply to escape market power

mitigation, and fails to properly consider the value of out-of-market contracts

•

MOPR does not apply throughout RTO

•

MOPR floor applies only for one year and is set at 90% of the net cost of new entry

Path Forward:

•

Stakeholders reviewing methods to restructure MOPR

•

Any MOPR changes intended to be effective by PJM RPM 2016/17 auction

ERCOT Market Redesign

Exelon is well positioned in ERCOT for any of the new market constructs

Option

Overview

Easy to

Implement

Risk of

Reliability

Issues

Incentivizes

New Build

Energy-Only

with

Market-Based Reserve

Margin

Market determines reliability levels

and investment decisions on energy

prices alone (current state)

Yes

High

Energy-Only

with

Adders to Support a

Target Reserve Margin

Potential options include:

•

increasing the system offer caps

•

establishing an LMP adder

Yes

Medium

Energy-Only

with

Backstop Procurement

at Minimum Acceptable

Reliability

Allows for ERCOT to reactivate

mothballed capacity under RMR

agreements and procure emergency

demand resources at the price cap

Yes

Low

Mandatory

Resource

Adequacy Retirement

for LSEs

LSEs would be required to obtain

enough capacity to meet peak load

plus reserve margin or face penalty

Low

Yes

Resource

Adequacy

Requirement with

Centralized Forward

Capacity Market

•

PJM style capacity market

•

Forward capacity obligations are

procured on behalf of load 3-4 years

prior to delivery

Low

Yes

APPENDIX

Achievable Merger Synergies

•

Run rate gross margin opportunities of

$100M

(2)

starting in 2014

–

Matching load and generation

–

Retail growth opportunities

–

Portfolio optimization

$500

$305

$170

2015+

2014

2013

2012

Merger O&M synergies

Higher run rate

O&M synergies of

~$500M

•

Key drivers of run rate O&M synergies

include

–

Labor savings from corporate and

commercial consolidations

–

Reduced collateral requirements

–

IT systems consolidation

–

Supply chain savings

–

Other non-labor corporate synergies

Fully committed to achieving merger synergies

(1) O&M synergies include cost savings of ~$40M from lower liquidity requirements.

(2) Gross margin opportunities included in Total Gross Margin shown on slide 16.

Unregulated

75%

BGE

PECO

ComEd

11%

Gross Margin Opportunities ($M)

O&M

Savings

($M)

Run Rate O&M Synergies Breakdown

(1)

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% +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

•

ICC order by year end; rates effective January 2013

Summary of Filings

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

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

•

BGE Rate Case Overview

Rate Case Request

Electric

Gas

Docket #

9299

Test Year

October 2011 –

September 2012

Common Equity Ratio

48.4%

Requested Returns

ROE: 10.5%; ROR: 8.02%

Rate Base

$2.7B

$1B

Revenue Requirement Increase

$151M

$53M

Proposed Distribution Price

Increase as % of overall bill

Timeline

•10/12/12: Staff/Intervenors file direct testimony

•10/22/12: Update 8 months actual/4 month estimated test period data with actuals for last 4 months

(June-Sept. 2012)

•11/9/12: BGE and staff/intervenors file rebuttal testimony

•11/20/12: Staff/Intervenors and BGE file surrebuttal testimony

•12/3/12 –

12/18/12: Hearings

•1/11/13: Initial Briefs

•1/23/13: Reply Briefs

•2/23/13: Decision

•New rates are in effect shortly after the decision

Exelon Generation Fleet

Generation fleet uniquely diversified across regions and technologies

National Scope

•

Power generation assets in 20

states and Canada

Large and Diverse

•

diverse

generation

(1)

–

19 GW of Nuclear

–

10 GW of Gas

–

2 GW of Hydro

–

2 GW of Oil

–

1 GW of Coal

–

1 GW of Wind/Solar/Other

Clean

•

One of nation’s cleanest fleets

as measured by CO2, SO2 and

NOx intensity

(1)

Total owned generation capacity as of 4/30/2012 for legacy Exelon and legacy Constellation combined, net of physical market mitigation of 2,648 MW. Nuclear capacity reflects EXC

ownership of CENG and Salem. Coal capacity shown does not include Eddystone 2 (309 MW) retired on 6/1/2012.

Growing Clean Generation with Uprates

Station

Base Case

(3)

Max Potential

(3)

MW Onlne to

Date

Year of Full

Operation

by Unit

(1)

MW Recovery & Component Upgrades:

Quad Cities

2011 / 2010

Dresden

2013 / 2012

Peach Bottom

2011 / 2012

Dresden

106

110

2011 / 2013

Limerick

2012 / 2013

Peach Bottom

2014 / 2015

MUR:

LaSalle

2010 / 2011

Limerick

2011 / 2011

Braidwood

2012 / 2012

Byron

2012 / 2012

Quad Cities

2014 / 2014

Dresden

2014 / 2015

TMI

2014

EPU:

Clinton

2010

Peach Bottom

130

137

2015 / 2016

LaSalle

303

336

2018 / 2017

Limerick

306

340

2016 / 2017

Total

1,184

250

(1)

Includes deferral of LaSalle EPU.

(2)

In 2012 dollars. Overnight costs do not include financing costs or cost escalation.

(3)

Adjusted for actual MW’s achieved.

Estimated

IRR

Overnight

Cost

(2)

Approval

Process

Project

Duration

Megawatt

Recovery &

Component

Upgrades

11-14%

$860 M

Not

required

3-4 Years

MUR

(Measurement

Uncertainty

Recapture)

12-16%

$340 M

Straight

forward

approval

process

2-3 Years

EPU (Extended

Power Uprate)

9-13%

$2,260 M

Straight

forward

approval

process

3-6 Years

Executing uprate projects across our

geographically diverse nuclear fleet –

planned to add 85 MW’s in 2012

Nuclear Uprate Program Summary

(1)

1,287

Well Positioned for Clean Air Rules

A clean and diverse portfolio that is well positioned for environmental upside from

EPA regulations

(1)

Total owned generation capacity as of 4/30/2012 for legacy Exelon and legacy Constellation combined, net of physical market mitigation of 2,648 MW.

(2)

Nuclear capacity shown above reflects EXC ownership of CENG and Salem.

(3)

Coal capacity shown above does not include Eddystone 2 (309 MW) retired on 6/1/2012.

•

Largest clean merchant generation

portfolio in the nation

•

Less than 5% of combined generation

capacity will require capital expenditures

to comply with Air Toxic rules

•

Low-cost generation capacity provides

unparalleled leverage to rising commodity

prices

Total Generation Capacity

(1)

: ~ 34,660 MW

Hydro

Wind/Solar/Other

Gas

28%

Oil

Coal

(3)

Nuclear

(2)

55%

–

Approx. $200 million of CapEx, majority of

which is at Conemaugh (Exelon ownership

share ~31%)

Combined Company Portfolio

ExGen Disclosures

June 30, 2012

Margins move from new business to MtM of hedges over the

course of the year as sales are executed

Margins

move

from

“Non

power

new

business”

“Non

power executed”

over the course of the year

Gross margin linked to power production and sales

Open Gross

Margin

MtM of

Hedges

(2)

“Power”

New

Business

“Non Power”

Executed

“Non Power”

New Business

•Generation Gross

Margin at current

market prices,

including

capacity &

ancillary

revenues

•Exploration and

Production

•PPA Costs &

Revenues

•Provided at a

consolidated

level for all

regions (includes

hedged gross

margin for South,

West &

Canada

(1)

)

•MtM of power,

capacity and

ancillary hedges,

including cross

commodity, retail

and wholesale

load transactions

•Provided directly

at a consolidated

level for five

major regions.

Provided

indirectly for

each of the five

major regions via

EREP, reference

price, hedge %,

expected

generation

•Retail, Wholesale

planned gas sales

•Load Response

•Energy Efficiency

•GE Home

•Distributed Solar

•Portfolio

Management /

origination fuels new

business

•Proprietary trading

(3)

Gross margin from

other business activities

•Retail, Wholesale

planned electric

sales

•Portfolio

Management

new business

•Mid marketing

new business

•Retail, Wholesale

executed gas

sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

Components of Gross Margin Categories

(1) Hedged gross margins for South, West & Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region.

(2) MtM of hedges provided directly for the five larger regions. MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh.

(3) Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non Power” Executed category.

ExGen Disclosures

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 divested in 2012.

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.

Reference

Prices

(6)

Gross

Margin

Category

($ MM)

(1)

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

(1) Stub period calculated by excluding Jan 2012 thru mid-March 2012 for Constellation only. (2) Excludes Maryland assets divested in 2012. (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 assume

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

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

Gross Margin Sensitivities (With Existing Hedges)

(1,4)

2012

2013

2014

(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 divested in 2012. (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

(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 divested in 2012.

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)

Mark-to-market

value

hedges

million)

(1)

$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.

Commonwealth Edison 8-KRegulation FD Disclosure