Commonwealth Edison 8-K This presentation contains certain forward-looking statements within the meaning of the Private Securities

Edison Electric Institute

Financial Conference

November 12 –

13, 2012

Exhibit 99.1

2012 EEI Conference

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 Third 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 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. 

2

Financial Discipline & Flexibility

Financial

Action

Summary

Operational

Efficiencies

Cost

Management

•

Identified

additional

cost

savings

of

$50

million

per

year

beginning

in

2014,

in

addition

to

$500

million

merger

run

rate

synergies

(1)

Financial Tools

Financial

Flexibility

•

Optimized nuclear fuel inventory expenditures for cash savings

of

$400

million

from

2013-2016

(2)

(incorporated

in

2012

Analyst

Day CapEx schedule)

•

Investments in upstream gas business and utility scale solar

will be funded off-credit where possible

•

Evaluating project financing options for Exelon Wind portfolio

Defer Growth

Projects

•

Deferred ~$1.0B of nuclear uprate spend to align with

expected market recovery

•

LaSalle EPU 4-year deferral (additional two years since 2012 Analyst

Day announcement)

•

Limerick EPU 4-year deferral

Maintaining investment grade credit rating and dividend are our top priorities

(1)

Run rate target for O&M synergies from 2014 onwards.

2012 EEI Conference

(2) Includes reduction in nuclear fuel capital expenditures related to the 4 year deferral of LaSalle

and Limerick EPU projects.

Eliminated

undesignated

renewable

spend

of

~$1.3

billion

in

2013-2015

Note: EPU = Extended  Power Uprate.

3

Merger Checklist Update

Item

Target

Status

Highlights

O&M

Synergies

$500 million run rate

beginning

in

2014

(1)

•

On track to meet $170 million 2012 target and

$550

(2)

million run rate synergy target for 2014

•

Unregulated business comprises ~75% of target

Liquidity

Reduction

$4.2 billion year-end

2012

•

•

Gross Margin

Opportunities

$100

million

run

rate

(4)

•

On track to meet $100 million run rate synergies

starting in 2014

Asset Sales

Process

Execute sales agreement

by August 2012

•

Executed

sales

agreement

on

August

9 

for

~$400

million, plus tax benefits of $225 million; expect to

close transaction in 4Q 2012

BGE

File

rate

case

in

2

half

of 2012

•

Filed

rate

case

on

July

27

,

2012

and

expect

order

from MD PSC by February 2013

•

Filing reflects a $176M increase in revenue

requirements for both electric and gas

Commercial

Load Growth

~20% growth in volumes

from 2011 -

2014

•

Lower volume growth as a consequence of

significant competition but disciplined pricing

(3)

As of 9/30/2012.

(4)

(1)

Run rate target for O&M synergies from 2014 onwards.

(2)

We are successfully executing on the merger

2012 EEI Conference

nd

Includes additional $50M run rate cost savings disclosed in 3Q12 earnings materials.

Gross Margin opportunities on a run rate basis from 2014 onwards from

combining the two commercial portfolios.

Amended and extended existing $7 billion in credit 

facilities across all OpCos until 2017

th

th

On

track

to

eliminate

legacy

CEG

credit

facilities

of

$4.2 billion,

with

$2.7

billion

reduced

year

to

date

(3)

4

Exelon Generation: Load Serving Update

Retail Landscape

•

Expected load growth of 1% across the U.S.

•

Switched market expected to grow by

approximately 11% in C&I from 2011 to 2015

•

Switched market expected to grow by

approximately 22% in residential from 2011 to

2015

Strategy

•

Serve new customers as existing markets grow

and new markets open

-

Retail expected to grow at ~11% CAGR for 2011-2015

-

Wholesale expected to remain static starting in 2013

•

Improve market share in existing markets

•

Cross sell suite of products to existing

customers  to create higher retention

•

Leverage operational efficiency and national

footprint

Execution

•

Recently, the market has been impacted by

increased competition and aggressive pricing

•

Our disciplined approach to pricing has led to a

reduction in expected volumes and margins

•

Various channels to market are available to

optimize our generation

2012E

30-40%

60-70%

165

175

2013E

25-35%

185

2015E

2014E

20-30%

170

55-65%

35-45%

2011A

170

90

Wholesale Load

Total Contracted

Retail Load

Retail & Wholesale Load (TWh)

(1)

65-75%

70-80%

(2)

2012 EEI Conference

0

50

100

150

200

+9%

(1)

Numbers and percentages are rounded to the nearest 5.

(2)

Index

load

expected

to

be

20%

to

30%

of

total

forecasted

retail

load.

80

Exelon Generation:  Regulatory Priorities 

5

Exelon is heavily engaged in advocating positions that enhance the integrity of 

competitive markets and shareholder value

2012 EEI Conference

•

PJM

–

Restructured Minimum Offer Price Rules (MOPR)

-

Proposed

modifications

will

enhance

clarity

and

appropriately

apply minimum offer rule to subsidized projects

-

Modifications positioned to be implemented in advance of May

2013 PJM capacity auction

•

ERCOT

–

Market

Redesign

-

Forward capacity market remains a long-term option to assure

resource adequacy

-

In October, the PUCT voted to increase price caps (as an “interim”

step) from $4,500/MWh to:

•

$5,000/MWh (beginning June 1, 2013)

•

$7,000/MWh (beginning June 1, 2014)

•

$9,000/MWh (beginning June 1, 2015)

2012 EEI Conference

6

Executing Plan for Stronger Future

•Strong financial performance in 2012

•Successfully executing on the merger and meeting commitments

•Growing utility rate base in a prudent manner

•Expecting $3 -

$6/MWh upside in forward power prices as a result of plant

retirements, higher operating costs for compliance and a disconnect

between heat rates and gas prices

•Extracting value out of load serving business in a tough, competitive pricing

environment

•Anticipating positive enhancements in the regulatory arena, particularly with

the PJM MOPR

•Prioritizing capital allocation in order to maintain investment grade ratings

and provide time for a power market recovery to support the dividend

Financial Update

8

2012 Earnings Guidance

2012 Prior Guidance

(prior to 3Q earnings call)

$2.55 -

$2.85

(1)

$1.75 -

$1.95

$0.30 -

$0.40

$0.40 -

$0.50

$0.05 -

$0.15

HoldCo

ExGen

ComEd

PECO

BGE

(1)

2012 Revised Guidance

(disclosed at 3Q earnings call)

$2.75 -

$2.95

(1)

$1.85 -

$1.95

$0.45 -

$0.50

$0.40 -

$0.50

$0.05 -

$0.10

HoldCo

ExGen

ComEd

PECO

BGE

2012 EEI Conference 

2012 guidance includes Constellation Energy and BGE earnings for March 12 – December 31, 2012. Based on expected 2012 average outstanding shares of 819M. 

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

Key Drivers of Change

in Full-Year Guidance

•

Impact of ICC Rehearing

Order on ComEd’s earnings

•

Higher than expected RNF

at ExGen in 3Q 2012

•

Cost impact of Hurricane

Sandy

Cost Synergies Update

O&M

Savings

($M)

Run Rate O&M Synergies Breakdown

Run rate O&M

synergies of

~$550M

•

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

On track to achieving merger synergies

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

Unregulated

77%

BGE

7%

PECO

7%

ComEd

10%

9

2012 EEI Conference 

$305

$170

2015+

2014

$550

2013

2012

$50

$500

•

On

track

to

meet

$170M

O&M

synergies

target

for

2012

•

Completed

activities

to

enable

$275M

of

the

$550M

run-rate

synergies

to

date

(1)

Capital Expenditure Expectations

300

225

100

100

100

50

75

100

2015

2,450

950

975

325

2014

2,475

1,025

1,075

175

2013

2,750

975

925

575

2012

(1)

3,800

975

1,150

625

675

Base Capex

Nuclear Fuel

MD Commitments

Wind

Solar

Upstream Gas

Nuclear Uprates

2015

2,650

1,550

550

225

325

2014

2,525

1,375

550

225

375

2013

2,550

1,350

675

200

325

2012

(1)

2,200

1,400

400

200

200

Electric Distribution

Electric Transmission

Gas Delivery

Smart Grid/Smart Meter

(in $M)

(in $M)

(1) 2012 CapEx includes CEG and BGE from merger close date.

10

2012 EEI Conference 

Exelon Utilities

Exelon Generation

2012 Projected Sources and Uses of Cash

11

($ in Millions)

2012 EEI Conference 

(1)

Exelon beginning cash balance as of  12/31/11. Excludes counterparty collateral activity.

(2)

Includes $675 million of Constellation net collateral paid to counterparties prior to merger completion.

(3)

Cash Flow from Operations primarily includes net cash flows provided by operating activities, estimated proceeds from Maryland clean coal fleet divestitures and net cash flows used in

investing activities other than capital expenditures. 

(4)

Dividends are subject to declaration by the Board of Directors.

(5)

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 30, 2013.

(6)

“Other”

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

(7)

Includes cash flow activity from Holding Company, eliminations, and other corporate entities.  Represents Constellation cash flows from merger close through December 31, 2012.

Beginning

Cash

Balance

(1)

$550

Cash

acquired

from

Constellation

(2)

150

n/a

n/a

1,375

1,650

Cash

Flow

from

Operations

(3)

250

1,175

900

3,475

5,825

CapEx (excluding other items below):

(425)

(1,225)

(350)

(975)

(3,050)

Nuclear Fuel

n/a

n/a

n/a

(1,150)

(1,150)

Dividend

(4)

(1,725)

Nuclear Uprates

n/a

n/a

n/a

(300)

(300)

Wind

n/a

n/a

n/a

(625)

(625)

Solar

n/a

n/a

n/a

(675)

(675)

Upstream

n/a

n/a

n/a

(75)

(75)

Utility Smart Grid/Smart Meter

(75)

(50)

(75)

n/a

(200)

Net Financing (excluding Dividend):

Debt

Issuances

(5)

250

350

350

775

1,725

Debt Retirements

(175)

(450)

(375)

(125)

(1,125)

Project Finance/Federal Financing Bank

Loan

n/a

n/a

n/a

375

375

Other

(6)

--

25

(25)

--

(100)

Ending Cash Balance

(1)

$1,100

(7)

Credit Metrics Support Investment-Grade Ratings

Moody’s Credit

Ratings

(1)(2)

S&P Credit

Ratings

(1)(2)

Fitch Credit   

Ratings

(1)(2)

FFO / Debt

Target

Range

Exelon Corp

Baa2

BBB-

BBB+

ComEd

A3

A-

BBB+

15-18%

PECO

A1

A-

A

15-18%

BGE

Baa1

BBB+

BBB+

15-18%

Generation

Baa1

BBB

BBB+

25-27%

(3)

(1)

Current senior unsecured ratings for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd and PECO as of

November 8, 2012.

(2)

On November 8, 2012 Moody’s affirmed the ratings of Exelon and Generation with a negative outlook, concluding their review for a

possible

downgrade.

ComEd,

PECO

and

BGE

ratings

have

a

stable

outlook

at

Moody’s.

All

ratings

at

S&P

and

Fitch

have

a

stable

outlook.

(3)

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.

•

Committed to maintaining investment-grade ratings

•

2012-2015 credit metrics for Exelon Generation/HoldCo at or above target range

S&P target of 25-27% for Exelon Generation/HoldCo based on current market

conditions

12

2012 EEI Conference

Metrics sufficient to maintain investment-grade rating in 5-year financial plan

Credit Facility Update

•Achieving targeted facility reductions and associated synergies

$4.2B reduction in legacy CEG facilities (excluding BGE) on track by 12/31/12

$40M in annual cost savings beginning in 2013 ($35 million in 2012)

•

Amended and extended existing $7 billion in credit facilities for Exelon Corp, ExGen, PECO and

BGE

Anticipate ~$20M in savings over life of credit facilities

(1)

Includes Exelon Generation $5.3B revolver, legacy CEG $2.5B revolver, legacy CEG bilateral agreements of $1.7B, Exelon Corp $0.5B revolver and Exelon Generation $0.3B bilateral

agreement

$1.5

$6.1

$7.6

12/31/12

Termination of

legacy CEG revolver

9/30/12

Liquidity Reduced to Date

$2.7

Day 1 Merger Close

$10.3

(1)

Liquidity sizing supports commercial trading platform and provides ongoing

access to substantial liquidity

13

2012 EEI Conference 

Credit Facility (excluding utilities)

Pension and OPEB for Combined Company

Plan Design and Funding Strategy:

•

Plan funding strategies are summarized as follows:

For pension, contribute the minimum amounts required under ERISA, including amounts necessary to

avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006. For

Exelon’s

largest

pension

plan,

Exelon

expects

to

contribute

the

greater

of

$250M

or

the

minimum

amounts required under ERISA beginning annually in 2013.

OPEB plans are not subject to regulatory minimum contribution requirements. The contribution

strategy for Exelon’s OPEB plans is determined based on benefit claims paid and regulatory

implications (amounts deemed prudent to meet regulator expectations and best assure continued

recovery), while Constellation’s legacy plans are unfunded.

•

In July 2012, legislation was passed that provides pension funding relief for certain plans in the near term;

the impact of this legislation is included in the forecast and sensitivities.

•

During

the

third

quarter

of

2012,

Exelon

announced

certain

plan

design

changes

for

its

post-retirement

benefit plans. The changes are effective beginning in 2014 and their impact has been incorporated in the

forecast below.

Current Forecast:

•

The table below provides the combined company’s forecasted 2013 and 2014 pension and OPEB expense

and contributions.

(1)

Pension

and

OPEB

expenses

assume

an

~

24%

capitalization

rate.

(2)

Contributions shown in the table above are based on the current contribution policy for Exelon and Constellation plans.

(3)

Expected

return

on

assets

for

pension

is

7.50%

(2013)

and

7.0%

(2014).

Expected

return

on

assets

for

2013

-

2014

for

OPEB

is

6.68%.

Amounts

above

assume

Exelon

achieves

its

expected return on assets for pension and OPEB in 2012 of 7.50% and 6.68%, respectively.

(4)

Projected

12/31/12

pension

discount

rate

is

3.87%

(Exelon)

and

3.67%

(Constellation).

Projected

12/31/12

OPEB

discount

rate

is

3.96%

(Exelon)

and

3.69%

(Constellation).

14

2013

2014

(in $M)

Pre-Tax

Expense

(1)

Contributions

(2)

Pre-Tax

Expense

(1)

Contributions

(2)

Pension

(3)(4)

$430

$265

$455

$280

OPEB

(3)(4)

$240

$305

$225

$285

Total

$670

$570

$680

$565

2012 EEI Conference 

2013 Pension and OPEB Sensitivities

•

Tables below provide sensitivities for the combined company’s 2013 pension and OPEB expense and

contributions

(1)

under various discount rate and S&P 500 asset return scenarios

15

2013 Pension Sensitivity

(2) 

(in $M)

S&P Returns in Q4 2012

(3)

10%

0%

-10%

Discount Rate at

12/31/12

Pre-Tax

Expense

(1)

Contributions

(2)

Pre-Tax

Expense

(1)

Contributions

(2)

Pre-Tax

Expense

(1)

Contributions

(2)

Baseline Discount Rate

(4)

$400

$265

$420

$265

$440

$265

+50 bps

$365

$265

$385

$265

$405

$265

-

50bps

$445

$265

$465

$265

$485

$265

2013 OPEB Sensitivity

(2) 

(in $M)

S&P Returns in Q4 2012

(3)

10%

0%

-10%

Discount Rate at

12/31/12

Pre-Tax

Expense

(1)

Contributions

(2)

Pre-Tax

Expense

(1)

Contributions

(2)

Pre-Tax

Expense

(1)

Contributions

(2)

Baseline Discount Rate

(4)

$220

$275

$235

$295

$250

$315

+50 bps

$185

$235

$200

$255

$215

$275

-

50bps

$255

$320

$270

$340

$285

$360

2012 EEI Conference 

(1) Contributions shown in the table above are based on the current contribution policy for Exelon and Constellation plans and include the impact of pension funding relief.

(2) Pension and OPEB expenses assume an ~ 24% capitalization rate in 2013.

(3) Final 2012 asset return for pension and OPEB will depend in part on overall equity market returns for  Q4 2012 as proxied by the S&P 500.  The amounts above reflect

YTD S&P returns through September 30, 2012.

(4) The baseline discount rates reflect a projected 12/31/12 pension discount rate of 3.87% and 3.67% for Exelon and Constellation, respectively, and OPEB discount rate

of 3.96% and 3.69% for Exelon and Constellation, respectively.

2012 EEI Conference 

16

Additional 2012 ExGen and CENG Modeling

P&L Item

2012

Stub

(1)

Estimate

2012

Full-Year

(2)

Estimate

ExGen

Model

Inputs

(3)

O&M

(4)

$4,000M

$4,250M

Taxes Other Than Income (TOTI)

$300M

$300M

Depreciation

&

Amortization

(5)

$700M

$750M

Interest Expense

$300M

$350M

CENG Model Inputs

Gross Margin

Included in ExGen Disclosures

O&M

(6)

$350M

$450M

Depreciation

&

Amortization

(7)

$100M

$100M

(1)

(2)

(3)

(4)

(5)

(6)

(7)

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 amounts  for O&M, TOTI and Depreciation & Amortization exclude the impacts of CENG. CENG impact is reflected in “Equity earnings of 

unconsolidated affiliates” in the Income Statement.

ExGen O&M excludes decommissioning  costs and the impact from O&M related to entities consolidated solely as a result of the application of FIN 46R.

ExGen Depreciation & Amortization excludes the impact of decommissioning.

CENG O&M includes TOTI of $20M for stub estimate and $25M for full-year estimate.

CENG Depreciation & Amortization includes accretion expense.

Merger CapEx Synergies & Costs To Achieve

$100

2012

$55

2013

$70

$385

Capital

O&M

$70

$55

$35

2015+

2014

2013

2012

Run rate CapEx

synergies of

~$70M

2012 EEI Conference 

17

•

On track to achieve CapEx synergies in

2012 and beyond

•

Run rate CapEx synergies mainly driven

by:

Information Technology (IT) systems

consolidation

Supply Chain capital synergies

•

Costs to achieve excluded from

operating earnings

•

Key areas of costs to achieve:

IT systems consolidation

Transaction costs (banker, legal

costs, etc.)

Employee-related costs

CapEx Synergies ($M)

Costs to Achieve ($M)

Debt Maturity Schedule

600

2020

1,600

1,100

500

2019

2018

1,340

500

840

2017

1,166

700

425

41

2016

1,118

75

665

379

2015

1,685

550

260

800

75

2014

1,574

637

250

617

70

2013

1,019

300

252

467

2012

407

375

32

ExGen

(2)

PECO

ComEd

Exelon Corp

BGE

~64% of 2012 –

2016 debt maturities consist of regulated utility debt

(in $M)

Debt Maturity Profile

(1)

(2012-2020)

18

2012 EEI Conference 

(1)

As of 9/30/12

(2)

Includes $550M in 2015 and 2020 of inter-company loan agreements between Exelon and Exelon Generation that mirror the terms and amounts of the third party

obligations of Exelon.

GAAP to Operating Adjustments

19

2012 EEI Conference 

•

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 and the expected

sale in the fourth quarter of 2012 of three generating stations as required by the merger

Changes in decommissioning obligation estimates

Certain costs incurred 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

Changes

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

of

the

year

21

Commercial Business Overview

Scale, Scope and Flexibility Across the Energy Value Chain

Development and

exploration of natural gas

and liquids properties

12 assets in

seven

states

~295 BCFe of proved

Reserves

(1)

Leading merchant power

generation portfolio in the

U.S.

~35 GW of owned

generation capacity

(2)

Clean portfolio, well

positioned for evolving

regulatory requirements

Industry-leading wholesale

and retail sales and

marketing platform

~170 TWh of load and     

~420 BCF of gas delivered

(3)

~ 1 million residential and

100,000 business and

public sector customers

One of the largest and most

experienced Energy

Management providers

~1,800 MW of Load

Response under contract

(4)

Over 4,000

energy savings

projects implemented

across the U.S.

Benefiting from scale, scope and flexibility across the value chain

(1) Estimated

proved

reserves

as

of

12/31/2011.

Includes

Natural

Gas

(NG),

NG

Liquids

(NGL)

and

Oil.

NGL

and

Oil

are

converted

to

BCFe

at

a

ratio

of

6:1.

(2) Total owned generation capacity as of 9/30/2012, net of physical market mitigation (Brandon Shores, C.P. Crane and H.A. Wagner ~2,648 MW).

(3) Expected for 2012 as of 9/30/2012. Electric load and gas includes fixed price and indexed products. No stub period adjustment for legacy Constellation contribution.

(4) Load Response estimate as of 9/30/2012.

2012 EEI Conference

Upstream

Exploration

& Production

Power

Generation

Electric, Gas

Retail &

Wholesale

Beyond The

Meter

22

Commercial Business Transformation

PJM, wholesale marketing focus     

National, customer-facing business

Industry-leading retail platform and portfolio management expertise, combined

with one of the lowest cost and best managed generation fleets

Expand into

new markets

Cross sell new

products and

services

Benefit from

matching

generation and

load

Capital and

collateral

efficiency

Optimize

generation

assets/value

added forward

hedges

Leverage

relationships

with large

wholesale

customers

Monetize risk

management

expertise

~$8 billion in gross margin per year

Low-cost, geographically and technologically diverse generation fleet

Unparalleled upside to tightening energy and capacity markets 

2012 EEI Conference

Leading Merchant

Generation Fleet

Electric Load Serving

Business

Portfolio and Risk

Management

23

Generation and Load Match

We have already seen benefits across the portfolio this

summer:

•

Took advantage of large moves in summer heat 

rates  in ERCOT

—

Sold excess peaking generation at pre-

summer higher forward contract prices

—

Bought back below the cost of our units when

actual market heat rates dropped through

delivery

•

Sold load following products against our PJM

portfolio through our retail and wholesale load

channels

26

ERCOT

New England

14

30

New York

43

MidAtlantic

116

MidWest

118

Peaking

Intermediate

Baseload

Renewables

The combination establishes an industry-leading platform with regional

diversification of the generation fleet and customer-facing load business

Generation Capacity, Expected Generation and Expected Load 

2013 in TWh

(1,2)

Expected Load

Expected Generation

Generation capacity

2012 EEI Conference

15

11

6

12

17

14

17

18

48

75

25

97

South/West/

Canada

(1)

Owned and contracted generation capacity converted from MW to MWh assuming 100% capacity factor for all technology types, except for renewable capacity which is shown at estimated capacity factor.

(2)

Expected generation and load shown in the chart above will not tie out with load volume and ExGen disclosures. Load shown above does not include indexed products and generation reflects a net owned  

and contracted position. Estimates as of 9/30/2012.

Generation & Load Match: Competitive Advantage

Now able to sell closer to our generation

locations reducing risk associated with

locational pricing

—

Generation dispatched due to high summer

delivered heat rates and helped serve higher

loads from the hot weather

—

Minimum Offer Price Rules (MOPR) Update

24

PJM is proposing modifications to the MOPR to ensure uneconomic generation does not

distort market

•

Restructured MOPR

MOPR to apply to all new gas-fired and IGCC units in PJM, with limited exceptions

MOPR exemption to be available only to self-supply entities and competitive market

entrants

MOPR

floor

to

apply

for

three

years,

set

at

100%

of

the

net

cost

of

new

entry

•

Implementation/Timing

PJM currently reviewing restructured MOPR with all stakeholders

PJM expected to file for FERC approval by November 30, 2012

Exelon, other generators, and other stakeholders to support PJM’s filing

FERC approval expected in early February, 2013

PJM RPM

Auction

2015/16 –

May 2012

Stakeholder

Discussions -

Summer 2012

FERC Filing –

November  30, 2012

PJM RPM

Auction

2016/17 –

Spring 2013

FERC Ruling –

February 1, 2013

Note: IGCC = Integrated Gasification Combined Cycle.  FERC = Federal Energy Regulatory Commission.  RPM= Reliability Pricing Model.

2012 EEI Conference

Capacity Markets

25

2011/

2012

2012/

2013

2013/

2014

2014/

2015

2015/

2016

PJM

(3,8)

RTO 

Capacity

27,400

12,800

11,500

11,500

11,500

Price

$110

$16

$28

$126

$136

EMAAC

Capacity

(4)

9,100

9,100

9,100

9,100

Price

$140

$245

$137

$168

MAAC 

Capacity

2,600

2,700

2,700

2,700

Price

$133

$226

$137

$168

SWMAAC

Capacity

(5)

1,800

1,800

1,800

1,800

Price

$133

$226

$137

$168

Average Exelon

$110

$78

$142

$132

$153

New England

(6)

NEMA  

Capacity

2,100

2,100

2,100

2,100

2,100

Price

$104

(7)

$85

(7)

$85

(7)

$107

$114

SEMA

Capacity

35

35

35

35

35

Price

$104

(7)

$85

(7)

$85

(7)

$95

(7)

$104

(7)

Rest of Pool   Capacity

700

700

700

700

700

Price

$104

(7)

$85

(7)

$85

(7)

$95

(7)

$104

(7)

NYISO

(8)

Rest of Pool   Capacity

1,100

1,100

1,100

1,100

1,100

MISO

(9)

AMIL 

Capacity

1,100

1,100

1,100

1,100

1,100

2012 EEI Conference

PJM RPM Capacity Revenues

$-

$200

$400

$600

$800

$1,000

$1,200

$1,400

$-

$20

$40

$60

$80

$100

$120

$140

$160

2012

2013

2014

2015

$97

$105

$138

$141

Exelon

fleet

weighted

average

price

($/MWd)

(2)

Revenue ($MM)

(1)

(1)

Revenues reflect capacity cleared in base and incremental auctions and are for calendar years.

Revenue rounded to nearest $50M.

(2)

Weighted average $/MW-Day would apply if all owned generation cleared.

(3)

Reflects owned and contracted generation Installed Capacity (ICAP) adjusted for mid-year PPA roll

offs.

(4)

ICAP is net of Eddystone 1&2, Cromby 1&2 and Schuykill 1 (total ~ 1,100 MW).

(5)

ICAP is net of units to be divested (Brandon Shores, Wagner & Crane ~2,648 MW; Constellation

offered these units in PY11/12 - PY 15/16 auctions) and Riverside 6 CT (~115MW).

(6)

Reflects Qualified Summer Capacity including owned and contracted units.

(7)

Price is pro-rated for auctions that clear at the floor price and there is more capacity procured

than suggested by the reliability requirement.

(8)

Reflects 50.01% ownership in CENG.

(9)

Does not include wind under PPA.

RTO = Regional Transmission Organization, MAAC = Mid-Atlantic Area Council, EMAAC = Eastern

Mid-Atlantic Area Council, SWMAAC = South West Mid-Atlantic Area Council, NEMA = North East

Massachusetts; SEMA = North East Massachusetts, AMIL = Ameren Illinois.

26

Retail and Wholesale Gas

Retail Gas

(1)

(2011 –

2015 Bcf)

+18%

+14%

480

465

420

Contribution from ONEOK Energy

Marketing Company acquisition

(1)

Estimate as of 9/30/2012.

Portfolio Size:

•

420 Bcf expected to be served in 2012

•

Month by month renewals, with high renewal rates

Market Potential:

•

All states are competitive markets with an estimated

total market size of 15,000 Bcf, of which 7,000 Bcf is

currently switched

Growth Strategy and Objectives:

•

Looking to grow Northeast gas markets as well as

recently acquired ONEOK territories

Portfolio Size:

•

5 Bcf wholesale storage

•

300,000 MMBtu’s per day of term transport

•

Over 1 Bcf/day of plant supply

Growth Strategy and Objectives:

•

Expand wholesale presence to complement power

assets

•

Increase market knowledge of regional and basis

transport information to assist power forecasting

495

2012 EEI Conference

385

0

50

100

150

200

250

300

350

400

450

500

550

2011A

2012E

2013E

2014E

2015E

Retail Gas

Wholesale Gas

27

(1)

Oil/NGL conversion to gas is 6:1.

(2)

Constellation does not operate any of its properties.

Note: E&P =  Exploration and Production.

Upstream E&P Assets

Estimated Net Proved

Reserves

(as of 12/31/11)

Average Net Daily

Production

(Q2 2012)

295 Bcfe

60.3 MMcfe

•

Our Upstream Gas business achieves strong returns

(>12% IRR)

•

$150m (~50% utilized) Reserve Based Lending (RBL)

facility in place

—

Receives off-balance sheet treatment from S&P

•

Provides

valuable

market

intelligence

in

complex

natural gas markets

Forecasted Production

2012

2013

2014

2015

Net Daily Prod

(MMcfe / day)

55 -

70

55 -

70

60 -

75

60 -

75

2012 EEI Conference

Mississippi lime (OK)

Hunton dewatering (OK)

Woodford shale (OK)

Eagle Ford shale (TX)

Fayetteville shale (AR)

Haynesville shale (LA)

Floyd shale (AL)

Ohio shale (OH)

Woodbine shale (TX)

Trenton Black River (MI)

Current Portfolio Of Investments

Investment Thesis

28

Exelon Generation Disclosures

September 30, 2012

(As disclosed in Third Quarter 2012 Earnings Materials)

2012 EEI Conference

29

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

Exercising Market Views

Purely ratable

Actual hedge %

Market views on timing, product

allocation and regional spreads

reflected in actual hedge %

High End of Profit

Low End of Profit

% Hedged

Open Generation

with LT Contracts

Portfolio Management &

Optimization

Portfolio Management Over Time

Align Hedging & Financials

Establishing Minimum Hedge Targets

2012 EEI Conference

Credit Rating

Capital &

Operating

Expenditure

Dividend

Capital

Structure

Strategic Policy Alignment

•Aligns hedging program with financial

policies and financial outlook

•Establish minimum hedge targets to

meet financial objectives of the

company (dividend, investment-grade

credit rating)

•Hedge enough commodity risk to meet

future cash requirements under a stress

scenario

Three-Year Ratable Hedging

•Ensure stability in near-term cash

flows and earnings

•Disciplined approach to hedging

•Tenor aligns with customer

preferences and market liquidity

•Multiple channels to market that

allow us to maximize margins

•Large open position in outer years

to benefit from price upside

Bull / Bear Program

•Ability to exercise fundamental market

views to create value within the ratable

framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat rate

positions, options, etc.)

•Delivery locations, regional and zonal

spread relationships

30

Components of Gross Margin Categories

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”

to

“Non power executed”

over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

2012 EEI Conference

•Generation Gross

Margin at current

market prices,

including capacity &

ancillary revenues,

nuclear fuel

amortization and

fossils fuels expense

•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 electric

sales

•Portfolio

Management new

business

•Mid marketing new

business

•Retail, Wholesale 

executed gas sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

•Retail, Wholesale

planned gas sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

•Portfolio

Management /

origination fuels new

business

•Proprietary

trading

(3)

Open Gross

Margin

MtM of

Hedges

(2)

“Power”

New

Business

“Non Power”

Executed

“Non Power”

New Business

(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.

31

ExGen Disclosures 

2012 EEI Conference

Gross Margin Category ($M)

(1,2)

2012

(3)

2013

2014

2015

Open Gross Margin

(including South, West & Canada hedged GM)

(4,5)

$4,500

$5,750

$6,050

$6,200

Mark to Market of Hedges

(5,6)

$3,200

$1,350

$500

$250

Power New Business / To Go

$50

$500

$750

$950

Non-Power Margins Executed

$300

$150

$100

$50

Non-Power New Business / To Go

$100

$450

$500

$550

Total

Gross

Margin

$8,150

$8,200

$7,900

$8,000

Reference Prices

(7)

2012

2013

2014

2015

Henry Hub Natural Gas ($/MMbtu)

$2.77

$3.84

$4.18

$4.37

Midwest: NiHub ATC prices ($/MWh)

$28.95

$30.59

$31.34

$32.32

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

$33.93

$38.24

$39.44

$40.77

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$3.67

$8.37

$8.30

$7.15

New York: NY Zone A ($/MWh)

$30.85

$35.19

$35.98

$36.55

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

ALQN Gas, 7.5HR, $0.50 VOM

$6.72

$4.42

$3.79

$4.07

(4)

Excludes Maryland assets to be divested.

(5)

Includes CENG Joint Venture.

(6)

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

(7)

Based on September 30, 2012 market conditions.

(1)

Gross margin does not include revenue related to decommissioning, Exelon Nuclear Partners

and entities consolidated solely as a result of the application of FIN 46R.

(2)

Gross margin rounded to nearest $50M.

(3)

Stub period calculated by excluding Jan 2012 through mid-March 2012 for Constellation

only.

32

ExGen Disclosures

Generation and Hedges

2012

(1)

2013

2014

2015

Exp. Gen (GWh)

(4)

219,500

218,700

211,400

209,800

Midwest

100,700

97,400

97,500

99,000

Mid-Atlantic

(2,3)

71,800

75,000

72,200

71,800

ERCOT

19,900

18,500

16,900

15,800

New York

(3)

13,000

13,800

10,900

9,300

New England

14,100

14,000

13,900

13,900

% of Expected Generation Hedged

(5)

99-102%

88-91%

56-59%

21-24%

Midwest

99-102%

89-92%

56-59%

20-23%

Mid-Atlantic

(2,3)

99-102%

88-91%

57-60%

24-27%

ERCOT

96-99%

78-81%

53-56%

28-31%

New York

(3)

98-101%

92-95%

61-64%

15-18%

New England

97-100%

89-92%

51-54%

11-14%

Effective Realized Energy Price ($/MWh)

(6)

Midwest

$42.00

$38.00

$35.00

$34.50

Mid-Atlantic

(2,3)

$56.00

$48.00

$47.50

$50.50

ERCOT

7

$9.00

$7.50

$5.00

$5.00

New York

(3)

$44.00

$36.00

$35.00

$52.00

New England

(7)

$8.00

$7.00

$4.00

$5.00

2012 EEI Conference

(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 and 2015 at Exelon-operated nuclear plants and Salem but excludes CENG.  Expected generation assumes capacity

factors of 92.8%, 93.5%, 93.8%, and 93.3% in 2012, 2013, 2014 and 2015 at Exelon-operated nuclear plants excluding Salem and CENG. These estimates of expected generation in 2012,

2013, 2014 and 2015 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.

33

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges) 

(1, 4)

2012

2013

2014

2015

Henry Hub Natural Gas ($/MMbtu)

(2)

$(5)

$55

$400

$780

$25

$(15)

$(325)

$(700)

NiHub ATC Energy Price

$(5)

$40

$230

$390

$5

$(35)

$(230)

$(385)

PJM-W ATC Energy Price

(2)

$(5)

$50

$165

$295

$5

$(40)

$(160)

$(285)

NYPP Zone A ATC Energy Price

$5

$15

$35

$45

$(5)

$(15)

$(35)

$(45)

Nuclear Capacity Factor

(3)

+/-

1%

+/-

$10

+/-

$40

+/-

$45

+/-

$45

2012 EEI Conference

(1) Based on September 30, 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.

+ $1/MMbtu

-

$1/MMbtu

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

34

Exelon Generation Hedged Gross Margin Upside/Risk

$8,200

$8,100

$8,500

$7,850

$8,950

$7,150

2012 EEI Conference

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

11,000

2012

2013

2014

2015

$11,050

$6,350

(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, 2014 and 2015 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, 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

35

Illustrative Example of Modeling Exelon Generation             

2013 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New

England

New York

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$5.75 billion

(B)

Expected Generation (TWh)

97.4

75.0

18.5

14.0

13.8

(C)

Hedge % (assuming mid-point of range)

90.5%

89.5%

79.5%

90.5%

93.5%

(D=B*C)

Hedged Volume (TWh)

88.2

67.1

14.7

12.7

12.9

(E)

Effective Realized Energy Price ($/MWh)

$38.00

$48.00

$7.50

$7.00

$36.00

(F)

Reference Price ($/MWh)

$30.59

$38.24

$8.37

$4.42

$35.19

(G=E-F)

Difference ($/MWh)

$7.41

$9.76

($0.87)

$2.58

$0.81

(H=D*G)

Mark-to-market

value

of

hedges

($

million)

(1)

$655 million

$655 million

($15) million

$35 million

$10 million

(I=A+H)

Hedged Gross Margin ($ million)

$7,100 million

(J)

Power New Business / To Go ($ million)

$500 million

(K)

Non-Power Margins Executed ($ million)

$150 million

(L)

Non-

Power New Business / To Go ($ million)

$450 million

(N=I+J+K+L)

Total Gross Margin

$8,200 million

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

2012 EEI Conference

36

Constellation Energy Nuclear Group (CENG) Background

As a result of Exelon’s equity interest in CENG, CENG gross margins and earnings are reflected in ExGen disclosures

and

other

financial

statements.

The

following

is

information

related

to

PPA

contracts

between

CENG

and

3rd

parties and the PPA between CENG and its equity parents.

Calvert 1&2

NMP 1

NMP 2

(1)

Ginna

(2)

Ownership Interest

Total Plant Capacity

1,705 MW

620 MW

1,138 MW

581 MW

Ownership Split

100% CENG

100% CENG

82% CENG / 18% LIPA

100% CENG

ExGen Ownership (50.01% of CENG)

852.5 MW

310 MW

466.5 MW

290.5 MW

PPA structure (% output)

CENG Legacy PPA with Utilities

-

-

See footnote 1

90%

< June 2014

0%

> June 2014

CENG PPA with Parents

100%

100%

100%

10%

< June 2014

100%

> June 2014

CENG PPA with Parents

5 year

contract

extendable

at

end

of

each

year

for

additional

year

-

Market

based

pricing

and

monthly,

rolling

3

year

hedge

profile

(100%,

60%,

30%)

2012

2013

2014

2015

(%  of uncommitted output)

EDF Trading

15

15

15

N.A.

ExGen

85

85

85

N.A.

2012 EEI Conference

(1) Nine Mile Point 2 (NMP) has a revenue sharing agreement (via a call option type contract) on 80% of the output.

(2) Ginna Legacy PPA at $44/MWh; CENG PPA with parents (ExGen, EDF) at close to market prices and designed to maintain a monthly ratable profile for CENG.

37

Constellation Energy Nuclear Group (CENG) Background

2012 EEI Conference

ExGen Disclosures

Forward Estimates

•ExGen forward disclosures reflect the gross position that

accrues to ExGen from ownership interest in CENG and

PPA with CENG as of a certain date

•Open Gross Margin: Reflects proportionate share of

CENG revenues and fuel costs, market value of PPA less

PPA costs paid by ExGen to CENG

•MtM

of Hedges: Reflects MtM

of any hedges placed by

ExGen for managing position arising from ownership

interests or PPAs with CENG

•Expected Generation: Reflects proportionate ownership

in CENG and generation associated with PPA between

CENG and ExGen.

•Hedge Percentage: Reflects hedges placed by ExGen to

hedge exposure arising from CENG position (owned or

contracted)

•Effective Realized Energy Price: Reflects MtM

and

hedges from CENG position (owned or contracted)

Financial Statements

(10-Q, 10-K, Earnings Release tables)

Actuals

•ExGen actuals

reflect equity method accounting

treatment for ownership interest  in CENG and regular

treatment for PPA between ExGen and CENG.

•RnF:  Includes net PPA gross margin (revenues less

costs) between ExGen and CENG. CENG earnings or

gross margin are not included, and are instead shown

under “CENG equity earnings”

on the income statement.

•Total Supply: Includes only the generation corresponding

to the PPA between ExGen and CENG.

•Average Margins ($/MWh): Includes only margins

corresponding to PPA between ExGen and CENG as well

as any hedges placed by ExGen

Exelon Utilities

ComEd Distribution Rate Case Overview

2011

Formula

Rate

Filing

(Docket

#

11-0721

filed

11/8/11;

2010

test

year

costs,

2011

plant

additions,

rates

eff.

June

2012

–

Dec

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 reduction to revenue requirement; incremental reduction includes:

~$50M related to costs ICC determined should be recovered through alternative rate recovery tariffs or reflected in 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

ICC Re-hearing Order (issued 10/3/12) on pension asset, interest rate on reconciliation and average rate base

•

Granted $35M of prior disallowance related to pension, reflecting an updated total reduction to revenue requirement of $133M

Upheld the average rate base decision

Order also revised the decision on interest on reconciliation balances, granting a rate equal to the short term debt rate

•

ComEd filed a notice of appeal with the First Appellate Court on 10/4/12 and a motion to expedite on 10/10/12.  The motion to expedite was

denied, therefore, initial briefs are due on 12/13/12.

2012 Formula Rate Filing (Docket # 12-0321 filed 4/30/12, 2011 test year costs, 2012 projected plant additions, rates eff. Jan 2013 –

December 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)

•

When factoring in 5/30/12 Order and 10/3/12 Re-hearing Order for #11-0721, ComEd proposes a $74M increase to distribution revenue

requirement

•

Received staff and intervener direct testimony on 7/17/12 and rebuttal testimony on 9/11/12

•

ICC order by 12/26/12; 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.

39

2012 EEI Conference

40

BGE Rate Case (Updated to reflect 10/22/12 filing)

Rate

Case

Request

(1)

Electric

Gas

Docket #

9299

Test Year

October 2011 –

September 2012

Common Equity Ratio

48.4%

Requested Returns

ROE: 10.5%; ROR: 7.96%

Rate Base

$2.7B

$1B

Revenue Requirement Increase

$131M

$45M

Proposed Distribution Price

Increase as % of overall bill

4%

6%

Timeline

•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

2012 EEI Conference

Initial filing on 7/27/12 used 8 months of actuals and 4 months of projections for October 2011 – September 2012 time period and requested an ROR of 8.02%, electric 

revenue increase of $151M and gas revenue increase of $53M.  Rate base, equity ratio and ROE have not changed materially since the 7/27/12 filing.

(1)

41

ComEd Load

2012 EEI Conference

2012E

-0.3%

-0.2%

-0.6%

-0.3%

1.7%

2011

0.6%

-0.8%

-1.3%

-0.5%

1.4%

GMP

Large C&I

Small C&I

Residential

All Customers

Driver or

Indicator

2013 Outlook

Gross Metro

Product (GMP)

1.5% growth in GMP, which reflects a slow

growth economy

Employment

1.3% increase in total employment is expected

for 2013.

Manufacturing

Manufacturing employment is expected to grow

2.0% in 2013, which is consistent with the

growth in 2011 and 2012.

Households

Household formations is expected to increase

0.4% in 2013.  This is slightly better than the

0.3% growth expected for 2012.

Energy

Efficiency

Continued expansion of EE programs with ~ 1%

reduction in usage in 2013.

Notes: 2012 data is not adjusted for leap year.  Source of 2013 economic outlook data is Global Insight (July 2012).

Slow growth economy and energy efficiency initiatives will continue to impact

load growth

Weather-Normalized Load YoY Growth

Economic Forecast of Drivers that Influence Load

42

PECO Load

2012E

-2.4%

-3.5%

-2.0%

-2.4%

1.9%

2011

-3.3%

-0.7%

1.7%

-0.9%

0.5%

GMP

Large C&I

Small C&I

Residential

All Customers

Driver or

Indicator

2013 Outlook

Gross Metro

Product (GMP)

GMP projected to grow at 1.8% for

2013, vs. pre-recession average of

2.5%

Employment

Resident Employment outlook is

1.3% in 2013 vs. 1.0% in 2012

Manufacturing

Manufacturing employment is

expected to grow at 1.0%.

Philadelphia has had negative growth

from 2000 to 2011.

Households

Household growth is expected to be

0.3%, the same as the last three

years.

Energy

Efficiency

Energy Efficiency impact forecasted

to be  ~1% reduction in usage in

2013.

Improvements at oil refineries will be partially offset by on-going energy efficiency

initiatives

2012 EEI Conference

Notes: 2012 data is not adjusted for leap year.  Source of 2013 economic outlook data is Global Insight (July 2012).

Weather-Normalized Load YoY Growth

Economic Forecast of Drivers that Influence Load

43

BGE Load

2012E

-0.6%

-3.1%

-1.2%

-2.2%

1.7%

2011

2.0%

0.8%

-4.3%

-1.1%

1.0%

GMP

Large C&I

Small C&I

Residential

All Customers

Driver or

Indicator

2013 Outlook

Gross Metro

Product (GMP)

GMP is projected to grow at 1.5% for

2013.

Employment

1.0% growth projected. BGE’s

decoupled non-rate case revenue

growth is primarily driven by customer

growth.  The main driver for customer

growth is employment.

Manufacturing

Manufacturing employment is expected

to be fairly flat to 2012 levels in 2013

Personal Income

Projected to grow at 1.7%

Energy Efficiency

Continued expansion of EE programs

will offset any growth seen due to

improvements in economic conditions.

2013 is expected to be another transition year for the Baltimore

economy with

continued slow growth projected combined with the shutdown of RG

Steel

2012 EEI Conference

Notes: 2012 data is not adjusted for leap year.  Source of 2013 economic outlook data is Global Insight (July 2012).

Weather-Normalized Load YoY Growth

Economic Forecast of Drivers that Influence Load 

44

Exelon Utilities: Rate Base and ROE Targets

2012E

Long-Term Target

Equity Ratio

~49%

~53%

(4)

Earned ROE

4 -

5%

(5)

2012E

Long-Term Target

Equity Ratio

~45%

~53%

(2)

Earned ROE

8 -9%

Continued investment in Utilities will provide stable earnings growth

Based on 30-yr.

US Treasury

(3)

($ in billions)

$1.1

$0.7

$1.1

2012E

$5.1

$3.3

$0.7

$5.6

$3.6

2015E

$1.2

$0.8

$1.2

2013E

$5.2

$3.4

2014E

$5.5

$3.6

$0.7

Electric Distribution

Electric Transmission

Gas Delivery

$2.1

$7.2

$2.7

2014E

$8.6

$6.7

$2.5

2013E

$9.2

$6.4

$9.9

$6.1

2015E

$8.2

$2.2

2012E

Transmission

Distribution

$4.6

$2.8

$0.6

$4.1

$0.7

$1.0

$1.0

2013E

$2.7

2014E

$0.6

$0.9

$2.6

$4.3

2012E

$4.8

2015E

$1.0

$2.9

$0.8

Electric Distribution

Gas Delivery

Electric Transmission

=10%

(1)

ComEd distribution rate base represents an average and transmission rate base represents

end of year; PECO rate base represents end-of-year; and BGE rate base represents a trailing

13-month average.  Numbers may not add due to rounding.

(2)

Equity component for distribution rates will be the actual capital structure adjusted for

goodwill.

(3)

Earned ROE will reflect the weighted average of 11.5% allowed transmission ROE and

distribution ROE resulting from 30-year Treasury plus 580 basis points for each calendar year.

2012 EEI Conference

(4)

Per MDPSC merger commitment, BGE is precluded from paying dividends through 2014.

Per MDPSC orders, BGE cannot pay out a dividend to its parent company if said dividend

would cause BGE’s equity ratio to fall below 48%.

(5)

ROE

represents

full

year

of

2012

earnings

and

therefore

includes

activity

prior

to

the

merger close in March 2012.

(1)

2012E

Long-Term Target

Equity Ratio

~55%

~53%

Earned ROE

11.5 –

12.5%

=10%

45

Capital Expenditures

($ in millions)

2014E

$475

2015E

$50

$125

$50

$250

$575

$275

$150

2012E

$425

$50

$100

2013E

$525

$250

$125

$50

$100

$175

$100

$75

$75

Gas Delivery

Electric Transmission

Electric Distribution

Smart Meter/Smart Grid

(1)

2015E

$1,575

$1,000

$250

$325

2014E

$1,325

$850

$125

$350

2013E

$1,400

$825

$100

$475

2012E

$1,275

$925

$50

$300

2015E

$600

$300

$25

$175

$100

2014E

$625

$250

$275

$100

2013E

$100

$125

$150

$625

$150

$100

2012E

(2)

$575

$325

$75

$50

$125

(1)

Smart Meter/Smart Grid CapEx net of proceeds from U.S. Department of Energy (DOE) grant. For BGE, includes CapEx from Smart Energy Savers program of ~$10M per year.

(2)

Represents 2012 full year CapEx; estimated 2012 CapEx from merger close date totals $500M.

2012 EEI Conference

46

Smart Meter / Smart Grid Update

Investments will provide customer operational and reliability benefits

(1)

The $200M DOE grant was the maximum allowable under the Smart Grid Investment Grant Program.

2012 EEI Conference

•Installation of nearly 4M smart electric meters delayed to Q1 2015

pending order on rehearing

•Smart Grid program to include distribution automation device

installations and substation modernization upgrades

•ComEd Innovation Corridor will provide a “Test Bed” for smart grid

technologies to be demonstrated within a utility scale environment   

•Investment recovered through distribution formula rate

ComEd will invest ~$1.3B over

the next 10 years

•Installation of more than 1.8M smart electric meters began Q1 2012

•Plans to file request with PAPUC to accelerate deployment completion

by 2014

•Awarded $200M under the DOE program

(1)

, lowering net cost to

customers to ~$450M

•Investment recovered through surcharge mechanism with 10% ROE

PECO will invest up to $650M

through 2014

•Installation of 2M smart electric and gas meters began in April 2012

•A customer web portal and dynamic pricing (Peak Time Rebates) as

the default tariff

•Awarded $200M under the DOE program

(1)

, lowering net cost to

customers to ~$300M

•Cost recovery on project pending until cost-effectiveness showing at

the end of deployment

BGE will invest up to $500M 

through 2015

47

PECO –

Default Service Plan Filing (DSP II)

(1)

FR = Full Requirements; (2) FPFR = Fixed-Price Full Requirements

Retention as of:  October 9, 2012

Proposed Procurement Mix

Class

DSP I (1/1/11 –

5/31/13)

DSP II (6/1/13 –

5/31/15)

Large C&I

Current load retained:

3%

•

100% spot-priced FR

(1)

products

•

2011 opt-in FPFR

(2)

product

•

100% spot-priced FR products

Medium

Commercial

Current load retained:

17%

•

85% 1-year FPFR products, 15% spot-priced FR products

•

100% 6-month FPFR products

Small

Commercial

Current load retained:

42%

•

70% 1-year FPFR products, 20% 2-year FPFR products,

10% spot-priced FR products

•

100% 1-year FPFR products

Residential

Current load retained:

70%

•

45% 2-year FPFR products; 30% 1-year FPFR products;

targeted 20% block products of 1-yr, 2-yr, 5-yr and

seasonal terms; targeted 5% spot market purchases

•

As block products expire, block and spot is replaced by FPFR

products with terms ending 5/31/15 (end of DSP II period)

•

Remainder of portfolio is a mix of 2-yr and 1-yr FPFR

products, with delivery periods overlapping on a semi-annual

basis

•

On 1/13/12, PECO filed a new Default Service Plan with the PAPUC, which outlines how PECO will purchase electricity for

customers not purchasing from a competitive generation supplier from 6/1/13 through 5/31/15

•

PA PUC entered an Opinion and Order on October 12, 2012

PA PUC order:

•

Directs PECO to develop a plan by 1/1/14 to allow Customer Assistance Program (CAP) customers to select an Electric Generation

Supplier (EGS)

•

Provides for some changes to PECO’s Retail Market Enhancements (Opt-In and Customer Referral programs)

•

Directs PECO, EGSs, and interested parties to submit a plan within 60 days to address how participating EGSs will pay for Retail

Market Enhancements

2012 EEI Conference

48

BGE –

Standard Offer Service

•

BGE provides Standard Offer Service (SOS) as fixed seasonal rates for those electric customers who are not shopping.  The

costs

of

providing

this

service

are

recovered

from

customers

via

an

Administrative

Charge

included

in

the

SOS

rate.

The

Administrative Charge and the Energy & Transmission components of the SOS Rate are subject to periodic true-ups.  BGE

procures the majority of energy for this product via Full Requirements load auctions as ordered by the MDPSC.  See table

below:

(1)

FPFR = Fixed-Price Full Requirements

Retention as of: September  30, 2012

Procurement Mix

Class

6/1/12 –

5/31/13

6/1/13 –

5/31/14

Large C&I

(Hourly)

Current load retained:

7%

•

100% of supply procured directly from the PJM spot

market

•

100% of supply procured directly from the PJM spot

market

Medium

Commercial

(Type II)

Current load retained:

38%

•

100% 3-month FPFR

(1)

products

•

Auction

Apr

’12

for

Jun

’12

–

Aug

’12

•

Auction

Jun

’12

for

Sep

’12

–

Nov

’12

•

Auction

Oct

’12

for

Dec

’12

–

Feb

’13

•

Auction

Jan

’13

for

Mar

’13

–

May

’13

•

100% 3-month FPFR products

•

Auction

Apr

’13

for

Jun

’13

–

Aug

’13

•

Auction

Jun

’13

for

Sep

’13

–

Nov

’13

•

Auction

Oct

’13

for

Dec

’13

–

Feb

’14

•

Auction

Jan

’14

for

Mar

’14

–

May

’14

Small

Commercial

(Type I)

Current load retained:

63%

•

25% 2-year FPFR products

•

Auction

Apr

’10

for

Oct

’10

–

Sep

’12

•

Auction

Oct

’10

for

Jun

’11

–

May

’13

•

Auction

Apr

’11

for

Oct

’11

–

Sep

’13

•

Auction

Oct

’11

for

Jun

’12

–

May

’14

•

Auction

Apr

’12

for

Oct

’12

–

Sep

’14

•

25% 2-year FPFR products

•

Auction

Apr

’11

for

Oct

’11

–

Sep

’13

•

Auction

Oct

’11

for

Jun

’12

–

May

’14

•

Auction

Apr

’12

for

Oct

’12

–

Sep

’14

•

Auction

Oct

’12

for

Jun

’13

–

May

’15

•

Auction

Apr

’13

for

Oct

’13

–

Sep

’15

Residential

Current load retained:

74%

•

25% 2-year FPFR products

•

Auction

Apr

’10

for

Oct

’10

–

Sep

’12

•

Auction

Oct

’10

for

Jun

’11

–

May

’13

•

Auction

Apr

’11

for

Oct

’11

–

Sep

’13

•

Auction

Oct

’11

for

Jun

’12

–

May

’14

•

Auction

Apr

’12

for

Oct

’12

–

Sep

’14

•

25% 2-year FPFR products

•

Auction

Apr

’11

for

Oct

’11

–

Sep

’13

•

Auction

Oct

’11

for

Jun

’12

–

May

’14

•

Auction

Apr

’12

for

Oct

’12

–

Sep

’14

•

Auction

Oct

’12

for

Jun

’13

–

May

’15

•

Auction

Apr

’13

for

Oct

’13

–

Sep

’15

2012 EEI Conference

49

Regulatory Schedule

4Q12

1Q13

2Q13

3Q13

2013 formula rate

case filing (by

5/1/13)

ComEd Distribution

Formula Rate 

Illinois Power

Agency

Procurement

ComEd

Transmission Rate

Update

2013 formula rate

case filing (by 5/1);

rates effective June

2013 thru May 2014

2013 formula rate case

filing final order (by

12/27/13); rates

effective 1/2/14 –

1/1/15

4Q13

BGE Distribution Rates

PECO Supply

Procurement

BGE Transmission Rate

Update

2013 formula rate case

filing (by 5/15/13);

rates effective June

2013 thru May 2014

MDPSC Order expected

February 23, 2013

DSP II Procurement

(December)

BGE Supply

Procurement

Regular procurement

event (January)

Regular procurement

event (April and June)

Act 129 Part II Energy

Efficiency Plan Filing

(11/2012)

PECO Distribution

Filing

12-0321 final order

(by 12/26); rates

effective 1/2/13 –

1/1/14

DSP II Procurement

(February)

DSP II Procurement

(October)

Regular

procurement event

(October)

Regular

procurement event

(October)

No procurement events scheduled for 2013

2012 EEI Conference

Generation

Exelon Generation Fleet

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

EPA regulations

(1)

Total owned generation capacity as of 9/30/2012 for legacy Exelon and legacy Constellation combined, net of physical market mitigation assumed to be 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.

51

National Scope

•

Power generation assets in 20 states and

Canada

•

Low-cost generation capacity provides

unparalleled leverage to rising commodity

prices

Large and Diverse

•

35

GW

of

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

•

Less than 5% of combined generation

capacity will require capital expenditures

to comply with Air Toxic rules

2012 EEI Conference

Executing on Renewable Development Projects

Existing renewable projects will expand the renewable portfolio by more than 600

MW by 2013

52

•

Six projects completed or to be completed by

the end of 2012

—

Adding 404 MW

—

Diverse geographic representation:

Idaho

Kansas

Michigan

New Mexico

Texas

•

All projects done under long-term PPAs with

anticipated payback in approximately 10 years

2012 EEI Conference

AVSR 1

Wildcat

Wind

Wind

Solar

•

Antelope Valley Solar Ranch Project One

Large scale solar project that will be 230

MW once fully operational

On track to add 80 MW by year-end 2012

150 MW online by Fall 2013

Initial investment fully recovered by 2015

25-year PPA for entire output with Pacific

Gas & Electric

Cashflow and EPS accretive in 2013

Los

Angeles

53

Nuclear Uprates

(1)

Includes deletion of TMI MUR from the uprate program and deferral of Limerick and LaSalle

EPU’s.

(2)

In 2013 dollars. Overnight costs do not include financing costs or cost escalation.

(3)

Adjusted for actual MW’s achieved.

(4)

Total project returns

Uprate projects enhance Exelon’s

geographically diverse nuclear fleet –

approximately 18 MW to come on line

in 2012 and an additional 230 MW

through 2015

Nuclear

Uprate

Program

Summary

(1)

Estimated

IRR

(4)

Overnight

Cost

(2)

Approval

Process

Project

Duration

Megawatt

Recovery &

Component

Upgrades

11 -

13%

$890 M

Not

required

3-4 Years

MUR

(Measurement

Uncertainty

Recapture)

12 -

16%

$300 M

Straight

forward

approval

process

2-3 Years

EPU (Extended

Power Uprate)

8 -

13%

$2,240 M

Straight

forward

approval

process

3-6 Years

Station

Base Case

MW

(3)

Max Potential

MW

(3)

MW Online to

Date

Year of Full

Operation

by Unit

(1)

MW Recovery & Component Upgrades:

Quad Cities

99

99

99

2011 / 2010

Dresden

3

3

2013 / 2012

Peach Bottom

29

30

15

2012 / 2011

Dresden

106

110

62

2011 / 2013

Limerick

6

6

3

2012 / 2013

Peach Bottom

2

2

2014 / 2015

MUR:

LaSalle

39

39

39

2010 / 2011

Limerick

30

30

30

2011 / 2011

Braidwood

34

42

2013 / 2013

Byron

34

42

2013 / 2013

Quad Cities

20

21

2014 / 2014

Dresden

26

28

2014 / 2015

TMI

0

0

Deleted

EPU:

Clinton

2

2

2

2010

Peach Bottom

130

137

2015 / 2016

LaSalle

297

313

2020 / 2019

Limerick

270

284

2021 / 2021

Total

1,127

1,188

250

2012 EEI Conference

Peach Bottom Uprate Program

•

MW Recovery

–

Low Pressure Turbine Retrofit installation complete

for both Unit 2 and Unit 3

–

Replacement of Reactor Recirculation Pump Motor

Generator sets with energy efficient Adjustable

Speed Drives in 2014 and 2015

•

EPU

–

Funding approved for installation work

54

Unit 2

Unit 3

Uprate Project

MW

Increase

(1)

Online

Date

MW

Increase

(1)

Online

Date

Status

MW Recovery -

Low Pressure

Turbine Retrofit

14

4Q 2012

15

4Q 2011

Complete

MW Recovery -

Adjustable Speed

Drives

1

4Q 2014

1

4Q 2015

Initial studies in progress

EPU

65

1Q 2015

65

1Q 2016

Installation phase in progress

(1)  Capital investment and MW uprate numbers represent Exelon’s 50% ownership stake in Peach Bottom Station. $’s used in chart are nominal (excludes capitalized interest).

Peach Bottom Uprate Projects are underway –

15 additional MWs came online in

2011 and the remaining will come online between late 2012 and 2016

$0

$50

$100

$150

2009

2010

2011

2012

2013

2014

2015

2016

2017

Capital Investment $M

(1)

MW Recovery

EPU

2012 EEI Conference

Exelon Nuclear Fleet Overview (including CENG and Salem)

Plant Location

Type/

Containment

Water Body

License Extension Status / License

Expiration

Ownership

Spent Fuel Storage/

Date to lose full core

discharge capacity

Braidwood, IL

(Units 1 and 2)

PWR

Concrete/Steel Lined

Kankakee River

Expect to file application in 2013 /  2026,

2027

100%

Dry Cask

Byron, IL

(Units 1 and 2)

PWR

Concrete/Steel Lined

Rock River

Expect to file application in 2013 /  2024,

2026

100%

Dry Cask

Clinton, IL

(Unit 1)

BWR

Concrete/Steel Lined / Mark III

Clinton Lake

2026

100%

Dry Cask

(2017)

Dresden, IL

(Units 2 and 3)

BWR

Steel Vessel / Mark I

Kankakee River

Renewed / 2029, 2031

100%

Dry Cask

LaSalle, IL

(Units 1 and 2)

BWR

Concrete/Steel Lined / Mark II

Illinois River

2022, 2023

100%

Dry Cask

Quad Cities, IL

(Units 1 and 2)

BWR

Steel Vessel / Mark I

Mississippi River

Renewed / 2032

75% Exelon, 25% Mid-

American Holdings

Dry Cask

Calvert Cliffs, MD

(Units 1and 2)

PWR

Concrete/Steel Lined

Chesapeake Bay

Renewed / 2034, 2036

100% CENG

Dry Cask

R.E. Ginna, NY

(Unit 1)

PWR

Concrete/Steel Lined

Lake Ontario

Renewed / 2029

100% CENG

Dry Cask

Limerick, PA

(Units 1 and 2)

BWR

Concrete/Steel Lined / Mark II

Schuylkill River

Filed application in June 2011 (decision

expected in 2015) / 2024, 2029

100%

Dry Cask

Nine Mile Point, NY

(Units 1 and 2)

BWR

Concrete/Steel Vessel / Mark I /

Concrete/Steel Vessel/ Mark II

Lake Ontario

Renewed / 2029, 2046

100% CENG    /

82% CENG   , 18% Long

Island Power Authority

Dry Cask

Oyster Creek, NJ

(Unit 1)

BWR

Steel Vessel / Mark I

Barnegat Bay

Renewed / 2029

100%

Dry Cask

Peach Bottom, PA

(Units 2 and 3)

BWR

Steel Vessel / Mark I

Susquehanna

River

Renewed / 2033, 2034

50% Exelon, 50% PSEG

Dry Cask

TMI, PA

(Unit 1)

PWR

Concrete/Steel Lined

Susquehanna

River

Renewed / 2034

100%

2023

Salem, NJ

(Units 1 and 2)

PWR

Concrete/Steel Lined

Delaware River

Renewed / 2036, 2040

42.6% Exelon, 57.4%

PSEG

Dry Cask

(1)

Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review.

(2)

The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge

capacity in their on-site storage pools.

(3)

On December 8, 2010, Exelon announced that it will permanently cease generation operations at Oyster Creek by December 31, 2019.

Oyster Creek’s current NRC license expires in 2029.

(4)

Exelon Generation has a 50.01% ownership interest in CENG (Constellation Energy Nuclear Group, LLC). Electricite de France SA (EDF) has a 49.99% ownership interest in CENG.

55

2012 EEI Conference

(1)

(2)

(3)

(4)

(4)

(4)

(4)

Effectively Managing Nuclear Fuel Costs

(1)

Projected Exelon (100%) Uranium Demand

Components of Nuclear Fuel in 2012

2012 –

2015: 100% hedged in volume

2016:

~85% hedged in volume

2017:

~55% hedged in volume

11

10

9

8

7

6

5

4

3

2

1

0

2017E

2016E

2015E

2014E

2013E

2012

Projected Exelon Average Uranium Cost vs. Market

2017E

2016E

2015E

2014E

2013E

2012

Exelon Average Reload Price

Projected Market Price

(1)

All charts exclude Salem and CENG.

(2)

At ownership, excluding Salem and CENG. Excludes costs reimbursed under the settlement agreement with the DOE.

56

Projected

Total

Nuclear

Fuel

Spend

(2)

2017E

1,174

2016E

1,152

2015E

1,096

2014E

1,051

2013E

992

2012

926

Nuclear Fuel Capex

Nuclear Fuel Expense (Amortization + Spent Fuel)

2012 EEI Conference

14%

Fabrication

14%

Nuclear Waste

36%

Uranium

3%

Conversion

2%

Tax/Interest

31%

Enrichment

0

20

40

60

80

100

0

200

400

600

800

1,000

1,200

1,400

Impact of Refueling Outages

Refueling Outage Duration

31%

36%

14%

14%

Nuclear

Output

(1)

Note: Net nuclear generation data at ownership excluding Salem and CENG. 

57

1,208

1,169

1,104

Nuclear Refueling Cycle

•

All Exelon owned units on a 24 month cycle

except for Braidwood U1/U2, Byron U1/U2 and

Salem U1/U2, which are on 18 month cycles

•

Average Outage Duration (2010-11): ~27 days

Note: Exelon data excludes Salem & CENG. Exelon’s 2009 average includes 23 days of TMI outage that

extended into 2010 for a steam generator replacement.

Actual

Target

# of Outages

2012 Refueling Outage Impact

•

10 planned refueling outages, including 1 at

Salem

•

Exelon completed 4 refueling outages in the

Spring with an average duration of 30 days

•

5 Exelon planned Fall refueling outages (Byron

1, Peach Bottom 2, Braidwood 2, Oyster Creek,

and Dresden 3)

•

1 Salem planned Fall refueling outage

2013 Refueling Outage Impact

•

10 planned refueling outages, including 1 at

Salem

•

4 Exelon planned Spring refueling outages and

5 planned Fall refueling outages

•

1 Salem planned Spring refueling outage

Industry (w/o Exelon)

Exelon

2011

2010

2009

2008

2007

2006

2005

2004

2003

2002

2012 EEI Conference

125

126

127

128

129

130

131

132

133

134

135

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

7

7.5

8

8.5

9

9.5

10

10.5

0

10

20

30

40

50