Presentation Slides

Cautionary Statements Regarding

Forward-Looking Information

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

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

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

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

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

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

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

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

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

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

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

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

Readers

are

cautioned

not

place

undue

reliance

these

forward-looking

statements,

which

apply

only

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

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

2012 Analyst Meeting – Performance that Drives Progress

Exelon Overview

Power Generation

Constellation

ComEd, PECO & BGE

Competitive Business

Regulated Business

Exelon is the largest competitive integrated energy company in the U.S.

•

Largest merchant fleet in the

nation (~35 GW of capacity),

with unparalleled upside

•

One of the largest and best

managed nuclear fleets in the

world (~19 GW)

•

Significant gas generation

capacity (~10 GW)

•

Renewable portfolio (~1 GW),

mostly contracted

•

Leading competitive energy

provider in the U.S.

•

Customer-facing business, with

~1.1 M competitive customers

and large wholesale business

•

Top-notch portfolio and risk

management capabilities

•

Extensive suite of products

including Load Response,

RECs, Distributed Solar

•

One of the largest electric and

gas distribution companies in

the nation ~6.6 M customers

•

Diversified across three utility

jurisdictions –

Illinois, Maryland

and Pennsylvania

•

Significant investments in

Smart Grid technologies

•

Transmission infrastructure

improvement at utilities

Exelon Generation

Exelon Utilities

ComEd, PECO & BGE

Exelon Utilities

2012 Analyst Meeting – Performance that Drives Progress

Diversified Platform and Revenue Growth

Exelon’s portfolio is well diversified and positioned for long-term growth

~50%

Regulated Business

Competitive Businesses

•

Upside from tightening power

markets from significant amount of

coal retirements

•

Strong pipeline of organic generation

growth opportunities, including

nuclear uprates, wind & solar

•

Leverage Constellation brand,

network and relationships to grow

customer-facing business across the

country

•

Low-risk investment through

contracted renewables fleet and load

matched with generation

•

Investment grade credit ratings to

support operations and growth

•

Stable income and cash flow from

utility operations

•

Significant investment in

infrastructure upgrades, including

next generation technology

enhancements (Smart Grid)

•

Diversification across three utility

jurisdictions

•

Leverage utility structure to drive

best practices

•

Investments to improve reliability

and operations

Competitive Business

Diversification of revenue, earnings and cash flows

(1) Based on 2012 thru 2014 average operating EBITDA estimate as of 4/30/2012 and adjusting for ComEd rate order.

Regulated Business

2012 Analyst Meeting – Performance that Drives Progress

Balanced EBITDA Contribution

(1)

Exelon’s Transformation

The merger enhances scale, scope and flexibility across the value chain

Exelon Pre Merger

Exelon Post Merger

Financials

$55.1 billion

Assets

(1)

$74.5 billion

$18.9 billion

Revenues

(1)

$32.7 billion

$26.4 billion

Market Capitalization

(2)

$33.9 billion

Power Generation

(3)

~26 GW

Total Capacity

(4)

~35 GW

175 TWh

Expected Generation

(5)

220 TWh

~4 GW

Natural Gas Capacity

(5)

~10 GW

Constellation

(3)

~40 TWh / 50 BCF

Competitive Load & Gas

(6)

~170 TWh / 465 BCF

3,500

Customer Count

More than 1 million

Minimal Load Response

Load Response Portfolio

~2,000 MW

No projects

Energy Efficiency Projects

Over 4,000 projects across U.S.

Exelon Utilities

(3)

5.4 million

Customers

6.6 million

$13 billion

2011 Combined Rate Base

$17 billion

(1)

Represents 2011 actuals.

(2)

As of 3/12/2012.

(3)

2012 estimate as of 4/30/2012.

(4) Represents owned capacity, net of mitigation (~2,648 MW).

(5) Represents owned or contracted capacity, net of mitigation.

(6) Represents fixed price or indexed load, including retail and wholesale.

2012 Analyst Meeting – Performance that Drives Progress

Committed to Making the Merger Successful

Tasks Accomplished

Closed the merger in less than a year

Effective integration planning and execution for

seamless day 1 operations

Appointed leadership and management teams

Ongoing Focus

•

Employ Exelon’s management model to enhance

profitability by realizing efficiencies and reducing

costs

•

Enterprise-wide synergy realization (O&M, CapEx)

•

Efficient and optimal use of capital to pursue

highest value projects and opportunities

•

Grow and diversify our business in a deliberate and

sustainable manner

•

Focus on both process and innovation to protect

and grow the business

We are well on our way to realizing the value from this merger

Merger Checklist / Scorecard

Item

Target

Cost Synergies

$500 million run rate

(1)

Liquidity Reduction

$4.2 billion year-end 2012

Gross Margin

Opportunities

$100 million run rate

(2)

Asset Sales

Process

Complete by August 2012

Commercial Load

Volume Growth

~6% CAGR on volumes

(3)

BGE

File rate case in 2

half of 2012

Confident in ability to achieve or exceed

targets in a timely and efficient manner

Clearly defined plans to make this merger successful

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

(2) Gross Margin opportunities on a run rate basis from 2014 onwards from combining the two commercial

portfolios.

(3) Represents Compounded Annual Growth Rate (CAGR) until 2014 using 2011

as the base year.

2012 Analyst Meeting – Performance that Drives Progress

Operating O&M Forecast Lower than Inflation

•

2012 O&M forecast of $6.45B

(1)

Includes merger synergies of $170M for ~9.5 months

Excludes costs to achieve which are considered non-operating

•

Maintain O&M CAGR of ~1%

(2)

for 2012-2014

2012E (Combined

Company)

$6,775

(2) (3)

-50

4,100

1,200

675

525

2011 Actuals (Standalone

EXC + Standalone CEG)

3,000

1,100

725

650

1,250

(in $M)

ExGen

ComEd

PECO

BGE

Corp

•

ExGen O&M includes

costs of maintaining a

larger retail platform

•

Higher O&M at ComEd

mainly driven by EIMA

related costs of ~$70M

•

PECO costs lower due

to higher than normal

storm costs in 2011

(1)

O&M included in 2012 EPS guidance includes CEG and BGE costs from merger close date.

(2)

O&M Compound Annual Growth Rate (CAGR) calculated after normalizing 2012 O&M to include CEG and BGE costs for 12 months.

(3)

O&M for utilities excludes regulatory O&M that are P&L neutral. ExGen O&M excludes decommissioning costs.

EIMA = Energy Infrastructure Modernization Act

~1% CAGR for 2012-2014

ExGen

BGE

Constellation

2012 EPS

guidance includes

$6.45B

(1)

of O&M

costs

Stub O&M

$6,725

(3)

2012 Analyst Meeting – Performance that Drives Progress

2012 Projected Sources and Uses of Cash

(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 31, 2012.

(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.

(7)

($ in Millions)

Beginning Cash Balance

(1)

$550

Cash acquired from Constellation

(2)

150

n/a

1,375

1,650

Cash Flow from Operations

(3)

300

1,425

825

3,600

5,925

CapEx (excluding other items below):

(475)

(1,225)

(350)

(975)

(3,100)

Nuclear Fuel

n/a

(1,175)

Dividend

(4)

(1,725)

Nuclear Uprates

n/a

(400)

Wind

n/a

(650)

Solar

n/a

(625)

Upstream

n/a

(100)

Utility Smart Grid/Smart Meter

(75)

(100)

(75)

n/a

(250)

Net Financing (excluding Dividend):

Planned Debt Issuances

(5)

300

250

775

1,325

Planned Debt Retirements

(175)

(450)

(375)

(75)

(1,075)

Project Finance/Federal Financing

Bank Loan

n/a

350

Other

(6)

225

175

Ending Cash Balance

(1)

$875

2012 Analyst Meeting – Performance that Drives Progress

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

A-

BBB+

15-18%

PECO

A-

15-18%

BGE

Baa1

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

April 16, 2012.

(2)

Moody’s downgraded Exelon and Generation and upgraded BGE upon completion of the merger with Constellation Energy. Moody’s

currently

has

Exelon

and

Generation

Negative

Outlook.

S&P

and

Fitch

affirmed

ratings

Exelon

and

subsidiaries

upon

completion of the merger.

(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

•

2012-2016 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

2012 Analyst Meeting – Performance that Drives Progress

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

Merger Purchase Accounting P&L Impacts

Preliminary

Exelon

Generation

Pre-Tax

GAAP

P&L

Impacts

(1)

($M)

2012

Item

Total

2013

2014

Description

Earnings

Treatment

Unamortized energy

contracts, net

(Revenue net Fuel)

~($125)

~($450)

(~$275)

~($300)

~($1,150)

~($475)

~($100)

Non-cash amortization of

intangible assets, net, for

acquired power supply and

fuel contracts recognized at

fair value at the merger

date.

Excluded from

operating

earnings in

2012-14

Depreciation &

Amortization

~($1)

~($6)

~($20)

~($30)

Net incremental

depreciation and

amortization based on fair

value of generation station

and upstream assets, trade

name, and retail

relationships. Excludes

plant divestitures.

Included in

operating

earnings

Amortization of

adjustment to

recognize the

unregulated long-term

debt at fair value

(Interest Expense)

~$3

~$8

~$28

~$25

~$15

Non-cash amortization of

fair value adjustment for

long-term debt.

Included in

operating

earnings except

for $17M and

$12M hybrid

amortization in

2012-13,

respectively

(2)

2012 Analyst Meeting – Performance that Drives Progress

(1)

Amounts shown in table above are based on the preliminary valuation underlying the disclosures in the first quarter Form 10-Q. These amounts are subject to

revision and any changes could be material. Numbers represent increase / (decrease) to GAAP earnings. This list of purchase accounting adjustments is not all

inclusive. Other minor adjustments have minimal impact on earnings.

(2)

Exclusion from operating earnings for amortization related to hybrid instrument expected to be retired in 2013.

Pension and OPEB for Combined Company

Plan Design and Funding Strategy:

•

Exelon is evaluating benefit plan design changes for the combined company, but does not anticipate

merging the Exelon and Constellation plans until 2013 at the earliest

•

Exelon and Constellation plans will maintain their stand-alone funding strategies in 2012; the funding

strategy for the combined company will be reevaluated once the future state plan design is established

Both companies’

pension funding strategy is to 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

Unlike qualified pension plans, OPEB plans are not subject to regulatory minimum contribution

requirements and are, therefore, voluntary. 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

plans

are

unfunded

Current Forecast:

•

The table below provides the combined company’s 2012 and forecasted 2013 pension and OPEB expense

and

contributions

assuming

2012

asset

returns

7.50%

and

6.68%

(after-tax)

for

pension

and

OPEB,

respectively, a projected 12/31/12 pension discount rate of 4.70% and 4.52% for Exelon and

Constellation, respectively, and a projected 12/31/12 OPEB discount rate of 4.78% and 4.53% for Exelon

and Constellation, respectively

(1) Pension and OPEB expenses assume a 27.0% and 27.6% capitalization rate for 2012 and 2013, respectively.

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

2012

2013

(in $M)

Pre-Tax Expense

(1)

Contributions

(2)

Pre-Tax Expense

(1)

Contributions

(2)

Pension

$350

$160

$350

$150

OPEB

$240

$320

$235

$305

Total

$590

$480

$585

$455

2012 Analyst Meeting – Performance that Drives Progress

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

2013 Pension Sensitivity

(2)

(in $M)

S&P Returns in Q2 –

Q4 2012

(3)

10%

-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)

$340

$145

$360

$155

$375

$160

+50 bps

$310

$150

$325

$155

$345

$160

50bps

$375

$90

$390

$150

$410

$160

2013 OPEB Sensitivity

(2)

(in $M)

S&P Returns in Q2 –

Q4 2012

(3)

10%

-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

$285

$230

$300

$245

$320

+50 bps

$200

$260

$210

$275

$225

$290

50bps

$240

$315

$255

$335

$270

$355

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

(2) Pension and OPEB expenses assume a 27.6% capitalization rate.

(3) Final 2012 asset return for pension and OPEB will depend in part on overall equity market returns from Q2 – Q4 2012 as proxied by the S&P 500. The

amounts above reflect YTD S&P returns through March 31, 2012.

(4) The baseline discount rates reflect a projected 12/31/12 pension discount rate of 4.70% and 4.52% for Exelon and Constellation, respectively, and OPEB

discount rate of 4.78% and 4.53% for Exelon and Constellation, respectively.

2012 Analyst Meeting – Performance that Drives Progress

2012 Key Assumptions

Utility Statistics

2012 Estimate

Electric Delivery Growth (%)

(3)

ComEd

(0.3)%

PECO

(3.3)%

BGE

0.7%

Effective Tax Rate -

Operating (%)

ComEd

39.6%

PECO

33.6%

BGE

37.8%

Exelon

37.4%

(1)

Excludes Salem and CENG.

(2)

Reflects forward market prices as of April 30, 2012.

(3)

Weather-normalized load growth.

(4)

O&M rounded to the nearest $25M.

Generation Statistics

2012 Estimate

(2)

Nuclear Capacity Factor (%)

(1)

93.5%

Total Expected Generation(GWh)

219,900

Henry Hub Natural Gas ($/MMbtu)

$2.47

Midwest: NiHub ATC Price

$26.71

Mid-Atlantic: PJM-W ATC Price

$32.70

ERCOT-N ATC Spark Spread

$11.10

New York: NY Zone A ATC Price

$26.99

New England: Mass Hub Spark Spread

$5.98

Effective

Tax

Rate

(%)

Operating

37.1%

2012 O&M

(4)

Reconciliation (in $M)

ExGen

ComEd

PECO

BGE

Other

Exelon

GAAP O&M

$4,725

$1,350

$700

$575

$175

$7,525

Decommissioning accretion

$(75)

Retirement of Fossil Plants

$(25)

FERC Settlement

$(200)

Regulatory O&M

$(150)

$(25)

$(175)

Merger/Integration costs

$(325)

$(50)

$(225)

$(600)

Operating O&M (as shown on slide 18)

$4,100

$1,200

$675

$525

$(50)

$6,450

2012 Analyst Meeting – Performance that Drives Progress

GAAP to Operating Adjustments

Three Months Ended March 31, 2012

ExGen

(1)

ComEd

PECO

BGE

(1)

Other

(1)

Exelon

(1)

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

$0.58

$0.13

$0.14

$0.02

$(0.02)

$0.85

Mark-to-market adjustments from economic hedging activities

0.05

0.01

0.06

Unrealized gains related to nuclear decommissioning trust funds

0.05

Retirements of fossil generation units

(0.01)

Constellation merger and integration costs

(0.06)

(0.00)

(0.01)

(0.00)

(0.09)

(0.16)

Maryland commitments

(0.03)

(0.12)

(0.17)

(0.32)

Amortization of commodity contract intangibles

(0.11)

FERC settlement

(0.25)

Plant divestitures

(0.00)

Reassessment of state deferred income taxes

0.02

0.15

0.17

Other acquisition costs

(0.00)

1Q 2012 GAAP Earnings (Loss) Per Share

$0.24

$0.13

$0.14

$(0.09)

$(0.12)

$0.28

•

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

Mark-to-market adjustments from economic hedging activities

Unrealized gains and losses from nuclear decommissioning trust fund investments to the extent not offset by contractual accounting as described

in the notes to the consolidated financial statements

Financial impacts associated with the planned retirement of fossil generating units

Certain costs related to the Constellation merger and integration initiatives

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

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

Costs incurred as part of a March 2012 settlement with the Federal Energy Regulatory Commission (FERC) related to Constellation’s prior period

hedging and risk management transactions

Revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger

Non-cash benefit associated with a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s

deferred taxes as a result of the merger

Certain costs incurred associated with other acquisitions

Significant impairments of assets, including goodwill

Other unusual items

Significant changes to GAAP

•

Operating

earnings

guidance

assumes

normal

weather

for

remainder

the

year

2012 Analyst Meeting – Performance that Drives Progress

(1) For the three months ended March 31, 2012, includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

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

Commercial Business Overview

Scale, Scope and Flexibility Across the Energy Value Chain

Development and

exploration of natural gas

and liquids properties

11 assets in

seven states

~295 BCFe of proved

Reserves

(1)

Largest 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

~465 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

~2,000 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 4/30/2012, net of physical market mitigation (Brandon Shores, C.P. Crane and H.A. Wagner ~2,648 MW).

(3) Expected for 2012 as of 4/30/2012. Electric load and gas includes fixed price and indexed products. No stub period adjustment for legacy Constellation contribution.

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

2012 Analyst Meeting – Performance that Drives Progress

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

Credit Rating

Capital

Structure

Capital &

Operating

Expenditure

Dividend

2012 Analyst Meeting – Performance that Drives Progress

Strategic Policy Alignment

Three-Year Ratable Hedging

Bull / Bear Program

•Aligns hedging program with

financial policies and financial

outlook

•Establish minimum hedge targets

to meet financial objectives of the

company (dividend, credit rating)

•Hedge enough commodity risk to

meet future cash requirements

under a stress scenario

•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

•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

Renewables

Baseload

Intermediate

Peaking

Generation capacity

Generation and Load Match

Our generation portfolio is low cost,

flexible and diverse

Generation and load positions are well

balanced across multiple regions

Adequate intermediate and peaking

capacity within the portfolio for managing

peaking load

Continue to buy or sell length from

market to manage portfolio needs

101

New York

New England

ERCOT

MidAtlantic

113

MidWest

129

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

2012 in TWh

(1,2)

Expected Load

Expected Generation

Generation & Load Match: Competitive Advantage

South, West

& Canada

2012 Analyst Meeting – Performance that Drives Progress

(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 4/30/2012.

24%

Electric Load Serving Business: Growth Target

100

120

140

160

180

200

220

170

+20%

2014E

35-45%

200

65-75%

25-35%

2013E

180

65-75%

25-35%

2012E

55-65%

2011A

170

Retail Load

(2)

Wholesale Load

Total Contracted

Commercial Load

(1)

2011 –

2014 TWh

Load Split by Customer Class

(2011 TWh)

Well positioned for growth in volumes and

margins on the back of a sustainable platform

and new opportunities

A diverse set of customers enhances margin

opportunities from a sales and portfolio

management standpoint

Mass Markets

<1,000 MWhs per year

Small C&I

1,001-5,000 MWhs per year

Medium C&I

5,001-25,000 MWhs per year

Large C&I

>25,000 MWhs per year

46%

Wholesale

Large C&I

15%

Medium C&I

Small C&I

Mass Markets

C&I = Commercial & Industrial

Load Size

Customer Type

2012 Analyst Meeting – Performance that Drives Progress

(1)

Numbers and percentages are rounded to the nearest 5

(2)

Index load expected to be 20% to 30% of total forecasted retail load

18%

Electric Load Serving Business: Strategy

Constellation is well positioned in a 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%

2012 Analyst Meeting – Performance that Drives Progress

ExGen Disclosure Overview

Continue

provide

transparency

our

ExGen

disclosures

with

modified

and

expanded

framework that incorporates new business lines and regions

•

Continue to provide open gross margins, expected generation, hedge %, reference prices and effective realized

energy prices (EREP)

Also provide Mark-to Market (MtM) value of all hedges on a consolidated basis

•

Consider retail and wholesale load to be an alternate channel to

market our generation. As such, executed sales are

regarded as a hedge and thus flow into MtM, EREP and hedge percentage

Provide volume targets and track sales execution versus targets on an annual basis

•

Introduction of new gross margin categories

•

In addition to Open Gross Margin and MtM of hedges, gross margins will be provided for the following categories -

Power New Business: Gross margins from future hedging activity via retail, wholesale or structured

transaction/mid-marketing activities. Once power sales are executed, these flow into MtM via EREP

Non Power New Business: Gross margins from planned sales from business activities not related to hedging

power

production,

such

Load

Response,

Energy

Efficiency,

Retail

and

Wholesale

Gas,

Proprietary

Trading

(1)

etc.

Once

sales

are

executed,

gross

margins

will

flow

“Non

Power

Executed”

category.

Non Power Executed: Contracted gross margin associated with business activities not directly linked to production

or sale of power

•

Introduction of new regions

To reflect our expanded national presence, New England, New York, and South, West & Canada regions have been

added to Midwest, Mid-Atlantic and ERCOT

Hedged gross margins for South, West & Canada will be included within the consolidated “Open Gross Margin”

estimate

The other five regions will have corresponding expected generation, hedge %, reference prices and EREP

2012 Analyst Meeting – Performance that Drives Progress

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

–

Maintain ability to value generation fleet on an open and hedged basis

No separate gross margins for commercial load, but will disclose volume targets and sales execution

Components of Gross Margin Categories

Open Gross

Margin

•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

Hedges

(2)

•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

“Power”

New

Business

•Retail, Wholesale

planned electric

sales

•Portfolio

Management

new business

•Mid marketing

new business

“Non Power”

Executed

•Retail, Wholesale

executed gas

sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

“Non Power”

New Business

•Retail, Wholesale

planned gas

sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

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

Gross margin from

other business activities

(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 andnot move to “Non power” executed category.

2012 Analyst Meeting – Performance that Drives Progress

ExGen Disclosures

Gross Margin Category ($ MM)

2012

(1)

2013

2014

Open Gross Margin

(2,3)

(including South, West, Canada hedged gross margin)

$4,300

$5,800

$6,250

Mark-to-Market of Hedges

$3,150

$1,400

$500

Power New Business / To Go

$200

$550

$850

Non-Power Margins Executed

$200

$100

$50

Non-Power New Business / To Go

$200

$500

$550

Total Gross Margin

$8,050

$8,350

$8,200

Generation and Hedges

2012

(1)

2013

2014

Exp. Gen (GWh)

219,900

218,400

210,200

Midwest

101,800

97,900

97,800

Mid-Atlantic

(2,3)

71,300

74,100

72,000

ERCOT

19,900

18,800

16,100

New York

(3)

13,400

10,500

New England

13,500

14,200

13,800

% of Expected Generation Hedged

97-100%

73-76%

41-44%

Midwest

94-97%

77-80%

44-47%

Mid-Atlantic

(2,3)

105-108%

74-77%

45-48%

ERCOT

(4)

89-92%

56-59%

34-37%

New York

(3)

91-94%

69-72%

20-23%

New England

(4)

94-97%

66-69%

27-30%

Effective Realized Energy Price ($/MWh)

Midwest

$41.00

$39.50

$37.00

Mid-Atlantic

(2,3)

$53.00

$49.00

ERCOT

(4)

$8.50

$6.00

$3.00

New York

(3)

$45.00

$37.00

$37.50

New England

(4)

$8.00

$8.50

$3.50

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

(2) Excludes Maryland assets to be divested.

(3) Includes Constellation Energy Nuclear Group (CENG) Joint Venture.

Reference Prices (ATC -$/MWh)

(5)

2012

2013

2014

Henry Hub Natural Gas ($/MMbtu)

$2.47

$3.45

$3.87

Midwest: NiHub

$26.71

$30.28

$32.45

Mid-Atlantic: PJM-W

$32.70

$37.93

$40.37

ERCOT-N ATC Spark Spread

$11.10

$9.19

$8.50

New York: NY Zone A

$26.99

$31.40

$33.46

New England: Mass Hub Spark Spread

$5.98

$4.66

$3.50

2012 Analyst Meeting –

Performance that Drives Progress

(4) Spark spreads shown for Texas and New England.

(5) Based on April 30, 2012 market conditions.

Closing Remarks

•

RPM PY 2015/2016 Auction Results

Results were in line with internal expectations of pricing improvement vs. last year’s auction

Moderate growth in cleared Demand Response (DR) signals continued DR bidding discipline

•

Best Positioned Merchant Generation Portfolio

Continue to believe the upside associated with net retirements and higher operational costs in

the range of $3-5/MWh in PJM, with a large portion not currently reflected in energy prices

•

Effective Risk Management

Well established criteria and effective oversight to manage and monitor risk

Small proprietary trading function and contribution to gross margin

•

Nation’s Number One Energy Marketer

Best positioned to capture additional load as new markets open and existing markets mature

Matching generation to load, and an extensive suite of products and services, provides us with

a competitive advantage

We are well positioned to expand our business across many fronts

and deliver on

overall commercial business growth

2012 Analyst Meeting – Performance that Drives Progress

Generation Capacity Market Positions

2011/2012

2012/2013

2013/2014

2014/2015

2015/2016

PJM

(1)

RTO

Capacity

27,400

12,800

11,500

Price

$110

$16

$28

$126

$136

EMAAC

Capacity

(2)

9,200

Price

$140

$245

$137

$168

MAAC

Capacity

2,600

2,700

Price

$133

$226

$137

$168

SWMAAC

Capacity

(3)

1,900

Price

$133

$226

$137

$168

New England

(4)

NEMA

Capacity

2,100

Price

$104

(5)

$85

(5)

$85

(5)

$107

$114

SEMA

Capacity

Price

$104

(5)

$85

(5)

$85

(5)

$95

(5)

$104

(5)

Rest of Pool

Capacity

700

Price

$104

(5)

$85

(5)

$85

(5)

$95

(5)

$104

(5)

NYISO

(6)

Rest of Pool

Capacity

1,100

MISO

(7)

AMIL

Capacity

1,100

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.

2012 Analyst Meeting – Performance that Drives Progress

(1) Reflects owned and contracted generation installed capacity (ICAP) adjusted for mid – year PPA roll offs.

(2) ICAP is net of Eddystone 1&2, Cromby 1&2 (total ~ 933 MW), which are not included PY 11/12 onwards reflecting decision in December 2009 to permanently retire these units.

(3) ICAP for all years beginning PY 11/12 excludes capacity for units to be divested (Brandon Shores, Wagner & Crane ~2,648 MW). Constellation offered these units in PY11/12 - PY 15/16 auctions.

(4) Reflects Qualified Summer Capacity including owned and contracted units.

(5) Price is pro-rated for auctions that clear at the floor price and there is more capacity procured than suggested by the reliability requirement.

(6) Reflects 50.01% ownership in CENG; (7) Does not include wind under PPA.

Distributed Solar

Portfolio Size

•

the

company’s

345

solar

installations

owned

under

construction

(all

expected

operational

by 2013), approximately 59 MW are non-utility scale installations for our commercial, industrial and public

sector customers

Market

Potential

(2)

•

Unsubsidized economic potential for distributed residential and commercial solar PV in the U.S. likely to reach

10 to 12 GW by the end of 2012

Growth Strategy and Objectives

•

Focus

states

with

established

incentives

markets

place

–

MD,

NJ,

and

–

and

where

there

potential

for

new

incentive

markets

–

and

•

Pursue

opportunities

non-Solar

REC

markets

–

CO,

and

–

where

there

increased

interest

solar

(1)

Excludes Antelope Valley Solar Ranch One (230 MW), Sacramento Municipal Utility District (30 MW), City Solar Project (10 MW) and Maryland Generating Clean Horizons (16 MW).

(2)

Source:

McKinsey,

“Solar

Power:

Darkest

Before

Dawn”

published

April

2012.

2012 Analyst Meeting – Performance that Drives Progress

ExGen Disclosures

Gross Margin Category ($ MM)

2012

(2)

2013

2014

Open Gross Margin

(including South, West & Canada hedged GM)

(3,4)

$4,300

$5,800

$6,250

Mark to Market of Hedges

(5)

$3,150

$1,450

$550

Power New Business / To Go

$200

$550

$850

Non-Power Margins Executed

$200

$100

$50

Non-Power New Business / To Go

$200

$500

$550

Total Gross Margin

$8,050

$8,350

$8,200

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

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

(3) Excludes Maryland assets to be divested.

Reference Prices

(6)

2012

2013

2014

Henry Hub Natural Gas ($/MMbtu)

$2.47

$3.45

$3.87

Midwest: NiHub ATC prices ($/MWh)

$26.71

$30.28

$32.45

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

$32.70

$37.93

$40.37

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$11.10

$9.19

$8.50

New York: NY Zone A ($/MWh)

$26.99

$31.40

$33.46

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

ALQN Gas, 7.5HR, $0.50 VOM

$5.98

$4.66

$3.50

(4) Includes CENG Joint Venture.

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

(6) Based on April 30, 2012 market conditions.

2012 Analyst Meeting – Performance that Drives Progress

(1)

ExGen Disclosures

Generation and Hedges

2012

(1)

2013

2014

Exp. Gen (GWh)

(4)

219,900

218,400

210,200

Midwest

101,800

97,900

97,800

Mid-Atlantic

(2,3)

71,300

74,100

72,000

ERCOT

19,900

18,800

16,100

New York

(3)

13,400

10,500

New England

13,500

14,200

13,800

% of Expected Generation Hedged

(5)

97-100%

73-76%

41-44%

Midwest

94-97%

77-80%

44-47%

Mid-Atlantic

(2,3)

105-108%

74-77%

45-48%

ERCOT

89-92%

56-59%

34-37%

New York

(3)

91-94%

69-72%

20-23%

New England

94-97%

66-69%

27-30%

Effective Realized Energy Price ($/MWh)

(6)

Midwest

$41.00

$39.50

$37.00

Mid-Atlantic

(2,3)

$53.00

$49.00

ERCOT

$8.50

$6.00

$3.00

New York

(3)

$45.00

$37.00

$37.50

New England

(7)

$8.00

$8.50

$3.50

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

Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity. Expected generation is based upon a

simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options.

Expected generation assumes 10 refueling outages in 2012 and 2013 and 11 refueling outages in 2014 at Exelon-operated nuclear plants and Salem but excludes CENG. Expected

generation assumes capacity factors of 93.5%, 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.

2012 Analyst Meeting – Performance that Drives Progress

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges)

(1, 4)

2012

2013

2014

Henry Hub Natural Gas ($/MMbtu)

(2)

+ $1/Mmbtu

$(70)

$155

$570

$1/Mmbtu

$85

$(130)

$(505)

NiHub ATC Energy Price

+ $5/MWh

$20

$105

$295

$5/MWh

$(10)

$(105)

$(290)

PJM-W ATC Energy Price

(2)

+ $5/MWh

$(20)

$90

$205

$5/MWh

$25

$(90)

$(200)

NYPP Zone A ATC Energy Price

+ $5/MWh

$10

$25

$45

$5/MWh

$(10)

$(25)

$(45)

Nuclear Capacity Factor

(3)

+/-

$25

+/-

$40

+/-

$40

(1) Based on April 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.

2012 Analyst Meeting – Performance that Drives Progress

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

$7,800

$8,900

$8,000

$9,500

$7,200

2012 Analyst Meeting – Performance that Drives Progress

(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 April 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.

ExGen Disclosure Overview

Continue

provide

transparency

our

ExGen

disclosures

with

modified

and

expanded

framework that incorporates new business lines and regions

•

Continue to provide open gross margins, expected generation, hedge %, reference prices and effective realized

energy prices (EREP)

Also provide Mark-to Market (MtM) value of all hedges on a consolidated basis

•

Consider

retail

and

wholesale

load

alternate

channel

market

our

generation.

such,

executed

sales

are regarded as a hedge and thus flow into MtM, EREP and hedge percentage

Provide volume targets and track sales execution versus targets on an annual basis

•

Introduction of new gross margin categories

•

In addition to Open Gross Margin and MtM of hedges, gross margins will be provided for the following categories -

Power New Business:

Gross margins from future hedging activity via retail, wholesale or structured

transaction/mid-marketing activities. Once power sales are executed, these flow into MtM via EREP

Non Power New Business: Gross margins from planned sales from business activities not related to hedging

power

production,

such

Load

Response,

Energy

Efficiency,

Retail

and

Wholesale

Gas,

Proprietary

Trading

(1)

etc.

Once

sales

are

executed,

gross

margins

will

flow

“Non

Power

Executed”

category.

Non Power Executed: Contracted gross margin associated with business activities not directly linked to production

or sale of power

•

Introduction of new regions

To reflect our expanded national presence, New England, New York, and South, West & Canada regions have been

added to Midwest, Mid-Atlantic and ERCOT

Hedged gross margins for South, West & Canada will be included within the consolidated “Open Gross Margin”

estimate

The other five regions will have corresponding expected generation, hedge %, reference prices and EREP

Maintain ability to value generation fleet on an open and hedged basis

No separate gross margins for commercial load, but will disclose volume targets and sales execution

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

2012 Analyst Meeting – Performance that Drives Progress

ExGen Disclosure Overview

Gross Margin Categories ($ MM)

For all regions, three years forward

General Description

Open Gross Margin

Value of generation at current market prices, excluding the impact of any near-

term hedges

Mark to Market of Hedges

Mark-to-market value of transactions associated with hedging open generation

position (power or fuel hedges, including executed retail/wholesale electric load)

Power New Business / To Go

New category of gross margins for future hedging activity via retail, wholesale or

structured transaction / mid marketing activities.

Non-Power Margins Executed

New category for contracted gross margin associated with business activities not

directly linked to production or sale of power

Non-Power New Business / To Go

New category for gross margins from planned sales from business activities not

related to hedging power production

Total Gross Margin

Sum total of each of the five gross margin categories

Generation & Hedges

General Description

Expected Generation (GWh)

Anticipated output from owned or contracted generating capacity

% of Expected Generation Hedged

Physical or financial hedges against power output

Effective Realized Energy Price

Close proxy for the hedged power price or spark, and when used in conjunction

with the reference price and hedged MWh yields the MtM of hedges.

Retail & Wholesale Volumes

General Description

Electric load target & contracted volumes

Estimate of load sales target and sales executed from all load

channels

Retail gas target

Estimate of gas sales target

2012 Analyst Meeting – Performance that Drives Progress

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”

“Non power executed”

over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

Open Gross

Margin

•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

Hedges

(2)

•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

“Power”

New

Business

•Retail, Wholesale

planned electric

sales

•Portfolio

Management

new business

•Mid marketing

new business

“Non Power”

Executed

•Retail, Wholesale

executed gas

sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

“Non Power”

New Business

•Retail, Wholesale

planned gas

sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

(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 andnot move to “Non power” executed category.

2012 Analyst Meeting – Performance that Drives Progress

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

$5.8 billion

(B)

Expected Generation (TWh)

97.9

74.1

18.8

13.4

14.2

(C)

Hedge % (assuming mid-point of range)

78.5%

75.5%

57.5%

70.5%

67.5%

(D=B*C)

Hedged Volume (TWh)

76.9

55.9

10.8

9.4

9.6

(E)

Effective Realized Energy Price ($/MWh)

$39.50

$49.00

$6.00

$37.00

$8.50

(F)

Reference Price ($/MWh)

$30.28

$37.93

$9.19

$31.40

$4.66

(G=E-F)

Difference ($/MWh)

$9.22

$11.07

($3.19)

$5.60

$3.84

(H=D*G)

Mark-to-market

value

hedges

million)

(1)

$715 million

$625 million

($35) million

$55 million

$40 million

(I=A+H)

Hedged Gross Margin ($ million)

$7,200 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

$8,350 million

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

2012 Analyst Meeting – Performance that Drives Progress

Constellation Energy Nuclear Group (CENG) Background

result

Exelon’s

equity

interest

CENG,

PPA

contracts

between

CENG

and

parties

and

the

PPA

between

CENG and ExGen, some background on CENG and how CENG gross margins and earnings are reflected in ExGen

disclosures and other financial statements.

Calvert 1&2

NMP 1

NMP 2

(1)

Ginna

(2)

Ownership Interest

Total Plant Capacity

1, 750 MW

620 MW

1,138 MW

581 MW

Ownership Split

100% CENG

82% CENG / 18% LIPA

100% CENG

ExGen Ownership (50.01% of CENG)

875 MW

310 MW

466.5 MW

290.5 MW

PPA structure (% output)

CENG Legacy PPA with Utilities

See footnote 1

90%

< June 2014

> June 2014

CENG PPA with Parents

100%

10%

< June 2014

100%

> June 2014

CENG PPA with Parents

year

contract

extendable

end

each

year

for

additional

year

Market

based

pricing

and

monthly,

rolling

year

hedge

profile

(100%,

60%,

30%)

2012

2013

2014

2015

(% of uncommitted output)

EDF Trading

N.A.

ExGen

N.A.

(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.

2012 Analyst Meeting – Performance that Drives Progress

Constellation Energy Nuclear Group (CENG) Background

•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)

•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

ExGen Disclosures

Forward Estimates

Financial Statements

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

Actuals

2012 Analyst Meeting – Performance that Drives Progress

Drive Competition and Choice

We believe in the value competitive energy markets bring to our customers via

choice, innovation and savings

Retail Markets

Wholesale Markets

Perfect Core Markets

Support continued growth of competitive retail choice

for energy and services in restructured states

Defend Open Markets

Oppose and defeat efforts to limit competitive retail

choice for energy and services

Support Transparent Pricing Mechanisms

Promote the establishment of market rules that

provide transparent price signals for energy and

capacity and allow a level playing field for all

providers to compete

Defend Well Functioning Wholesale Markets

Oppose government mandates to subsidize

unneeded, uneconomic generation. Challenge

illegalities of legislative or regulatory construct and

strengthen mitigation measures via FERC (e.g. MOPR)

We champion competitive energy markets to empower our customers and

enhance value for our shareholders

Expand into Restricted or Closed Markets

Enable competitive retail choice for energy & services

in states that limit or are closed to competition

2012 Analyst Meeting – Performance that Drives Progress

Perfecting Existing Retail Energy Markets

•

Opportunity to offer savings for residential class

continues to support switching

–

56% of eligible Illinois load is served by

competitive suppliers

–

Over 200 communities approved ballot

measures to allow municipal aggregation

–

Increased consumer protection encourages

residential consumers to pursue retail supply

Core retail markets are adopting continuous improvements to enhance shopping

and expand customer experience

•

PAPUC moving steadily toward a fully

competitive end state

60% of eligible Pennsylvania load is served

by competitive suppliers

Retail markets assessment targeting

improvements to retail market

Reforms of default service likely to

stimulate retail shopping

•

Exelon looking to build partnership with Maryland

energy stakeholders

56% of eligible Maryland load is served by

competitive suppliers

Web portal for residential electricity price

comparison

•

Steadfast commitment to retail competition

Market volatility creates opportunities for

risk management and enhanced products

and services

High penetration of smart meter

installation and state-wide, standardized

customer data interface creates

opportunities for increased products and

services

Note: PAPUC = Pennsylvania Public Utility Commission; AMI = Advanced Metering Infrastructure.

Illinois

Pennsylvania

Maryland

Texas

2012 Analyst Meeting – Performance that Drives Progress

Defense of Competitive Markets

Our regulatory advocacy efforts are designed to improve the functioning of

competitive markets where they exist and protect against attempts to undermine

price signals

We actively seek opportunities to preserve the integrity of competitive markets

We participate in, or if necessary initiate, proceedings at FERC and at state commissions to

protect

the

efficient

functioning

wholesale

and

retail

markets

and

thwart

attempts

undermine price signals

A current example is our efforts to defend forward capacity markets in PJM from the

exercise of buyer market power by states and load interests

key

component

energy

market

regulation

the

principle

comparability;

all

resources,

whether

existing,

new,

renewable,

fossil

nuclear,

should

have

level

playing

field

and

the

ability to compete on a best price basis. Supply and demand resources should be expected to

meet the same performance criteria if they receive the same compensation

Transmission

critical

element

wholesale

market

liquidity,

seek

develop

facilitate the development of transmission upgrades that reduce congestion around our assets

utilize

public

messaging

and

are

active

coalitions

such

COMPETE

inform

consumers of the value of competition

2012 Analyst Meeting – Performance that Drives Progress

Opportunities to Expand Competitive Retail Energy Markets

•

Considering opening the market to retail choice

–

Customer/supplier advocacy efforts to

encourage policymakers and commission to

take action to re-open retail shopping

–

Recent rate case settlement includes pilot

shopping program

There is a growing interest to open or expand competition in markets with

restricted or non-existent retail choice

•

Increase existing Direct Access Cap

–

Existing program fully subscribed

–

Incremental shopping eligibility fills within

seconds

–

Exit fees remain a challenge

–

Community Choice Aggregation still an option

•

Increase or remove existing 10% electric choice

cap and enable more customers to select their

provider of choice

–

Current program is fully subscribed

–

Legislation introduced to raise shopping cap

to 19% to accommodate current waiting list

•

Significant improvement in retail competition with

the changes in the Electric Security Plan to phase-

in competition but there is room for further

enhancements

–

50% of eligible Ohio load is served by

competitive suppliers

–

Outlook suggests competitive solicitations for

utility standard service offer

–

Utilities moving assets to participate in PJM

RPM market

2012 Analyst Meeting – Performance that Drives Progress

Arizona

California

Michigan

Ohio

Exelon Utilities –

Leveraging Operational Expertise

Exelon Utilities will deliver best-in-class operational and financial performance,

creating greater value for our stakeholders

Achieving best-in-class performance:

•

Set a strategic direction to be among the best

•

Ensure that each utility performs to the highest standards

•

Drive for standardization and sharing of best practices

•

Realize merger synergies across the utilities

•

2011 Revenues: $3.0B

•

Employees: ~3,400

•

Electric customers: 1.2 million

•

Gas customers: 0.7 million

•

Service Territory: 2,300 square miles

•

All-Time Peak Load: 7,616 MW

Baltimore, Maryland

Philadelphia, Pennsylvania

•

2011 Revenues: $3.7B

•

Employees: ~2,400

•

Electric customers: 1.6 million

•

Gas customers: 0.5 million

•

Service Territory: 2,100 square miles

•

All-Time Peak Load: 8,983 MW

•

2011 Revenues: $6.1B

•

Employees: ~5,800

•

Electric customers: 3.8 million

•

Service Territory: 11,300 square miles

•

All-Time Peak Load: 23,753 MW

Chicago, Illinois

2012 Analyst Meeting – Performance that Drives Progress

ComEd –

Growth through Investment that Benefits Customers

Driving innovative legislative and regulatory policy to benefit customers, improve

ratemaking process transparency and enable economic development

Energy Infrastructure Modernization Act (EIMA)

Formula Rate Process

•

Driving investment in electricity infrastructure and

smart meter/smart grid

–

$2.6B over 10 years

•

Making investments that benefit customers

–

Smart meters

–

Distributed automation

–

Storm hardening

•

Monitoring performance standards and metrics

•

Providing for returns on investment

–

Performance-based distribution formula rate

recovery

Distribution:

•

Nov. 2011 initial filing (2010 calendar year + 2011 net

plant additions) proposed $59M decrease in revenue

requirement

–

10.05% ROE (12-month average of the 30-year US

Treasury yield plus 580 basis point risk premium)

–

May 2012 ICC ordered $168M decrease

•

April 2012 first annual update (2011 calendar year +

2012 net plant additions) and 2011 reconciliation filing;

rates effective following January

•

Latest annual formula rate update filed in May 2012,

increased revenue requirement ~$23M

•

Rates effective June 2012

•

FERC approved 11.50% ROE

Economic Development Initiatives

•

Illinois Economic Development Corporation Act

introduced to form public-private partnership

supporting business expansion and creating jobs

•

ComEd’s Economic Development team targeting new

facilities in northern Illinois, including expansion of

data centers, warehouses and manufacturing

Transmission Growth

•

Several upgrade projects planned

–

Burnham to Taylor lines will reinforce transmission

system and increase capacity to reliably serve the

Chicago southern business district

–

Capital spend estimated at ~$150M

–

In-service date planned for June 2014

Note: ICC = Illinois Commerce Commission; FERC = Federal Energy Regulatory Commission

2012 Analyst Meeting – Performance that Drives Progress

Transmission:

PECO –

Competitive Market Initiatives

Supporting competitive procurement markets and evaluating longer-term

opportunities of Act 11

Alternative Ratemaking

Rate Case Update

Electricity Supply Procurement

•

Newly enacted Act 11 (HB 1294) provides a distribution

system improvement charge (DSIC) to support electric

and gas infrastructure investment

Provision for use of fully projected future test year

in rate cases

Requires submission of long-term infrastructure

improvement plan

DSIC capped at 5% of distribution rates

PAPUC DSIC rulemaking underway

Distribution:

•

In Dec. 2010, PAPUC approved settlement of electric

and gas rate cases; no allowed ROE specified

•

Increase in annual service revenue of $225M for electric

and $20M for gas effective 1/1/11

•

No rate cases currently planned; timing of future filings

will depend on load and expense forecasts and

implementation of DSIC

•

PAPUC-approved Default Service Plan (DSP) Program

has 29-mo. term that ends 5/31/13

•

PECO filed second DSP outlining plan from 6/1/13

through 5/31/15

•

As of May 2012, ~28% of total retail customers

purchased energy from alternative suppliers,

representing ~60% of load

•

PAPUC evaluating alternative default service models to

enhance competition

Growth Initiatives

•

Executing $650M Smart Grid investment plan with

surcharge recovery for AMI costs

•

Support potential sales and repurposing of oil refineries

•

Convert oil and propane usage to natural gas

•

Enhance economic development outreach

Note: PAPUC = Pennsylvania Public Utility Commission; AMI = Advanced Metering Infrastructure

2012 Analyst Meeting – Performance that Drives Progress

BGE –

Fulfilling Commitments

Fulfilling commitments to stakeholders with continued focus on

safety and reliability

Commitments to Maryland

Rate Case Update

•

Reinforced ring fencing

•

Maintaining employment and minimum O&M/capital

spending levels for 2 years

•

Rate credit of $100 per residential customer provided

in May/June 2012

•

$113.5M customer investment fund

–

First contribution to fund within 90 days from

merger close

–

MD Public Service Commission (MDPSC) set

June 15 deadline for parties to submit

preliminary proposals for allocating fund

MDPSC Service Quality and Reliability Regulations

•

Effective regulations establish standards in a variety

of service quality and reliability areas

•

Actions expected to add incremental costs beginning

in 2012 to achieve compliance and enhance system

reliability and customer satisfaction

Distribution:

•

Last electric and gas rate cases filed 5/7/10

•

MDPSC approved $31M electric revenue increase with

9.86% ROE and $10M gas increase with 9.56% ROE

•

New rates effective December 2010

•

Plan to file electric and gas cases in 2 half of 2012

with rates effective no more than 210 days after filing

Transmission:

•

Latest annual formula rate update filed in April 2012,

increased revenue requirement ~$18M

•

Rates effective June 2012

•

FERC approved 11.3% ROE

Transmission Growth

•

Transmission-related capital spend expected to total

~$690M through 2016

–

Majority of spend (~$450M) related to RTEP-

mandated projects for system upgrades and

enhancements

Note: RTEP = PJM’s Regional Transmission Expansion Plan

2012 Analyst Meeting – Performance that Drives Progress

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.

Note: ComEd program may be reevaluated given recent ICC rate order.

ComEd will invest ~$1.3B over

the next 10 years

•

Installation of nearly 4M smart electric meters to begin Q4 2012

•

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 formula rate beginning with May 2012

filing

BGE will invest up to $500M

through 2015

•

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

•

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

PECO will invest up to $650M

through 2014

2012 Analyst Meeting – Performance that Drives Progress

Rate Base and ROE Targets

2012E

Long-Term Target

Equity Ratio

~48%

~53%

(3)

Earned ROE

5 -

2012E

Long-Term Target

Equity Ratio

~45%

~53%

(1)

Earned ROE

6 -

Smart meter and smart grid investment will be a key driver of rate base growth

Based on 30-yr.

US Treasury

(2)

($ in billions)

2014E

$5.5

$3.6

$0.7

$1.2

2013E

$5.2

$3.4

$0.7

$1.1

2012E

$5.1

$3.3

$0.7

$1.1

2011A

$4.9

$3.2

$0.7

$1.1

Electric Distribution

Electric Transmission

Gas Delivery

2012E

Long-Term Target

Equity Ratio

~56%

~53%

Earned ROE

11 -

12%

2014E

$9.7

$7.1

$2.5

2013E

$8.7

$6.5

$2.2

2012E

$8.2

$6.1

$2.1

2011A

$8.0

$6.1

$2.0

Distribution

Transmission

2014E

$5.0

$3.1

$0.9

$1.0

2013E

$4.6

$2.9

$0.7

$0.9

2012E

$4.4

$2.8

$0.6

$0.9

2011A

$4.0

$2.6

$0.5

$0.9

Electric Distribution

Electric Transmission

Gas Delivery

10%

(1) Equity component for distribution rates will be the actual capital structure adjusted for goodwill.

(2)

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.

(3)

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%.

Note: 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.

2012 Analyst Meeting – Performance that Drives Progress

ComEd Distribution Formula Rate Plan

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):

•

$168 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

2012 Formula Rate Filing (Docket # 12-0321 filed 4/30/12)

•

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

9.71%

ROE

(2011

Treasury

yield

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)

•

Supported $106M distribution revenue requirement increase relative to Dec. 2012

rates as ComEd initially proposed (Revenue requirement and relative increase will

be updated to reflect 11-0721 rate order)

•

ICC order by year end; rates effective January 2013

Financial Statement Impacts of Formula Rate Process

Summary of Filings

Income Statement:

•

Revenues are based on forecasted calendar year revenue requirement and are accrued and recorded monthly

Cash Flow:

•

Rate adjustments become effective two years after costs are incurred (one year for net plant additions and depreciation expense)

Rate adjustment intended to reconcile revenue requirement and actual costs incurred

Adjustment

for

2011

costs

incurred

(April

30,

2012

filing)

will

take

effect

January

2013

Adjustment for 2012 costs incurred (Spring 2013 filing) will take effect January 2014

Balance Sheet:

•

A regulatory asset is recorded (with interest) to reflect the difference between revenue recognized and revenue billed

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

2012 Analyst Meeting –

Performance that Drives Progress

2010

2011

2012

Costs used for filing

Plant additions used for filing

Formula rate filing

Rates in effect

2011

2012

2013

Costs used for filing

Plant additions used for filing

Formula rate filing

Rates in effect

Illinois Power Agency (IPA) RFP Procurement

Note: Chart is for illustrative purposes only.

ATC = around-the-clock; REC = renewable energy credit; LT Ren = long-term renewable energy; RS = rate stability

Financial Swap Agreement with ExGen

(ATC baseload energy –

notional quantity 3,000 MW)

•

Results of Rate Stability Standard Product Procurements held February 2012:

Effective ATC of $32.57/MWh for 3 winning Standard Product suppliers for the 2013-14

plan-year.

Prices increase 2.5% annually beginning 6/1/14

Contracts are for 450MW ATC through 12/31/17

•

Results of REC Rate Stability Procurement held February 2012:

Procured 2.7M RECs through December 2017

Included solar, wind and other qualified renewables

Average price = $1.67/REC

•

Results of Spring Standard Product Procurement held April 2012:

4 winning Standard Product suppliers for modest volumes within the 2012/13 and

2014/15 plan-years

•

Results of Spring REC Procurement held May 2012:

Procured 1.3M RECs

Included wind and other qualified renewables

Average price = $0.88/REC

Delivery

Period

Peak

Off-Peak

June 2011 -

May 2012

5,118

4,001

June 2012 -

May 2013

1,129

358

June 2013 -

May 2014

6,494

6,062

Volume procured in 2011 IPA

Procurement (GWh)

Delivery

Period

Peak

Off-Peak

June 2012 -

May 2013

235

176

June 2013 -

May 2014

June 2014 -

May 2015

308

Volume procured in Spring 2012

IPA Procurement (GWh)

Term

Fixed Price ($/MWh)

1/1/12-12/31/12

$52.37

1/1/13-5/31/13

$53.48

2012 Analyst Meeting – Performance that Drives Progress

PECO Load Trends

Note: C&I = Commercial & Industrial

4Q12

3Q12

2Q12

1Q12

4Q11

3Q11

2Q11

1Q11

Gross Metro Product

Residential

Large C&I

All Customer Classes

Philadelphia

U.S.

Unemployment rate

(1)

8.1%

2012 annualized growth in

gross domestic/metro product

(2)

1.6% 2.1%

(1)

Source:

Dept.

Labor

data

(April

2012)

–

Dept.

Labor

prelim.

data

(March

2012)

–

Philadelphia

(2)

Source: Global Insight (February 2012)

(3)

Not adjusted for leap year

2011

1Q12 2012E

(3)

Average Customer Growth

0.3%

0.5%

0.6%

Average Use-Per-Customer

1.3%

(2.9)%

(2.5)%

Total Residential

1.7%

(2.5)% (1.9)%

Small C&I

(0.7)%

(4.9)%

(2.7)%

Large C&I

(3.3)%

(1.8)% (5.6)%

All Customer Classes

(0.9)%

(2.7)%

(3.3)%

Weather-Normalized Electric Load Year-over-Year

Key Economic Indicators

Weather-Normalized Electric Load

Oil

refinery

closing

estimated

direct

impact

reduce

Large

C&I

and

total

load

2012

by 4.9% and 2.0%, respectively

2012 Analyst Meeting – Performance that Drives Progress

PECO –

Default Service Plan Filing (DSP II)

(1)

FR = Full Requirements;

(2)

FPFR = Fixed-Price Full Requirements

Retention as of: May 22, 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:

•

100% spot-priced FR

(1)

products

•

2011 opt-in FPFR

(2)

product

•

100% of supply procured directly from the PJM spot

market

Medium

Commercial

Current load retained:

18%

•

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

products

•

100% 6-month FPFR products

Small

Commercial

Current load retained:

44%

•

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

10% spot-priced FR products

•

100% 1-year FPFR products

Residential

Current load retained:

73%

•

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

•

A PAPUC order on the filing is expected in mid-October 2012

•

Offers a 6-month opt-in auction program with price at least 5% less than PECO’s expected Price to Compare (PTC) as of 6/1/13

•

Establishes a residential customer referral program for 1-year, fixed price at least 7% below PECO PTC

•

Provides

customer

information

and

referral

programs

for

various

products;

“seamless”

moves

between

properties

2012 Analyst Meeting – Performance that Drives Progress

Incorporates Retail Market Enhancements suggested by PAPUC Order issued 12/15/11:

BGE Load Trends

4Q12

3Q12

2Q12

1Q12

4Q11

3Q11

2Q11

1Q11

Gross Metro Product

Residential

Large C&I

All Customer Classes

Note: C&I = Commercial & Industrial

Baltimore

U.S.

Unemployment rate

(1)

7.1%

8.1%

2012 annualized growth in

gross domestic/metro product

(2)

1.6% 2.1%

2011

1Q12 2012E

(3)

Average Customer Growth

0.2%

0.0%

0.4%

Average Use-Per-Customer

(4.4)%

0.4%

0.0%

Total Residential

(4.3)%

0.4% 0.3%

Small C&I

0.8%

(8.3)%

(0.7)%

Large C&I

2.0%

(0.5)%

0.9%

All Customer Classes

(1.1)%

0.3%

0.7%

Weather-Normalized Electric Load Year-over-Year

Key Economic Indicators

Weather-Normalized Electric Load

2012 Analyst Meeting – Performance that Drives Progress

Note: As approved by the MDPSC, BGE records a monthly adjustment to residential and the majority of its commercial and industrial customers to eliminate the

effect of abnormal weather and usage patterns per customer on distribution volumes, thereby recovering a specified dollar amount of distribution revenues

per customer, by customer class, regardless of changes in consumption levels. Therefore, while these revenues are affected by customer growth, they will not

be affected by actual weather or usage conditions.

(1)

Source:

Dept.

Labor

data

(April

2012)

–

Dept.

Labor

prelim.

data

(March

2012)

–

Baltimore

(2)

Source:

Global

Insight

(February

2012)

–

Moody’s

Analytics

(February

2012)

–

Baltimore

(3)

Not adjusted for leap year

BGE –

Standard Offer Service

•

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

costs

providing

this

service

are

recovered

from

customers

via

Administrative

Charge

included

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: February 2012

Procurement Mix

Class

6/1/11 –

5/31/12

6/1/12 –

5/31/13

Large C&I

(Hourly)

Current load retained:

•

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:

28%

•

100% 3-month FPFR

(1)

products

•

Auction Apr ’11 for Jun ’11 –

Aug ’11

•

Auction Jun ’11 for Sep ’11 –

Nov ’11

•

Auction Oct ’11 for Dec ’11 –

Feb ’12

•

Auction Jan ’12 for Mar ’12 –

May ’12

•

100% 3-month FPFR 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

Small

Commercial

(Type I)

Current load retained:

63%

•

25% 2-year FPFR products

•

Auction Apr ’09 for Oct ’09 –

Sep ’11

•

Auction Oct ’09 for Jun ’10 –

May ’12

•

Auction Apr ’10 for Oct ’10 –

Sep ’12

•

Auction Oct ’10 for Jun ’11 –

May ’13

•

Auction Apr ’11 for Oct ’11 –

Sep ’13

•

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

Residential

Current load retained:

75%

•

25% 2-year FPFR products

•

Auction Apr ’09 for Oct ’09 –

Sep ’11

•

Auction Oct ’09 for Jun ’10 –

May ’12

•

Auction Apr ’10 for Oct ’10 –

Sep ’12

•

Auction Oct ’10 for Jun ’11 –

May ’13

•

Auction Apr ’11 for Oct ’11 –

Sep ’13

•

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

2012 Analyst Meeting – Performance that Drives Progress

Regulatory Schedule

Proposed order for initial

filing (5/1); Final order

(issued 5/30); rates

effective June thru Dec.

Procurements for ATC

supply and RECs for

6/1/13-12/31/17 (Feb.)

ComEd Distribution

Formula Rate

Illinois Power

Agency

Procurement

ComEd

Transmission Rate

Update

Annual update filing

with FERC (5/15);

rates effective June

2012 thru May 2013

First annual update

and reconciliation

filing (4/30)

Rates effective

Jan. thru Dec.

Regular annual

procurement event

(April)

Final order

(by 12/27)

2013

BGE Distribution Rates

PECO Supply

Procurement

BGE Transmission Rate

Update

Annual update filing

with FERC (4/24);

rates effective June

2012 thru May 2013

File case with MDPSC

(2 half of 2012)

Procure DSP I

residential block

supply (April)

BGE Supply

Procurement

Regular

procurement event

(April & June)

Regular

procurement event

(October)

Procure DSP I

residential block

supply (September)

Final DSP II order

(mid-October)

DSIC filing

(tentative)

PECO DSIC Filing

MDPSC order due

210 days after filing

2012

2012 Analyst Meeting – Performance that Drives Progress

Energy Efficiency Progress

Note: EE = energy efficiency; DR = demand response

2012 Analyst Meeting – Performance that Drives Progress

ComEd –

Illinois

PECO –

Pennsylvania

BGE –

Maryland

•Annual savings requirement 0.8% of energy deliveries for year ended

5/31/12; increases annually to 2.0% beginning 6/1/15 and each year

thereafter, subject to spending cap of ~2% of revenues

•EIMA created process that would allow spending above cap for incremental

cost-effective EE approved by the IPA and ICC

•Achieved annual savings goal in each of the first three years and is

projected to achieve goal in year four

•Recovery of EE/DR program costs approved by ICC

•Electric consumption required to be reduced by 1% and 3% by

5/31/11 and 5/31/13, respectively (vs. 6/09–5/10 baseline)

•Exceeded 1% energy use reduction target and is projected to achieve

3% goal in Q4 2012

•Since program inception, more than 1 million MWh energy reduced

and less than 50% of budget target spent

•Recovery of EE/DR program costs approved by PAPUC

•EmPOWER MD statute 15% by 2015 (vs. 2007 baseline); most

ambitious targets of any state

•Making good progress to achieving demand reduction and toward

energy targets, with further potential from smart grid and recent

program filings

•Revenue decoupling mechanism implemented to mitigate impact of

declines in customer consumption

•Recovery of EE/DR program costs approved by MDPSC

Operational Excellence

Continue tradition of operational excellence and continuous improvement

Operator

5-Year Average

5-Year Range

2007

2008

2009

2010

2011

Industry (Excluding Exelon)

Exelon

2008

2007

100

2011

2010

2009

Hydro Equivalent Availability (closer to 100% is better)

2002

2011

2010

2009

2008

2007

2006

2005

2004

2003

Industry (w/o Exelon)

Exelon

Nuclear 2-Yr Production Cost ($/MWh)

(3)

Fossil

and

Hydro

Fleet

Availability

(2)

Range

Nuclear

Fleet

2-Yr

Avg

Capacity

Factor

(2007-2011)

(1)

Industry Leading Refueling Outage Duration

(4)

(1)

Source: Platts Nuclear News, Nuclear Energy Institute and Energy Information Administration (Department of Energy). Exelon metrics exclude CENG & Salem.

(2)

Excludes legacy Constellation asset performance.

(3)

Source: 2011 Electric Utility Cost Group (EUCG) survey. Includes Fuel Cost plus Direct O&M divided by net generation. Exelon metrics exclude CENG & Salem.

(4)

Exelon data excludes Salem & CENG. Exelon’s 2009 average includes 23 days of TMI outage that extended into 2010 for a steam generator replacement.

2012 Analyst Meeting – Performance that Drives Progress

Fossil Fleet Equivalent Forced Outage Rate -

Demand (closer to 0% is better)

NRC Fukushima Related Orders

Working collaboratively with NRC and U.S. Nuclear Industry to invest in long

term enhancements resulting from lessons learned

Tier 1 Staff Requirements

•

Mitigating Strategies:

–

Additional

portable

equipment

purchased

enhance

mitigation

capability

for

beyond-design-

basis events

–

Integrated Plan to be submitted to NRC by February 2013

–

All actions will be implemented across the Exelon fleet by the end of 2016

•

Hardened Vents for Mark I and Mark II Containments:

–

Conceptual design for Mark II containments is in progress and conceptual design for Mark I

containments to begin in August 2012

–

Integrated Plan to be submitted to NRC by February 2013

–

All actions will be implemented across the Exelon fleet by the end of 2016

•

Spent Fuel Pool (SFP) Instrumentation:

–

Conceptual design for upgraded SFP instrumentation is in progress

–

Integrated Plan to be submitted to NRC by February 2013

–

All actions will be implemented across the Exelon fleet by the end of 2016

Exelon expects the costs to comply with NRC requirements to be manageable

2012 Analyst Meeting – Performance that Drives Progress

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 assumed to be 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

Hydro

Wind/Solar/Other

Gas

28%

Oil

Coal

(3)

Nuclear

(2)

55%

2012 Analyst Meeting – Performance that Drives Progress

Combined Company Portfolio

Approx. $200 million of CapEx,

majority of which is at Conemaugh

(Exelon ownership share ~31%)

–

100

Exelon Generation Fleet Overview

(1)

Plant

Location

Owned

Capacity

(MW)

LDA

Hub/Zone

Region for

Disclosure

Mapping

Nuclear

Braidwood

Braidwood,

2,348

Rest of RTO

NiHub

Midwest

Byron

Byron, IL

2,323

Rest of RTO

NiHub

Midwest

Calvert Cliffs I and II

Calvert Co, MD

853

SWMAAC

BGE

Mid-Atlantic

Clinton

Clinton, IL

1,067

n/a

Indiana Hub

Midwest

Dresden

Morris, IL

1,753

Rest of RTO

NiHub

Midwest

LaSalle

Seneca, IL

2,316

Rest of RTO

NiHub

Midwest

Limerick

Twp.,PA

2,312

EMAAC

PECO Zone

Mid-Atlantic

Nine Mile Point I and II

Scriba, NY

782

NYPP

Zone C

New York

Oyster Creek

Forked River, NJ

625

EMAAC

PECO Zone

Mid-Atlantic

Peach Bottom

Peach

Bottom

Twp.,

1,150

EMAAC

PECO Zone

Mid-Atlantic

Quad Cities

Cordova, IL

1,380

Rest of RTO

NiHub

Midwest

R.E. Ginna

Ontario, NY

291

NYPP

Zone B

New York

Salem

Hancock's Bridge, NJ

1,004

EMAAC

PECO Zone

Mid-Atlantic

Three Mile Island

Londonderry Twp, PA

837

MAAC

Whub/MetEd Zone

Mid-Atlantic

Coal

(2)

ACE

Trona, CA

n/a

Other

Conemaugh

New Florence, PA

533

MAAC

Whub/Penelec Zone

Mid-Atlantic

Jasmin

Kern Co, CA

n/a

Other

Keystone

Shelocta, PA

716

MAAC

Whub/Penelec Zone

Mid-Atlantic

POSO

Kern Co, CA

n/a

Other

Gas

Colorado Bend

Wharton, TX

550

Houston

ERCOT

Eddystone 3, 4

Eddystone, PA

760

EMAAC

PECO Zone

Mid-Atlantic

Fore River

North Weymouth, MA

688

ROP-NE

Hub

New England

Gould Street

Baltimore City, MD

SWMAAC

BGE

Mid-Atlantic

Grande Prairie

Alberta, Canada

n/a

Other

Handley 3, 4, 5

Fort Worth, TX

1,265

ERCOT N

ERCOT

Handsome Lake

Rockland Twp, PA

268

MAAC

Whub/Penelec Zone

Mid-Atlantic

Hillabee Energy

Alexander City, Alabama

740

GTC

Other

LaPorte

Laporte, TX

152

ERCOT

Medway

West Medway, MA

105

ISO-NE

Mass Hub

New England

Mountain Creek 6, 7, 8

Dallas, TX

805

ERCOT N

ERCOT

Mystic 7

Charlestown, MA

560

ROP-NE

Hub

New England

Mystic 8,9

Charlestown, MA

1,398

NEMA

Hub

New England

Notch Cliff

Baltimore Co, MD

101

SWMAAC

BGE

Mid-Atlantic

Perryman -Gas

Harford Co, MD

147

SWMAAC

BGE

Mid-Atlantic

Quail Run Energy

Odessa, TX

550

West

ERCOT

Riverside -Gas

Baltimore Co, MD

189

SWMAAC

BGE

Mid-Atlantic

Southeast Chicago

Chicago, IL

296

Rest of RTO

NiHub

Midwest

West Valley

Salt Lake City, UT

200

n/a

Other

Westport

Baltimore Co, MD

116

SWMAAC

BGE

Mid-Atlantic

Wolf Hollow 1, 2, 3

Granbury, TX

705

ERCOT N

ERCOT

Plant

Location

Owned

Capacity

(MW)

LDA

Hub/Zone

Region for

Disclosure

Mapping

Oil

Chester

Chester, PA

EMAAC

PECO Zone

Mid-Atlantic

Conemaugh

New Florence, PA

MAAC

Whub/Penelec Zone

Mid-Atlantic

Croydon

Bristol Twp., PA

391

EMAAC

PECO Zone

Mid-Atlantic

Delaware

Philadelphia, PA

EMAAC

PECO Zone

Mid-Atlantic

Eddystone

Eddystone, PA

EMAAC

PECO Zone

Mid-Atlantic

Falls

Falls Twp., PA

EMAAC

PECO Zone

Mid-Atlantic

Framingham

Framingham, MA

ISO-NE

Mass Hub

New England

Keystone

Shelocta, PA

MAAC

Whub/Penelec Zone

Mid-Atlantic

Moser

LowerPottsgrove

Twp.,

EMAAC

PECO Zone

Mid-Atlantic

Mystic Jet

Charlestown, MA

ROP-NE

Hub

New England

New Boston

South Boston, MA

ISO-NE

Mass Hub

New England

Perryman -

Oil

Harford Co, MD

200

SWMAAC

BGE

Mid-Atlantic

Philadelphia Road

Baltimore Co, MD

SWMAAC

BGE

Mid-Atlantic

Richmond

Philadelphia, PA

EMAAC

PECO Zone

Mid-Atlantic

Riverside -

Oil

Baltimore Co, MD

SWMAAC

BGE

Mid-Atlantic

Salem

Hancock's Bridge, NJ

EMAAC

PECO Zone

Mid-Atlantic

Schuylkill

Philadelphia, PA

199

EMAAC

PECO Zone

Mid-Atlantic

Southwark

Philadelphia, PA

EMAAC

PECO Zone

Mid-Atlantic

Wyman

Yarmouth, ME

ISO-NE

Maine Zone

New England

Hydro

Conowingo

Harford Co., MD

572

EMAAC

PECO Zone

Mid-Atlantic

Malacha

Muck Valley, CA

n/a

Other

Muddy Run

Lancaster, PA

1,070

EMAAC

PECO Zone

Mid-Atlantic

Safe Harbor

Safe Harbor, PA

278

MAAC

Whub

Mid-Atlantic

Wind

AgriWind

Bureau

Co.,

IL Hub/Indiana Hub

Midwest

Blue Breezes

Faribault Co., MN

MinnHub

Midwest

Bluegrass Ridge

Gentry Co., MO

SERC

Other

Brewster

Jackson Co., MN

MinnHub

Midwest

Cassia

Twin Falls Co., ID

WECC/Mid-C

Other

Cisco

Jackson Co., MN

MinnHub

Midwest

Conception

Nodaway

Co.,MO

SERC

Other

Cow Branch

Atchinson

Co.,MO

SERC

Other

Cowell

Pipestone Co., MN

MinnHub

Midwest

CP Windfarm

Faribault Co., MN

MinnHub

Midwest

Criterion

Oakland, MD

Whub

Mid-Atlantic

Echo 1

Umatilla Co., OR

WECC/Mid-C

Other

Echo 2,3

Morrow Co., OR

WECC/Mid-C

Other

Ewington

Jackson Co., MN

MinnHub

Midwest

Exelon Wind 1-11

Various Counties, TX

180

SPP

Other

Greensburg

Kiowa Co., KS

SPP

Other

Harvest

Huron Co., MI

MichHub

Midwest

(1)

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

(2)

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

2012 Analyst Meeting – Performance that Drives Progress

101

Exelon Generation Fleet Overview (cont’d)

(1)

Plant

Location

Owned

Capacity

(MW)

LDA

Hub/Zone

Region for

Disclosure

Mapping

Wind (cont’d)

High Plains

Moore Co., TX

SPP

Other

Loess Hills

Atchinson Co., MO

SERC

Other

Marshall

Lyon Co., MN

MinnHub

Midwest

Michigan Wind 1 and 2

Bingham Twp., MI

159

MichHub

Midwest

Mountain Home

Elmore Co., ID

WECC/Mid-C

Other

Norgaard

Lincoln Co., MN

MinnHub

Midwest

Threemile Canyon

Morrow Co., OR

WECC/Mid-C

Other

Tuana Springs

Twin

Falls

Co.,

WECC

Other

Wolf

Nobles Co., MN

n/a

Midwest

Solar

City Solar

Chicago, IL

Rest of RTO

NiHub

Midwest

Constellation Solar

Various

n/a

Other

SEGS IV-VI

Kramer Junction, CA

n/a

Other

Biomass

Chinese Station

Jamestown, CA

n/a

Other

Fresno

Fresno, CA

n/a

Other

Rocklin

Placer Co, CA

n/a

Other

Landfill Gas

Fairless Hills

Falls Twp, PA

EMAAC

PECO Zone

Mid-Atlantic

Pennsbury

Falls Twp., PA

EMAAC

PECO Zone

Mid-Atlantic

Waste Coal

Colver

Colver Township, PA

n/a

Mid-Atlantic

Panther Creek

Nesquehoning, PA

n/a

Mid-Atlantic

Sunnyside

Sunnyside, UT

n/a

Other

Total, Net of Physical Mitigation

(1)

34,662

Physical Market Mitigation

Brandon Shores

Anne Arundel Co, MD

1,273

SWMAAC

BGE

Mid-Atlantic

H. A. Wagner

Anne Arundel Co, MD

976

SWMAAC

BGE

Mid-Atlantic

C. P. Crane

Anne Arundel Co, MD

399

SWMAAC

BGE

Mid-Atlantic

(1)

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

2012 Analyst Meeting – Performance that Drives Progress

102

Post Fukushima: NRC Requirements and Anticipated Implications

Requirement

EXC Actions Required

Proactive Steps Taken

Mitigating strategies for beyond-

design-basis events

•

Develop procedures and plant

modifications to implement additional

requirements for mitigation of beyond

design basis events

•

Validated existing strategies

•

Performed preliminary analysis to identify

strategy improvements

•

Purchased additional portable equipment

Reliable hardened vents for Mark

I and Mark II containment

•

Install new hardened vents for Mark II

containments, upgrade existing Mark I

hardened containment vents

•

Validated existing venting procedures

•

Began conceptual design for installation of

Mark II containment vents

Spent Fuel Pool (SFP)

instruments

•

Upgrade existing SFP monitoring

capability to meet new requirements

•

Additional controls established for SFP

cooling equipment monitoring and

equipment availability

Tier 1 Staff Requirements

•

Significant activity is in progress in preparation for seismic and external flooding walkdowns which

are required under additional NRC requests for information and are scheduled to be completed by

the end of November 2012

•

In March, NRC issued its final Tier 1 requirements based on NRC task force and staff

recommendations

Exelon’s actions and commitments are aligned with coordination that is taking

place across the U.S. nuclear industry

2012 Analyst Meeting – Performance that Drives Progress

103

Growing Clean Generation with Uprates

Station

Base Case

Max Potential

MW Online to

Date

Year of Full

Operation

by Unit

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

1,287

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)

2012 Analyst Meeting – Performance that Drives Progress

(3)

(1)

Exelon’s Uprate Program Is a Pragmatic Approach to

Nuclear Growth

Key Considerations

Exelon

Uprate

Program

(2)

New

Merchant

Nuclear

(3)

Overnight cost

(1)

$2,700 -

$2,900 / KW

$4,500 -

$6,200 / KW

Time to market

2 -

6 years

At least 9 years

O&M cost

No additional O&M cost

$11 -

$15 / MWh

Ancillary costs –

NDT, maintenance

capital, etc

Minimal ancillary costs

$ 2 -

$3 / MWh

Asset diversification

Operational risk spread amongst several

assets

Operational risk concentrated to single

asset

Market diversification

Diversify revenue source amongst

several power markets / regions

Market risk concentrated to one

location

Market timing risk

Lower risk due to phased execution

Risk of hitting low commodity cycle

Regulatory approval

1 -

2 years review period

3 -

year minimum review period

Financing Source

Leverage balance sheet strength

Loan guarantees needed

Development flexibility

Ability to respond to changing market /

financial conditions

Much less flexibility to cancel

(1)

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

(2)

Includes deferral of LaSalle EPU.

(3)

Cost estimates are based on Exelon’s internal projections for new merchant nuclear.

Exelon’s uprate program is a proven approach to add clean generation to

the

portfolio, and it provides flexibility to respond to changing economic and

market conditions

105

2012 Analyst Meeting – Performance that Drives Progress

Peach Bottom Uprate Program

•

MW Recovery

•

EPU

106

Unit 2

Unit 3

Uprate Project

Increase

(1)

Online

Date

Increase

(1)

Online

Date

Status

MW Recovery -

Low Pressure

Turbine Retrofit

4Q 2012

4Q 2011

Unit 3 complete

Unit 2 in progress

MW Recovery -

Adjustable Speed

Drives

4Q 2014

4Q 2015

Scheduled to start in 2012

EPU

1Q 2015

1Q 2016

Design 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 2012 and 2016

2012 Analyst Meeting – Performance that Drives Progress

–

Low Pressure Turbine Retrofit in progress with

installation complete for Unit 3 and

completion for Unit 2 planned in 2012

–

Replacement of Reactor Recirculation Pump

Motor Generator sets with energy efficient

Adjustable Speed Drives in 2014 and 2015

–

Funding approved for design work

–

Full project authorization currently in progress

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

(2)

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%

2018

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

(4)

Dry Cask

R.E. Ginna, NY

(Unit 1)

PWR

Concrete/Steel Lined

Lake Ontario

Renewed / 2029

100% CENG

(4)

Dry Cask

Limerick, PA

(Units 1 and 2)

BWR

Concrete/Steel Lined / Mark II

Schuylkill River

Filed application in June 2011 (decision

expected in 2013) / 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

(4)

82% CENG

(4)

, 18% Long

Island Power Authority

Dry Cask

(Summer 2012)

Oyster Creek, NJ

(Unit 1)

BWR

Steel Vessel / Mark I

Barnegat Bay

Renewed / 2029

(3)

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.

109

2012 Analyst Meeting – Performance that Drives Progress

(1)

Effectively Managing Nuclear Fuel Costs

(1)

Projected Exelon (100%) Uranium Demand

Components of Fuel Expense in 2012

2012 –

2015: 100% hedged in volume

2016:

~80% hedged in volume

2017:

~55% hedged in volume

2017E

2016E

2015E

2014E

2013E

2012

Enrichment

31%

Tax/Interest

Conversion

Uranium

36%

Nuclear Waste

14%

Fabrication

14%

100

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. Data assumes LaSalle’s deferral of EPU.

110

200

400

600

800

1,000

1,200

1,400

2017E

1,205

2016E

1,174

2015E

1,110

2014E

1,068

2013E

992

2012

927

Nuclear Fuel Capex

Nuclear Fuel Expense (Amortization + Spent Fuel)

Projected Exelon Average Uranium Cost vs. Market

2012 Analyst Meeting – Performance that Drives Progress

Projected Exelon (100%) Uranium Demand

Components of Fuel Expense in 2012

Projected Total Nuclear Fuel Spend

(2)