8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

November 10, 2014

Date of Report (Date of earliest event reported)

Commission File Number	Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
1-16169	EXELON CORPORATION (a Pennsylvania corporation)	23-2990190
	10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company)	23-3064219
	300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation)	36-0938600
	440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation)	23-0970240
	P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000
1-1910	BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland corporation)	52-0280210
	2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (410) 234-5000

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On November 11-13, 2014, Exelon Corporation (Exelon) will participate in the Edison Electric Institute Financial Conference. Attached as Exhibit 99.1 to this Current Report on Form 8-K are the presentation slides and handouts to be used at the conference.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Description
99.1	Presentation slides and handouts

* * * * *

This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, and Baltimore Gas and Electric Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

This presentation includes 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 these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2013 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 22; (2) Exelon’s Third Quarter 2014 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 18; and (3) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

EXELON CORPORATION

/s/ Jonathan W. Thayer

Jonathan W. Thayer

Senior Executive Vice President and Chief Financial Officer

Exelon Corporation

EXELON GENERATION COMPANY, LLC

/s/ Bryan P. Wright

Bryan P. Wright

Senior Vice President and Chief Financial Officer Exelon Generation Company, LLC

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and

Treasurer

PECO Energy Company

BALTIMORE GAS AND ELECTRIC COMPANY

/s/ David M. Vahos

David M. Vahos

Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

November 10, 2014

EXHIBIT INDEX

Exhibit No.	Description
99.1	Presentation slides and handouts

EX-99.1

Edison Electric Institute

Financial Conference

November 12 –

13, 2014

Exhibit 99.1

*

*

*

*

*

*

*

*

*

*

1

2014 EEI Financial Conference

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 2013 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 22; (2) Exelon’s Third Quarter 2014 Quarterly Report on

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

Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and

Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial

Statements: Note 18; and (3) other factors discussed in filings with the SEC by the

Registrants. Readers are cautioned not to place undue reliance on these forward-

looking statements, which apply only as of the date of this presentation. None of the

Registrants undertakes any obligation to publicly release any revision to its forward-

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

presentation.

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2014 EEI Financial Conference

Our Strategy

Exelon

Corporation

Exelon Utilities

Exelon Generation

Attributes

Value Drivers

Guiding Principle

Corresponding Actions

•

Regulated growth

•

Dividend stability

•

Operational excellence

•

Earnings growth

•

Dividend yield

•

Public policy advocacy

General Characteristics

Role & Focus 

•

Provide dividend coverage and

stable earnings growth platform

•

Invest in regulated growth

opportunities

•

Competitive growth

•

Commodity exposure

•

Operational excellence

•

Free cash flow growth

•

Power prices/volatility

•

Public policy advocacy

•

Diversify business to provide

growth and reduce earnings

volatility

•

Invest in existing and adjacent

markets and introduce new

products and services

Exelon’s Strategy

Leverage the integrated business model to create value and

diversify our business

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2014 EEI Financial Conference

Driving Value at Exelon Utilities

Providing Material EPS Accretion

(1)

Significant Rate Base Growth

(2)

Operational Excellence

Creating

the Leading Mid-Atlantic Utility

•

Continue first quartile operating performance in

areas such as reliability and customer satisfaction

•

Achieve financial performance targets

•

Leverage standardization, common platforms and

best practices across operating companies

•

Improved operational performance at ComEd,

PECO and BGE since the merger

IL

Chicago

$0.00

$0.90

$1.70

$1.60

$1.40

$1.30

$1.20

$1.50

$1.10

$1.00

2017

$1.55

2016

2015

$1.40

2014

$1.25

$1.50

$1.20

$1.25

$0.95

$1.10

$21.8

$23.2

$24.7

$8.1

$8.8

$9.6

$20.1

$34.3

+15%

2017

2016

$32.0

2015

$29.9

2014

+49%

Exelon

PHI

(1)

Earnings guidance is for Exelon Utilities  only and does not include PHI utilities

(2)

Denotes year end rate base

$20.1

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2014 EEI Financial Conference

Driving Value at Exelon Generation

Capacity Prices

Capacity

Performance

Role of Demand

Response

Shift in Demand

Curve

Power Prices

Carbon

Heat Rates

Liquidity

Taking action to create value today while preparing for a different future

Guiding Principles:

Preserve the value of our core

business . . .

•

Operate the nuclear fleet safely and

reliably

•

Provide clean, reliable and affordable

energy

•

Manage portfolio through hedging and

generation to load matching

. . . while strategically growing and

diversifying the business

•

Leverage competencies for growth

•

Identify and capitalize on emerging

trends and technologies by being a first

mover

•

Invest in business diversification to

position the company for the future

•

Use full arsenal of financing tools

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2014 EEI Financial Conference

IL -

Market Based Solution

Possible Market Based Solutions

Benefits of Exelon’s Fleet to Illinois

Note: 2015 Legislative timeline is illustrative

•

•

•

•

•

•

Illinois could enact legislation to create a Clean Energy

Standard (CES)

A CES is a requirement that all customers purchase a

minimum percentage of “clean”

generation. The concept is

similar to a Renewable Portfolio Standard with the distinction

that the set of resources which qualify under the CES include

all zero or low CO

2

emission generators

Clean energy credits would be traded in a similar fashion to

how renewable energy credits (RECs) are traded today

Illinois could enact legislation to create a carbon trading

program or join an existing program like the Regional

Greenhouse Gas Initiative (RGGI)

Carbon trading programs put a cap on carbon emissions

and each fossil fuel generator must submit a carbon

allowance for each tonne of carbon the plant emits

These allowances are traditionally auctioned with the

proceeds going to the state treasury. Some of the funds may

be provided to customers to offset any rate impacts or

dedicated to other energy-related programs

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2014 EEI Financial Conference

Exelon is positioned for a strong future

Operational Excellence

Financial Strength

Portfolio Optimization

Strategic Diversification

Strong

Integrated

Business

Model

We

operate

our

nuclear

fleet

at

world

class

levels,

and

deliver

first

quartile

performance

at

the

utilities

We

maintain

a

strong

balance

sheet

and

the

ability

to

raise

and

deploy

capital

for

growth

We

manage

commodity

market

volatility

and

optimize

earnings

through

our

hedging

strategy

We

diversify

our

business

to

capitalize

on

evolving

industry

trends

over

the

long

term

We

leverage

our

core

competencies

to

grow

our

regulated

and

competitive

business

while

expanding

to

adjacent

markets

Core Strength

Strategic Actions

Public Policy Advocacy

We

advocate

for

policies

that

strengthen

competitive

markets,

value

the

grid

and

enhance

the

value

of

clean,

reliable

generation

Key Developments

*

*

*

*

*

8

2014 EEI Financial Conference

Capacity Performance (CP) Impact on PJM Fleet

Source: NorthBridge Analysis; includes FRR resources/Loads; PJM proposal is to fully procure CP for 2016/17 and 2017/18 but to incrementally procure up to 10 GW of base

capacity for 2015/16.  Potential 2015/16 all-in CP procurement quantity shown for comparison purposes.

Exelon’s fleet is well positioned to benefit from Capacity Performance due to

significant investments in reliability

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2014 EEI Financial Conference

Asset Divestitures --

$ 1.4 Billion in Proceeds to Date

Retail

EXC Service Territory

PHI Service Territory

(1)

Represents EXC’s portion of the asset

Note:  CF: Capacity Factor through September 2014; Safe Harbor capacity factor through July 2014

Gas CT / 200 MW

2014 CF –

8%

Signed with Wayzata on

9/20

West Valley

Gas CT / 477 MW

2014 CF –

17%

Signed with Starwood

9/26

Quail Run

Gas / Oil CCGT / 688

MW

2014 CF –

61%

Signed with Calpine on

8/22

Fore River

Hydro / 277 MWZ

(1)

2014 CF –

38%

Transaction closed on

8/8 with Brookfield

Safe Harbor

Coal / 1245 MW

(1)

2014 CF –

74% / 82%

Signed with ArcLight on 10/24

Keystone / Conemaugh

Gas CCGT / 684 MW

2014 CF –

74%

Currently in sale

process

Hillabee

To date, Exelon has signed definitive agreements on five non-core

assets representing a total  of nearly $1.4 billion of after-tax sales

proceeds upon closings; This excludes proceeds from Hillabee,

which is currently on the market

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2014 EEI Financial Conference

ExGen Disclosures -

Asset Sale Impacts

Gross

Margin

Category

($M)

2015

2016

2017

Open Gross Margin

(including South, West & Canada hedged GM)

6,750

6,500

6,650

Mark to Market of Hedges

-

150

150

Power New Business / To Go

400

550

750

Non-Power Margins Executed

100

50

50

Non-Power New Business / To Go

300

350

350

Total Gross Margin

(2,5)

7,550

7,600

7,950

Impact of Removing Keystone / Conemaugh

(150)

(100)

(100)

Pro-forma Total Gross Margin excluding Keystone / Conemaugh

7,400

7,500

7,850

Impact

of

Announced

Assets

Sales

During

2014

(1)

2015

2016

2017

OGM Impact Q2 (Safe Harbor)

(50)

(50)

(50)

OGM Impact Q3 (Fore River, Quail Run, West Valley)

(100)

(100)

(100)

OGM Impact Q4 (Keystone / Conemaugh)

(150)

(100)

(100)

Total Impact to OGM from Announced Asset Sales

(300)

(250)

(250)

O&M

100

100

100

D&A

100

100

100

EBIT

(100)

(50)

(50)

CapEx

(50)

(50)

(100)

EPS Reduction

(6)

($0.06-$0.08)

($0.02-$0.04)

($0.02-$0.04)

(1)

Rounded

to

nearest

$50M

(2)

Total

Gross

Margin

(Non-GAAP)

is

defined

as

operating

revenues

less

purchased

power

and

fuel

expense,

excluding

revenue

related

to

decommissioning,

gross

receipts

tax,

Exelon

Nuclear

Partners

and

variable

interest

entities.

Total

Gross

Margin

is

also

net

of

direct

cost

of

sales

for

certain

Constellation

businesses

(3)

Excludes

EDF’s

equity

ownership

share

of

the

CENG

Joint

Venture

(4)

Mark

to

Market

of

Hedges

assumes

mid-point

of

hedge

percentages

(5)

Reflects

the

divestiture

impact

of

Fore

River,

Quail

Run

and

West

Valley.

Does

not

include

divestiture

of

Keystone/Conemaugh

or

the

Integrys

Acquisition

(6)

EPS

impact

does

not

include

impact

of

investing

the

proceeds

from

the

sale.

As

a

reminder

these

sales

were

included

in

the

accretion

calculation

for

the

PHI

transaction

(3,4)

(3)

(1)

11

2014 EEI Financial Conference

2014 EEI Financial Conference

State of the Art Combined Cycles in ERCOT

•

Efficient:

Two of the cleanest, most efficient

Combined Cycle Gas Turbines (CCGT) in the

nation

•

Cost Effective:

Simplified design provides for

easier construction and maintenance, making

these units among the most predictable and

least costly to operate and maintain in the

industry

•

Environmental:

Plants

use

air

cooling

which

mitigates water constraint issues

•

Fast

Ramp:

100

MW/Minute

ramp

rate

(market

ramp rate ~50 MW/minute)

WEST

SOUTH

NORTH

HOUSTON

Wolf Hollow

Colorado Bend

Key Facts

Sites

Wharton County, TX

Granbury, TX

Total Capacity

~2,200MW

(Wolf Hollow: 1,085MW / Colorado

Bend: 1,104MW)

Construction Cost

~$700/kW

Heat Rate

~6,500 mmBtu/MWh

OEMs

GE and Alstom

EPC

Zachry

Cooling System

Air Cooled

Construction Start

2015

Commercial Operation

By Summer 2017

ERCOT Dispatch

12

2014 EEI Financial Conference

2014 EEI Financial Conference

Distributed Energy Platform

Distributed Energy is a Fast Growing Business

•

On-site generation, including solar, quadrupled since 2006

(Wall Street Journal 2013)

•

US C&I customers are spending ~$5-6 billion per year on self-

generation and energy efficiency programs (Bloomberg 2013)

•

Revenues from Distributed Generation are expected to reach

$12.7 billion by 2018 (Pike Research, Navigant, 2012)

Distributed Energy

Supports Exelon’s

Strategy:

Grow

Organically & 

Through M&A

Participate in 

Emerging Trends                       

& Technologies

Commercializing

emerging

and

potentially

disruptive

energy

technologies

to

diversify

existing

technology

base

Acquiring

long

term

retail

customers

through

a

PPA

or

other

long-term

agreement

Attract

and

acquire

new

customers

with

unique

offering

Provides

adaptive

growth

in

an

emerging

market

sector

Bolstering

existing

relationships

with

customers

to

help

achieve

reliability

or

sustainability

objectives

Integrating

supply

&

demand

side

solutions

Key Attributes of Financial Value

Backup

Generation

Battery

Storage

Co-Generation

Fuel

Cell

CNG

Solar

Energy

Efficiency

•

Provide equity financing for 21 MW of Bloom Energy fuel cell projects

at 75 commercial facilities including AT&T

•

Provides renewable energy value or credits, if applicable

•

Provides tax incentives, if applicable

•

Own and operate CNG facilities

•

Leverage retail gas supply and risk management expertise

•

Long-term customer off-take agreement(s)

•

~ 200 MW of Retail Solar Projects in operation or under construction

•

Long-term customer PPA (usually @ fixed price)

•

Provides renewable energy value or credits, if applicable

•

Provides tax incentives, if applicable

•

Over 1,000 energy saving projects implemented

•

~ 50 MW conserved by customers

•

More than $1 billion in projects 3rd party customer financed

•

Own and operate energy assets as a service to retail customers

•

Bundled service offering with long-term customer agreements

through grid power supply & LR programs

•

Load Response market -based value creation (e.g., LR Programs)

•

Own and operate energy assets as a service to retail customers

•

Bundled service offering with long-term customer agreements

through grid power supply & LR programs

•

Load Response market based value creation (e.g., ancillary services)

•

Design, build and operate energy assets

•

Provides renewable energy value or credits, if applicable

•

Long-term O&M agreements

Owned Assets –

additional attributes:

•

Long-term customer PPA (usually @ fixed price)

•

Provides tax incentives, if applicable

Invested

more

than

$1

billion

of

capital

with

projects

averaging

returns

of

8%

-

12%,

and

well

positioned

for

growth

Preserve

Value

Financial Update

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2014 EEI Financial Conference

2014 EEI Financial Conference

Financing Strategy

•

Our financing strategy incorporates a broad range of financial products, from the standard corporate-style

products (such as corporate debt and equity), to alternative structures such as project financing,

partnership structures and other arrangements

•

We employ a wide variety of financing tools that will enable us to access capital to grow on both the

regulated and unregulated sides of the business

Financing

Growth

Balance Sheet

Debt

Equity or Equity-

Like Products

Structured

Finance

On Balance Sheet Debt

supports core business and/or

strategic assets

•

Senior Unsecured Notes

•

Utility First Mortgage Bonds

Equity or Equity-Like Products

support growth projects (both

on-going and strategic M&A)

•

Mandatory Convertible Units

•

Marketed Follow-On Offerings

Structured Financing supports

non-core assets that generate

consistent cash flows

•

Project Financing

•

Asset Based Lending

•

Joint Venture/Equity Partner

Asset Sales

Proceeds from asset sales

support

•

Reinvestment of Free Cash Flow

•

Strategic Diversification

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2014 EEI Financial Conference

2014 EEI Financial Conference

Exelon’s Strategic and Financial Decisions Enable Growth

Across the Enterprise

Exelon has a proven ability to finance growth

A broad spectrum of financing alternatives beyond the

core financing options can be used to fund growth

o

Monetize assets in the portfolio via project

finance (Nearly $3B over past 3 years)

o

Sell assets which are worth more to others

($1.0-$1.5B after-tax in 2014-15)

o

Other financing structures (joint ventures,

minority partners, etc.) could be used based on

opportunity

Incremental Sources of Cash

750

750

750

775

775

550

425

675

300

625

275

2016

775

25

2015

2,650

1,900

2014

2018

1,200

2017

1,050

4,275

1,400

1,150

2013

1,175

Strategic and Diversified Deployment

Exelon

1.

Constellation

2.

BGE

3.

Utility Rate Base

4.

Retail Acquisitions

5.

Wind

6.

Annova LNG

7.

ERCOT New Build

8.

Pepco Holdings

9.

Distributed Energy

3

4

2/8

7

6

1

5

Contracted           Retail

Regulated

Earnings Volatility

Higher

Lower

Merchant

Strategic Decisions

Dividend Reduction

Alternative Financings

Forward Equity Sale

Mandatory Converts

ExGen Texas Power, LLC

Asset Sales

(1)

EPU Cancellations

ExGen Renewables I

Continental Wind

(1)

Includes Safe Harbor, Fore River, Quail Run, West Valley and Keystone Conemaugh. 

Does not include future Hillabee proceeds

9

Note:

16

2014 EEI Financial Conference

2014 EEI Financial Conference

Over the Last Three Years, Exelon Has Raised Nearly $3 Billion

through Project Financing

•

Exelon uses project financing to:

•

Maintain upside reward of the project while mitigating the downside risk

•

Enhance corporate credit metrics and strengthen the balance sheet via non-recourse financing vehicles

•

Provide different and new sources of liquidity that Exelon would

not typically be able to access corporately

•

Maximize Exelon’s returns on its strategic investments

Antelope Valley

Solar Ranch

•230 MW photovoltaic

solar generating plant in

Lancaster, CA

•$646 MM

Senior

Secured Bond –

due

January 2037 with a DOE

Loan Guaranty

Continental Wind

•667 MW of wind spread

across 13 projects and five

wind regimes

•$613MM Senior Secured

144a Project Bond –

due

February 2033 and

$141MM Senior Secured LC

and Working Capital

Facilities –

due February

2021

•Deal of the Year

•Project Finance’s 2013

North American Portfolio

Power Deal of the Year

•Project Finance & Risk’s

2013 Project Finance

Renewable Deal of the Year

ExGen Renewables

I

•HoldCo financing of

Continental’s distributions

to further maximize our

returns on our wind

investments

•$300MM Senior Secured

Team Loan B –

due

February 2021

ExGen Texas Power

•3,476 MW ERCOT

conventional power

portfolio consisting of

CCGTs and Simple Cycles

•$675MM Senior Secured

Term Loan B –

due

September 2021

•One of the largest non-

corporate, single-tranche

term loan B issuances in

the power sector in 2014

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2014 EEI Financial Conference

2014 Operating Earnings Guidance

2014  Original Guidance

$2.25 -

$2.55

(1)

$0.50 -

$0.60

$0.40 -

$0.50

$0.20 -

$0.30

ExGen

ComEd

PECO

BGE

2014 Revised Guidance (Disclosed

on 3Q2014 Earnings Call)

$2.30 -

$2.50

(1)

$1.25 -

$1.35

$0.45 -

$0.55

$0.35 -

$0.45

$0.15 -

$0.25

ExGen

ComEd

PECO

BGE

$1.10 -

$1.30

(1) Earnings guidance for OpCos may not add up to consolidated EPS guidance. Refer to slide 24for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating EPS

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2014 EEI Financial Conference

2014 EEI Financial Conference

EPS Sensitivities

2015

2016

2017

Fully Open

Henry Hub Natural Gas

+$1/MMBtu

$0.10

$0.37

$0.66

$0.88

-$1/MMBtu

($0.05)

($0.34)

($0.59)

($0.87)

NiHub ATC Energy Price

+$5/MWh

$0.07

$0.22

$0.31

$0.36

-$5/MWh

($0.07)

($0.22)

($0.31)

($0.36)

PJM-W ATC Energy Price

+$5/MWh

$0.03

$0.14

$0.21

$0.27

-$5/MWh

($0.02)

($0.13)

($0.20)

($0.27)

PJM Capacity Market

+$10/MW-day

$0.05

-$10/MW-day

($0.05)

30 Year Treasury Rate

+25 basis points

$0.01

$0.01

$0.01

$0.01

-25 basis points

($0.01)

($0.01)

($0.01)

($0.01)

Share Count (millions)

870

872

892

910

(1)

Based

on

September

30,

2014

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

price

inputs

constant.

Due

to

correlation

of

the

various

assumptions,

the

EPS

impact

calculated

by

aggregating

individual

sensitivities

may

not

be

equal

to

the

EPS

impact

calculated

when

correlations

between

the

various

assumptions

are

also

considered.

(2)

Assumes

2017/2018

auction

cleared

volumes

(3)

Does

not

include

shares

assumed

to

be

issued

via

forward

equity

sale

in

connection

with

PHI

acquisition

(3)

(2)

19

2014 EEI Financial Conference

2014 EEI Financial Conference

Capital Expenditure Expectations ($M)

Exelon Utilities

Exelon Generation

(1)

(1)

At Ownership

Note: Numbers rounded to nearest $25m

275

275

300

325

525

425

300

250

650

800

725

650

1,600

1,925

1,900

2,000

2016

3,225

2015

3,425

2014

3,050

2017

3,225

Gas Delivery

Smart Grid/Smart Meter

Electric Transmission

Electric Distribution

1,175

950

900

1,125

1,050

550

675

175

125

150

125

200

150

3,250

100

50

100

2014

2,775

75

1,025

1,000

950

100

75

2016

2,875

100

75

25

2015

2,200

2017

75

Wind

Base Capex

Nuclear Fuel

MD Commitments

TX New Build

Solar

Upstream

Nuclear Uprates

20

2014 EEI Financial Conference

2014 Projected Sources and Uses of Cash

Key Messages

(1)

•

Cash from Operations is projected to be $7,475M vs. 2Q14E of

$6,975M for a $500M variance. This variance is driven by:

$625M Net proceeds from divestitures

$175M Income taxes and settlements

$125M Reclassification of PHI preferred stock purchase

($325M) Integrys acquisition, including working capital

($100M) Working capital at Utilities

•

Cash from Financing activities is projected to be $375M vs.

2Q14E of $250M for a $125M variance. This variance is driven

by:

$175M Incremental project financing at ExGen

($50M) Decreased ComEd long term debt requirements

($25M) Decrease in projected commercial paper financings

•

Cash from Investing activities is projected to be ($5,725M) vs.

2Q14E of ($5,450M) for a ($275M) variance. This variance is

driven by:

($125M) ExGen development

($125M) Reclassification of PHI preferred stock purchase

($25M) Upstream

Projected Sources & Uses

(1)

(1)

All amounts rounded to the nearest $25M.

(2)

Excludes counterparty collateral of $134 million at 12/31/2013. In addition, the 12/31/2014 ending

cash balance  does not include collateral.

(3)

Includes cash flow activity from Holding Company, eliminations, and other corporate entities. CapEx for

Exelon is shown net of $325M CPS early lease termination fee, and ($125M) purchase of PHI

preferred stock.

(4)

Adjusted Cash Flow from Operations (non-GAAP) primarily includes net cash flows from operating

activities and net cash flows from investing activities excluding capital expenditures of $5.7B for 2014.

(5)

Dividends are subject to declaration by the Board of Directors.

(6)

“Other Financing”

primarily includes CENG distribution to EDF, expected changes in short-term debt,

and proceeds from issuance of mandatory convertible units.

($ in millions)

BGE

ComEd

PECO

ExGen

Exelon

(3)

As of 2Q14

Variance

Beginning Cash Balance

1,475

1,475

--

Adjusted Cash Flow from Operations

675

1,600

650

4,550

7,475

6,975

500

CapEx (excluding other items below):

(550)

(1,475)

(500)

(1,275)

(3,700)

(3,450)

(250)

Nuclear Fuel

n/a

n/a

n/a

(1,000)

(1,000)

(1,000)

--

Dividend

(1,075)

(1,075)

--

Nuclear Uprates

n/a

n/a

n/a

(150)

(150)

(150)

--

Wind

n/a

n/a

n/a

(75)

(75)

(75)

--

Solar

n/a

n/a

n/a

(200)

(200)

(200)

--

Upstream

n/a

n/a

n/a

(75)

(75)

(50)

(25)

Utility Smart Grid/Smart Meter

(75)

(275)

(150)

n/a

(525)

(525)

--

Net Financing (excluding Dividend):

Debt Issuances

--

900

300

--

1,200

1,250

(50)

Debt Retirements

--

(625)

(250)

(525)

(1,375)

(1,375)

--

Project Finance/Federal Financing Bank

Loan

n/a

n/a

n/a

1,050

1,050

875

175

Other Financing

(75)

175

100

(375)

575

575

--

Ending Cash Balance

3,600

3,250

350

(2)

(4)

(2)

(6)

(5)

21

2014 EEI Financial Conference

Pension and OPEB Contributions and Expense

2015

2016

(in $M)

Pre-tax Expense

(1)

Contributions

(2)

Pre-Tax Expense

(1)

Contributions

(2)

Pension

(3)(4)

$375

$515

$325

$565

OPEB

(3)(4)

$5

$30

$5

$35

Total

$380

$545

$330

$600

(1)

Pension and OPEB expenses assume a ~27% and ~28% capitalization rate in 2015 and 2016, respectively

(2)

Contributions shown in the table above are based on the current contribution policy, which for the pension includes a discretionary component of $250M

(3)

Expected return on assets for pension is 7.00% and for OPEB is 6.59%

(4)

Projected 12/31/14 pension and OPEB discount rates are 4.28% and 4.26%, respectively, for the majority of plans

22

2014 EEI Financial Conference

2015 Pension and OPEB Sensitivities

•

Tables below provide sensitivities for the combined company’s 2015 pension and OPEB expense and

contributions

(1)

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

(1)

Contributions

shown

in

the

table

above

are

based

on

the

current

contribution

policy,

which

for

the

pension

includes

a

discretionary

component

of

$250M

(2)

Pension

and

OPEB

expenses

assume

an

~

27%

capitalization

rate

in

2015

(3)

Final

2014

asset

return

for

pension

and

OPEB

will

depend

in

part

on

overall

equity

market

returns

for

Q4

2014

as

proxied

by

the

S&P

500;

The

amounts

above

reflect

YTD

asset

returns

through

September

30,

2014

(4)

The

baseline

discount

rates

reflect

projected

12/31/14

pension

and

OPEB

discount

rates

of

4.28%

and

4.26%,

respectively,

for

the

majority

of

plans

2015 Pension Sensitivity

(2) 

(in $M)

S&P Returns in Q4 2014

(3)

10%

0%

-10%

Discount Rate at

12/31/14

Pre-Tax

Expense

(1)

Contributions

(2)

Pre-Tax

Expense

(1)

Contributions

(2)

Pre-Tax

Expense

(1)

Contributions

(2)

Baseline

Discount

Rate

(4)

$365

$505

$375

$515

$390

$520

+50 bps

$345

$265

$345

$520

$355

$525

-

50bps

$400

$490

$410

$495

$425

$505

2015 OPEB Sensitivity

(2) 

(in $M)

S&P Returns in Q4 2014

(3)

10%

0%

-10%

Discount Rate at

12/31/14

Pre-Tax

Expense

(1)

Contributions

(2)

Pre-Tax

Expense

(1)

Contributions

(2)

Pre-Tax

Expense

(1)

Contributions

(2)

Baseline

Discount

Rate

(4)

$0

$30

$5

$30

$25

$35

+50 bps

($10)

$30

$0

$30

$10

$30

-

50bps

$10

$30

$25

$35

$35

$50

23

2014 EEI Financial Conference

Exelon-PHI Debt Maturity Profile

(1)

250

250

325

260

1,275

425

1,350

300

500

650

600

550

700

600

1,100

525

100

125

100

75

200

250

800

2022

1,450

2016

1,575

2015

1,985

2014

2021

900

2020

1,600

2019

925

25

2018

1,600

2017

1,225

25

ExCorp

PHI Holdco

PHI Regulated

EXC Regulated

ExGen

(1)

ExGen

debt

includes

legacy

CEG

debt;

EXC

Regulated

includes

capital

trust

securities;

Excludes

PHI

unregulated

debt,

which

totals

$25M;

Excludes

acquisition

debt

and

non-recourse

debt;

(2)

Current

senior

unsecured

ratings

for

Exelon,

Exelon

Generation

and

BGE

and

senior

secured

ratings

for

ComEd

and

PECO

(3)

All

ratings

are

“Stable”

outlook,

except

for

at

Fitch,

which

has

BGE

on

“Positive”

and

Exelon

and

ExGen,

on

“Ratings

Watch

Negative”

As of 10/31/14

Manageable debt maturity profile

Current

Ratings

(2)(3)

Moody’s

S&P

Fitch

Corp

Baa2

BBB-

BBB+

ComEd

A2

A-

A-

PECO

Aa3

A-

A

BGE

A3

A-

BBB+

Generation

Baa2

BBB

BBB+

24

2014 EEI Financial Conference

GAAP to Operating Adjustments

•

Exelon’s 2014 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:

-

Mark-to-market adjustments from economic hedging activities

-

Unrealized gains and losses from NDT 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 increase and decrease in certain decommissioning obligations

-

Financial impacts associated with the sale of interests in generating stations

-

Non-cash charge to earnings related to the cancellation of previously capitalized nuclear uprate projects

and

the

impairment

of

certain

wind

generating

assets

and

certain

assets

held

for

sale

-

Gain recorded upon consolidation of CENG

-

Certain costs incurred associated with the Constellation, CENG merger, and Pepco Holdings, Inc. merger

and integration initiatives

-

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

the merger date for 2014

-

Favorable settlements of certain income tax positions on Constellation’s 2009-2012 tax returns

-

CENG interest not owned by Generation, where applicable

Exelon Utilities

*

*

*

*

*

26

2014 EEI Financial Conference

Exelon Utilities Strategy

Strategy

Increase Total Enterprise Value

Maintain

First Quartile

Operating Performance

Achieve Financial

Performance Targets

Leverage standardization,

common platforms, and

best practices across

operating companies,

building a value creation

platform for future scale

Optimize Existing

Infrastructure

(get full potential from

current businesses)

Invest in Traditional

Infrastructure

(delivery network investments)

Grow Emerging

Infrastructure

(transformative growth)

Innovate

Products & Services

(expand customer offering)

Operational Excellence

Growth

27

2014 EEI Financial Conference

Leveraging Best Practices for Operational Excellence

Operations

Metric

At Merger (2012)

Post Merger (2014)

BGE

PECO

ComEd

BGE

PECO

ComEd

Electric

Operations

OSHA Recordable Rate

OSHA Severity Rate

2.5 Beta SAIFI

2.5 Beta CAIDI

Customer

Operations

Customer Satisfaction (MSI)

Service Level % of Calls Answered in

<30 Sec

Abandon Rate

Calls per Customer

Gas

Operations

Percent of Calls Responded to in

<=1 Hour

No

Gas

Operations

No

Gas

Operations

3rd Party Damages per 1,000 Gas

Locates

Q1

Q2

Q3

Q4

Performance

Quartiles

Exelon

Utilities

has

identified

and

transferred

best

practices

at

each

of

its

utilities

to

improve

operating

performance

in

areas

such

as:

•

System Performance

•

Emergency Preparedness

•

Corrective and Preventive Maintenance

28

2014 EEI Financial Conference

Capital Expenditures

(1)

Smart

Meter/Smart

Grid

CapEx

net

of

proceeds

from

U.S.

Department

of

Energy

(DOE)

grant;

For

BGE,

includes

CapEx

from

Smart

Energy

Savers

program

of

~$10M

per

year

175

150

175

200

275

350

300

225

150

100

475

575

425

375

75

75

125

175

225

200

1,000

1,225

1,225

1,325

350

350

325

325

250

350

350

350

125

125

125

100

25

2017E

775

25

2016E

750

2015E

725

50

2014E

650

2017E

525

2016E

525

2015E

550

50

2014E

650

50

2017E

1,925

2016E

1,950

2015E

2,150

2014E

1,750

Gas Delivery

Electric Transmission

Smart Grid/Smart Meter

(1)

Electric Distribution

($ in millions)

29

2014 EEI Financial Conference

Exelon

Utilities:

Rate

Base

(1)

and

ROE

Targets

2014E

Long-Term Target

Equity Ratio

52%

~53%

(4)

Earned ROE

7-8%

10%

Rate Case

2015

2014E

Long-Term Target

Equity Ratio

~46%

~53%

(2)

Earned ROE

8-9%

Based on 30-yr

US Treasury

(3)

Rate Case

Annual Formula Rate Filing

Continued investment in utilities will provide stable earnings growth

($ in billions)

(1)

ComEd,

PECO

and

BGE

rate

base

represents

end-of-year.

Numbers

may

not

add

due

to

rounding

(2)

Equity

component

for

distribution

rates

will

be

the

actual

capital

structure

adjusted

for

goodwill

(3)

Earned

ROE

will

reflect

the

weighted

average

of

11.5%

allowed

transmission

ROE

and

distribution

ROE

resulting

from

30-year

Treasury

plus

580

basis

points

for

each

calendar

year

(4)

Per

MDPSC

merger

commitment,

BGE

is

precluded

from

paying

dividends

through

2014

2014E

Long-Term Target

Equity Ratio

56%

~53%

Earned ROE

11-12%

10%

Rate Case

Possible 2015-2016

1.4

1.4

1.4

7.1

7.8

8.5

9.2

3.7

3.9

4.0

4.1

3.0

3.1

3.2

3.2

2.5

2.8

3.0

3.4

0.7

0.7

0.8

0.8

0.7

0.8

1.0

1.2

1.3

1.2

1.2

1.3

1.2

5.5

2015E

2017E

5.8

2016E

5.2

2014E

4.9

2017E

6.3

2014E

9.6

2016E

6.2

2015E

6.0

2014E

5.6

2017E

12.6

2016E

11.5

2015E

10.6

Gas

Distribution

Transmission

30

2014 EEI Financial Conference

9.9

2017 YE Rate Base

Other 2015-2017

$24.7B

(1.5)

Depreciation 2015-2017

(3.8)

CapEx 2015-2017

2014 YE Rate Base

$20.1B

Rate Base Growth

Utility CapEx spend outpaces depreciation, thereby growing rate base and

earnings

31

2014 EEI Financial Conference

Exelon Utility 2014-17 Adjusted Operating EPS

Guidance

By investing $16B in capital and improving earned ROEs, Exelon Utilities will

provide average earnings growth of ~8% per year from 2014-2017

32

2014 EEI Financial Conference

Grand Prairie Gateway Transmission Line

Key Facts

•

Line:

60

mile,

345

kV

transmission

line

connecting

ComEd’s

Byron

and

Wayne

substations

alleviating

identified

congestion

and

enhancing

reliability

•

Cost:

$260

million

•

Customer

Savings:

$250

million

within

the

first

15

years

of

operation

–

net

of

all

costs

•

Recovery

Mechanism:

FERC-filed

transmission

rate

of

11.5%

and

construction

work

in

progress

and

abandonment

recovery

•

Construction:

Scheduled

to

begin

Q2

2015

•

In

Service

Date:

Q2

2017

•

Environmental

Benefits:

735,000

pounds

of

carbon

dioxide

(CO2)

reduced

over

the

first

15

years

33

2014 EEI Financial Conference

ComEd April 2014 Distribution Formula Rate

Docket #

14-0312

Filing Year

2013

Calendar

Year

Actual

Costs

and

2014

Projected

Net

Plant

Additions

are

used

to

set

the

rates

for

calendar

year

2015.

Rates

currently

in

effect

(docket

13-0318)

for

calendar

year

2014

were

based

on

2012

actual

costs

and

2013

projected

net

plant

additions

Reconciliation Year

Reconciles

Revenue

Requirement

reflected

in

rates

during

2013

to

2013

Actual

Costs

Incurred.

Revenue

requirement

for

2013

is

based

on

docket

13-0386

filed

in

June

2013

and

reflect

the

impacts

of

PA

98-0015

(SB9)

Common Equity Ratio

~

46%

for

both

the

filing

and

reconciliation

year

ROE

9.25%

for

the

filing

year

(2013

30-yr

Treasury

Yield

of

3.45%

+

580

basis

point

risk

premium)

and

9.20%

for

the

reconciliation

year

(2013

30-yr

Treasury

Yield

of

3.45%

+

580

basis

point

risk

premium

–

5

basis

points

performance

metrics

penalty).

For

2014

and

2015,

the

actual

allowed

ROE

reflected

in

net

income

will

ultimately

be

based

on

the

average

of

the

30-year

Treasury

Yield

during

the

respective

years

plus

580

basis

point

spread,

absent

any

metric

penalties

Requested Rate of Return

~

7%

for

both

the

filing

and

reconciliation

years

Rate Base

(1)

$7,369

million–

Filing

year

(represents

projected

year-end

rate

base

using

2013

actual

plus

2014

projected

capital

additions).

2014

and

2015

earnings

will

reflect

2014

and

2015

year-end

rate

base

respectively.

$6,596

million

-

Reconciliation

year

(represents

year-end

rate

base

for

2013)

Revenue Requirement

Increase

(1)

$269M

($96M

is

due

to

the

2013

reconciliation,

$173M

relates

to

the

filing

year).

The

2013

reconciliation

impact

on

net

income

was

recorded

in

2013

as

a

regulatory

asset.

Timeline

•

04/16/14 Filing Date

•

240 Day Proceeding

•

ALJ Proposed Order issued on 10/15/14 proposes a $239M revenue requirement increase

•

ICC order expected by December 12, 2014

(1)

Amounts

represent

ComEd’s

position

filed

in

rebuttal

testimony

on

July

23,

2014

Note:

Disallowance

of

any

items

in

the

2014

distribution

formula

rate

filing

could

impact

2014

earnings

in

the

form

of

a

regulatory

asset

adjustment

Given

the

retroactive

ratemaking

provision

in

the

Energy

Infrastructure

Modernization

Act

(EIMA)

legislation,

ComEd

net

income

during

the

year

will

be

based

on

actual

costs

with

a

regulatory

asset/liability

recorded

to

reflect

any

under/over

recovery

reflected

in

rates.

Revenue

Requirement

in

rate

filings

impacts

cash

flow.

The

2014

distribution

formula

rate

filing

establishes

the

net

revenue

requirement

used

to

set

the

rates

that

will

take

effect

in

January

2015

after

the

Illinois

Commerce

Commission's

(ICC’s)

review.

There

are

two

components

to

the

annual

distribution

formula

rate

filing:

•

Filing

Year:

Based

on

prior

year

costs

(2013)

and

current

year

(2014)

projected

plant

additions.

•

Annual

Reconciliation:

For

the

prior

calendar

year

(2013),

this

amount

reconciles

the

revenue

requirement

reflected

in

rates

during

the

prior

year

(2013)

in

effect

to

the

actual

costs

for

that

year.

The

annual

reconciliation

impacts

cash

flow

in

the

following

year

(2015)

but

the

earnings

impact

has

been

recorded

in

the

prior

year

(2013)

as

a

regulatory

asset.

34

2014 EEI Financial Conference

BGE Rate Case Settlement

Electric

Gas

Docket #

9355

Test Year

September  2013 -

August  2014

Common Equity Ratio

(1)(2)

52.3%

Authorized Returns

(1)(3)

ROE: 9.75%; ROR: 7.46%

ROE: 9.65%; ROR: 7.41%

Requested Rate of Return

7.93%

7.88%

Proposed Rate Base (adjusted)

(1)(4)

$2.9B

$1.2B

Revenue Requirement Increase

$22.0M

$38.0M

Distribution Increase as % of

overall bill

1%

5%

Timeline

•

07/02/14 BGE filed application with the MDPSC seeking increases in electric & gas

distribution base rates

•

210 Day Proceeding

•

7/08/14 –

Case delegated to the Public Utility Law Judge Division

•

10/17/14 –

BGE filed unanimous “black box”

settlement with MD PSC

•

Settlement must be approved by the MD PSC

•

If approved, new rates are expected to be effective no sooner than the middle of

December 2014

(1)

Due

to

the

“black

box”

nature

of

the

settlement,

the

Common

Equity

Ratio,

Authorized

Returns,

and

Proposed

Rate

Base

(adjusted)

were

not

agreed

upon

by

the

parties

in

determining

the

ultimate

revenue

requirement

increase

(2)

Reflects

BGE’s

actual

capital

structure

as

of

8/31/2014

(3)

ROE

and

ROR

stated

in

the

settlement

only

apply

to

AFUDC

and

carrying

costs

on

regulatory

assets

(4)

BGE’s

Proposed

Adjusted

rate

base

First BGE rate case settlement agreement since 1999

35

2014 EEI Financial Conference

ComEd Load

Weather-Normalized Load Growth

Economic Forecast of Drivers that Influence Load

2014E

0.6%

0.1%

1.4%

0.7%

1.7%

2013

-0.3%

-0.5%

0.0%

-0.2%

1.2%

GMP

Large C&I

Small C&I

Residential

All Customers

Driver or Indicator

2015 Outlook

Gross Metro

Product (GMP)

2.3% growth in real GMP reflects overall

better economic conditions than the slower

growth in 2014 (Manufacturing and

Professional Business Services employment

accelerate in 2015)

Employment

1.3% increase in total employment is

expected for 2015, which is consistent with

the average growth for the past three years

Manufacturing

Manufacturing employment is expected to

grow 1.4% in 2015. This is a significant

improvement over the (0.4%) decline in

2013 and the (1.1%) decline in 2014

Households

Household formations are expected to

increase 0.7% in 2015 which is slightly

higher than the expected increase of 0.6% in

2014

Energy Efficiency

Continued expansion of EE program

expected to reduce usage in 2015 by

approximately 1.2%

Notes: 2013 data is not adjusted for leap year. Source of 2015 economic outlook data is IHS Economics (September 2014).  (C&I = Commercial and Industrial)

Improving economic conditions and energy efficiency initiatives will continue to

impact load growth

36

2014 EEI Financial Conference

PECO Load

Weather-Normalized Load Growth

Economic Forecast of Drivers that Influence Load

2014E

-0.6%

0.0%

1.1%

0.3%

1.2%

2013

1.5%

-1.1%

0.0%

1.3%

GMP

Large C&I

Small C&I

Residential

All Customers

Driver or Indicator

2015 Outlook

Gross Metro

Product (GMP)

GMP projected to grow at 2.5% for 2015,

the same as prerecession levels

Resident

Employment

Resident employment outlook is 1.7% in

2015 vs. 1.3% in 2014

Manufacturing

Employment

Manufacturing employment is expected to

grow at 1.7%. Philadelphia has had

negative growth from 2000 to 2014

Households

Household growth is expected to be 0.7%,

strongest growth since 2008, and at the

same level as 2014

Energy Efficiency

Deemed Energy Efficiency impact

forecasted to be ~0.9% reduction in

usage in 2015

Moderately strong economic recovery will drive sales in 2015, partially offset by

on-going energy efficiency initiatives

0.3%

Notes: 2013 data is not adjusted for leap year. Source of 2015 economic outlook data is IHS Economics (September 2014).  (C&I = Commercial and Industrial)

37

2014 EEI Financial Conference

BGE Load

Weather-Normalized Load Growth

Economic Forecast of Drivers that Influence Load

2014E

-1.8%

-0.5%

-0.7%

-1.2%

1.6%

2013

-3.2%

2.1%

2.0%

-0.6%

0.4%

GMP

Large C&I

Small C&I

Residential

All Customers

Moderately strong economic recovery will drive sales in 2015, partially offset by

energy efficiency initiatives

Driver or Indicator

2015 Outlook

Gross Metro

Product (GMP)

GMP is projected to grow at 2.6% for

2015

Employment

2.1% growth projected. BGE’s decoupled

non-rate case revenue growth is primarily

driven by customer growth.  The main

driver for customer growth is employment

Manufacturing

Manufacturing employment is expected to

be fairly flat to 2014 levels in 2015

Households

Household growth is projected to be

0.8%, almost flat to 2014

Energy Efficiency

Continued expansion of EE programs will

partially offset growth seen due to

improvements in economic conditions

Notes: 2013 data is not adjusted for leap year. Source of 2015 economic outlook data is IHS Economics (September 2014).  (C&I = Commercial and Industrial)

PHI Acquisition

*

*

*

*

*

39

2014 EEI Financial Conference

Delivering Value to PHI’s Customers and Communities

40

2014 EEI Financial Conference

PHI Acquisition Will Create the Leading Mid-Atlantic Utility

Operating Statistics

Commonwealth Edison

Potomac Electric Power

Customers:

Service Territory:

Peak Load:

2013 Rate

Base:

3,800,000

11,400 sq.

miles

23,753 MW

$8.7 bn

Customers:

Service Territory:

Peak Load:

2013 Rate Base:

801,000

640 sq. miles

6,674 MW

$3.4 bn

PECO Energy

Atlantic City Electric

Customers:

Service Territory:

Peak Load:

2013 Rate

Base:

2,100,000

2,100 sq. miles

8,983 MW

$5.4 bn

Customers:

Service Territory:

Peak Load:

2013 Rate Base:

545,000

2,700 sq. miles

2,797

MW

$1.6 bn

Baltimore Gas & Electric

Delmarva Power & Light

Customers:

Service Territory:

Peak Load:

2013 Rate

Base:

1,900,000

2,300 sq. miles

7,236 MW

$4.6 bn

Customers:

Service Territory:

Peak Load:

2013 Rate Base:

632,000

5,000 sq. miles

4,121 MW

$2.0 bn

___________________________

Source: Company filings.

Note: Operational statistics as of 12/31/2013

Combined Service Territory

Potomac Electric Power Service Territory

Atlantic City Electric Service Territory

Delmarva Power & Light Service Territory

Baltimore Gas and Electric Service Territory

PECO Energy Service Territory

ComEd Service Territory

41

2014 EEI Financial Conference

2014 EEI Financial Conference

Earnings Accretive First Full Year

(1)

Transaction Economics

Exelon Consolidated S&P FFO/Debt

24%

22%

2015

2016

(1) Assumes funding mix of assumed debt, new debt, asset sales and equity issuance with appropriate discount to market price.  (2) Reflects year end rate base

2016-2017 Operating Earnings

33%-39%

61%-67%

Pro Forma Business Mix

Regulated

Unregulated

Rate Base Growth ($B)

(2)

$21.8

$23.2

$24.7

$8.1

$8.8

$9.6

$20.1

$34.3

+15%

+49%

2017

2014

2015

2016

$29.9

$32.0

Exelon

PHI

2017

2016

$0.10 -

$0.15

$0.15 -

$0.20

Achieve run-rate 

accretion of 

$0.15-$0.20 

starting in 2017

The transaction is EPS accretive, adds to rate base growth and further

strengthens our financials

42

2014 EEI Financial Conference

2014 EEI Financial Conference

PHI: Capital Expenditures and Rate Base

$725

$675

$700

$725

$350

$350

$350

$350

$250

$275

$325

$325

$1,400

2017E

2016E

$1,375

2015E

$1,300

2014E

(2)

$1,325

(2)

Pepco

DPL

ACE

Rate Base ($B)

(1)(3)

Capital Expenditures ($M)

(1)

$4.0

$4.4

$4.8

$2.2

$2.4

$2.5

$2.7

$1.6

$1.7

$1.9

$2.1

$3.6

2016E

$8.8

2015E

$8.1

2014E

$7.5

2017E

$9.6

(1)

Source: PHI Third Quarter Earnings Materials 10/31/14

(2)

Source for 2014 CapEx is PHI 2014 Analyst Day Conference Presentation 03/21/14 and PHI First Quarter 2014 Earnings Materials 05/07/14

(3)

Denotes year end rate base

Note:  CapEx numbers rounded to nearest $25M; totals might not add due to rounding

Strong rate base growth will provide stable utility earnings growth

43

2014 EEI Financial Conference

2014 EEI Financial Conference

Opportunity for ROE Improvement at PHI Utilities

Source:  Pepco Holdings Inc. 2014 Analyst Conference Presentation, 3/21/14

44

2014 EEI Financial Conference

2014 EEI Financial Conference

Regulatory Approval Timeline Supports a Q2/Q3 2015 Close

Jurisdiction

Application

Filing

Key Regulatory Milestones

Approved

Virginia

(Case No. PUE-2014-00048)

3-Jun

Approved October 7, 2015

Federal Energy

Regulatory Commission

(FERC)

(Docket No. EC14-96-000)

30-May

Department of Justice

(DOJ)

6-Aug

Request for additional information received

October 9

Delaware

(Docket 14-193)

18-Jun

Pre-Hearing Briefs:  Feb 11, 2015

Hearings: Feb 18 -

20, 2015

Final Order: Mar 10, 2015

New Jersey

(Docket No. EM14060581)

18-Jun

Hearings: Jan 12 -

16, 2015

Briefs: Feb 6, 2015

Reply Briefs: March 3, 2015

Maryland

(Case No 9361)

19-Aug

Hearings: Jan 26 -

Feb 6, 2015

Briefs:  Feb 27, 2015

Reply Briefs: March 13, 2015

Statutory Deadline: April 1, 2015

District of Columbia

(Formal Case No. 1119)

18-Jun

Hearings: Feb 9 –

13, 2015

Briefs:  March 12, 2015

Reply Briefs:  March 26, 2015

46

2014 EEI Financial Conference

2014 EEI Financial Conference

Commercial Business Overview

Scale, Scope and Flexibility Across the Energy Value Chain

Development and

exploration of natural gas

and liquids properties

9 assets in

six states

~165 BCFe of proved

Reserves

(1)

Leading merchant power

generation portfolio in the

U.S.

~32 GW of owned

generation capacity

(2)

Clean portfolio, well

positioned for evolving

regulatory requirements

Industry-leading wholesale

and retail sales and

marketing platform

~150 TWh of load and     

~500 BCF of retail gas

delivered

(3)

~ 1 million residential and

100,000 business and

public sector customers

One of the largest and most

experienced Energy

Management providers

Over 4,000 energy savings

projects implemented

across the U.S.

A growing Distributed

Energy platform with over

$1B of investment to date

Benefiting from scale, scope and flexibility across the value chain

(1) 12/31/13

year-end

reserves

based

upon

assets

owned

as

of

9/30/14.

Includes

Natural

Gas

(NG),

NG

Liquids

(NGL)

and

Oil.

NGL

and

Oil

are

converted

to

BCFe

at

a

ratio

of

6:1.

(2)

Total

owned

generation

capacity

as

of

9/30/2014,

less

capacity

for

announced

divestitures

of

Fore

River,

Quail

Run,

West

Valley,

and

Keystone

Conemaugh

(3)

Expected

for

2014

as

of

9/30/2014.

Electric

load

and

gas

includes

fixed

price

and

indexed

products

Note:

Does

not

include

the

impact

of

Integrys

acquisition

47

2014 EEI Financial Conference

2014 EEI Financial Conference

10

15

5

9

18

7

15

16

49

71

27

97

25

ERCOT

38

Mid-Atlantic

108

Canada

Midwest

111

23

South/West/

New York

10

New England

Generation to Load Match

Industry-leading platform with regional diversification of the generation

fleet and

customer-facing load business

Generation Capacity, Expected Generation and Expected Load 

2015 in TWh

(1,2)

(1)

Owned

and

contracted

generation

capacity

converted

from

MW

to

MWh

assuming

100%

capacity

factor

(CF)

for

all

technology

types,

except

for

renewable

capacity

which

is

shown

at

estimated

CF

(2)

Expected

generation

and

load

shown

in

the

chart

above

will

not

tie

out

with

load

volume

and

ExGen

disclosures;

Load

shown

above

does

not

include

indexed

products

and

generation

reflects

a

net

owned  and

contracted

position;

Estimates

as

of

9/30/2014

Note:

Includes

divestitures

for

Safe

Harbor,

Fore

River,

Quail

Run,

and

West

Valley;

Does

not

include

impact

of

Keystone

/Conemaugh

divestiture

or

the

Integrys

acquisition

Expected Load

Expected

Generation

Baseload

Intermediate

Peaking

Renewables

Generation to Load match provides

portfolio management benefits in

differing volatility and price

environments

•

During the first quarter, our

nuclear baseload generation fleet,

in combination with our

dispatchable fleet, allowed us to

take advantage of the high

volatility/price environment while

managing load obligations

•

During the third quarter, we were

able to realize lower costs to serve 

our load due to the low

volatility/price environment

48

2014 EEI Financial Conference

2014 EEI Financial Conference

Electric Load Serving Business: Growth Targets

(1)

0

20

40

60

80

100

120

140

160

180

2015E

2017E

2016E

2014E

165

70-80%

20-30%

165

60-70%

30-40%

150

60-70%

30-40%

165

70-80%

20-30%

Retail Load

(2)

Wholesale Load

Total Contracted

Commercial Load 

2014 –

2017 TWh

8%

Load Split by Customer Class

(2014 TWh)

Expected growth in volumes and margins on the

back of a sustainable platform

A diverse set of customers enhances portfolio

management opportunities

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

Customer Type

Load Size

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

Medium C&I

Large C&I

35%

15%

Small C&I

10%

Mass Markets

5%

Wholesale

35%

C&I = Commercial & Industrial

(1) Does not include Integrys acquisition

49

2014 EEI Financial Conference

2014 EEI Financial Conference

Electric Load Serving Business: Market Landscape

Total U.S. Power Market 2014 (~3,700 TWh load)

(2)

Eligible Non-

Switched

Eligible

Switched

Muni/Co-Op Market

Other

Ineligible

Constellation Active Retail Electric Markets

(1)

Competitive Retail Market Expected to Grow Faster Than Overall

Market 2014-2017

•

Underlying 1% load growth across the U.S.

•

C&I switched market to grow by about 8%

•

Residential switched market to grow by about 7%

Retail Mergers & Acquisitions Activity has Increased

•

EXC has been active in evaluating opportunities, and acquired

Integrys Energy Services earlier this year

•

34 deals announced 2014 YTD, compared to 27 deals in 2013,

and 23 deals in 2012

Conditions have improved in many markets as impacts of the

Polar Vortex have played out

•

During 2014, we have experienced improved margins, contract

tenors, and renewal rates

Existing suppliers continue to expand market footprint and

product portfolio

•

Existing suppliers entered 23 new markets in 2014 YTD

•

Energy efficiency among most popular for cross-selling

opportunities

Market Landscape

(2)

(1)

Does

not

include

Integrys

acquisition

(2)

Sources

are

EIA,

DNV

GL,

and

internal

estimates

Improving market driving higher margins and better contract terms

50

2014 EEI Financial Conference

2014 EEI Financial Conference

Natural Gas Serving Business: Marketing Platform

Constellation Active Natural Gas Markets

Supply

~4-6 Bcf per day delivered in competitive markets

Transportation

Active shipper on more than 45 interstate pipelines on a daily basis

Trading

Active participant in all major supply basins, markets, and trading

points in North America

Volume

Management

Schedule, nominate and balance behind more than 100 LDCs

Nature

Gas

markets

continue

to

grow

on

both

the

consumption

and

supply

side

•

Lead by the industrial section, gas consumption is expected 

to increase by 1.6% in 2014

•

EXC expanded it’s gas marketing presence through the

Integyrs and ETC ProLiance acquisitions

Growing domestic production impacting imports

•

Continued downward pressure on natural gas imports from

Canada

•

Mexican exports, specifically from Eagle Ford, are expected to

increase due to growing demand in the electric power sector

The

Polar

Vortex

provided

multiple

supply

opportunities

across

the

US

for

natural

gas

LNG imports and exports

•

Higher prices in Europe and Asia more attractive to sellers

than low US prices

•

LNG exports are still a very small part of the total picture;

however, the United States will remain a net importer of

natural gas because of pipeline imports from Canada

Gas Storage and Pipeline Investment

•

Gas inventories continue to drop year over year.  Currently

373 BCF lower than last year driving storage opportunities

•

Investment in new pipelines supporting key production

areas continue grow supported by multiple parties (Equity,

LDCs)

(1) Source: EIA and internal estimates

Market Landscape 2014 -

2015

(1)

Top 10 US Gas Marketer with a growing presence

51

2014 EEI Financial Conference

Integrys Energy Services Acquisition

Natural Gas

Electric

Electric and Natural

Gas

•

Significantly

increases

natural

gas

portfolio

by

150

bcf

annually

•

Increases

power

load

by

15

TWh

•

Many

of

the

power

customers

served

by

Integrys

are

in

regions

where

Exelon

owns

significant

generation,

providing

generation

to

load

match

benefit

•

Mitigates

risk

of

hedging

in

illiquid

markets

•

Adds

1.2

million

customers,

bringing

the

total

Constellation

customer

base

to

approximately

2.5

million

homes

and

businesses

52

2014 EEI Financial Conference

(1)    12/31/13 year-end reserves based upon assets owned as-of 9/30/14.

Upstream E&P Assets

Estimated Net Proved

Reserves

(as of 12/31/13)

(1)

Average Net Daily

Production

(as of Q2 2014)

165 Bcfe

55 MMcfe

Investment Thesis

•

Our Upstream Gas business achieves strong returns

(>16% after-tax IRR)

•

$110m (~70% utilized) Reserve Based Lending (RBL)

facility in place

Non-recourse treatment at S&P

•

Provides valuable market intelligence  in complex

natural gas markets

Forecasted Production

2014

2015

2016

2017

Net Daily Prod

(MMcfe / day)

50-55

40-55

35-50

40-55

Current Portfolio Of Investments

Mississippi Lime (OK)

Hunton Dewatering (OK)

Woodford Shale (OK)

Fayetteville Shale (AR)

Haynesville Shale (LA)

Floyd Shale (AL)

Woodbine Shale (TX)

Trenton Black River (MI)

Barnett Shale (TX)

53

2014 EEI Financial Conference

Pipeline capacity expansions and regional demand should balance higher gas

production starting in mid-2017, improving Mid-Atlantic gas basis

Mid-Atlantic Gas Basis: Improves Starting 2017

•

Northeastern U.S. gas production is projected to approach 25 bcf/day by 2018, up from 19 bcf/day in 2015

•

Regional demand is projected to reach 18 bcf/day by 2018, up from 15 bcf/day in 2015

•

Based upon public announcements, we expect 19 bcf/day of pipeline takeaway capacity by 2018

•

Pipeline

projects

are

underway

adding

takeaway

capacity.

2017

is

a

transition

year

where

timing

of

pipeline

expansions

(~9

bcf/day)

will

play

a role in determining  local gas prices, but should be more balanced than in prior years.  This is consistent with the current forward market

which indicates an improving Mid-Atlantic natural gas basis

•

Additional pipeline capacity and regional demand will stabilize basis discounts in non winter months and reduce price spikes in the winter

Notes:

Values represent annual averages; Demand includes storage

54

2014 EEI Financial Conference

Northeast Gas Pipeline Expansion Projects

Almost 19 bcf/day of pipeline expansion projects have been announced for

completion by the end of 2018

55

2014 EEI Financial Conference

Power Markets -

NiHub

$2-$3/MWh power price upside

in 2016-2017 due to

higher dispatch costs and a modest increase in load

Expect continued volatility

due to incremental coal

retirements in  the second half of 2015

Forward markets continued their upward trend

through 2014

•

During 2014, strong spot prices have started to reflect the

changing nature of the grid in PJM and new reliance on

different resources such as NG supply, demand response,

and oil peakers

•

As a result, we have seen stronger forward power and heat

rate curves

•

Our portfolio is positioned to take advantage of expected

volatility and power price upside

•

2015 seasonal upside in the second half of the year,

especially at NIHUB off peak

•

2016-2017 average upside of $2-$3/MWh

56

2014 EEI Financial Conference

Capacity Markets

2013/

2014

2014/

2015

2015/

2016

2016/

2017

2017/

2018

PJM

(3,8,9)

ComEd

Capacity

N/A

N/A

N/A

N/A

10,900

Price

N/A

N/A

N/A

N/A

$120

RTO 

Capacity

11,500

11,500

11,500

11,250

0

Price

$28

$126

$136

$59

$120

EMAAC

Capacity

(4)

8,900

8,900

8,900

8,900

8,300

Price

$245

$137

$168

$119

$120

MAAC 

Capacity

(5)

2,300

2,300

2,300

2,300

2,300

Price

$226

$137

$168

$119

$120

SWMAAC

Capacity

(6)

1,800

1,800

1,800

1,800

900

Price

$226

$137

$168

$119

$120

BGE 

Capacity

N/A

N/A

N/A

N/A

900

Price

N/A

N/A

N/A

N/A

$120

Average Exelon

$140

$132

$153

$91

$120

New England

(7)

NEMA  

Capacity

2,100

2,100

2,100

2,100

2,100

Price

$98

$107

$114

$219

$493

Rest of Pool   Capacity

735

445

35

35

35

Price

$85

(8)

$95

(8)

$104

(8)

$90

$231

NYISO

(9)

Rest of Pool   Capacity

1,100

1,100

1,100

1,100

1,100

MISO

(10)

AMIL 

Capacity

1,100

1,100

1,100

1,100

1,100

Price

N/A

N/A

N/A

1

17

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 = Southeast Massachusetts, AMIL = Ameren Illinois.

PJM

RPM

Capacity

Revenues

(1,9)

Exelon Fleet Weighted Price ($/MWd)

Revenue ($MM)

(2)

(1)

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

rounded to nearest $50M

(2)

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

(3)

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

(4)

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

(5)

ICAP is net of Safe Harbor divestiture (total ~300 MW); Impact of Keystone Conemaugh diestiture not included

(6)

ICAP is net of units divested (Brandon Shores, Wagner & Crane ~2,648 MW; and Riverside 6 CT (~115MW)

(7)

Reflects Qualified Summer Capacity including owned and contracted units; excludes Fore River after 14/15

(8)

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

the reliability requirement

(9)

Reflects 50.01% ownership in CENG

(10)

Does not include wind under PPA

57

2014 EEI Financial Conference

PJM –

Working to Address Reliability

Source: PJM Interconnection, Response to Committee Questions of U.S. House of

Representatives Committee on Energy and Commerce, April 18, 2014, Figure 4.

Source: PJM Interconnection, “Analysis of Operational Events and Market

Impacts During the January 2014 Cold Weather,”

May 9, 2014, slide 10.

The polar vortex in the winter of 2014

highlighted generator reliability concerns

that PJM is now working to address

Source:  Northbridge Analysis based on PJM data

58

2014 EEI Financial Conference

PJM’s Proposed Solution -

Capacity Performance Proposal

•

PJM recognizes that generation resources procured through its existing forward capacity market (RPM)

may not be sufficient to meet future load conditions, especially

at winter peak

o

Additionally, current revenues and penalty structures are insufficient to provide incentives for

necessary investment to maintain highly available capacity

•

PJM

released

a

revised

“Capacity

Performance”

proposal

on

October

7,

2014

revamping

initial

reform

concepts suggested in August

o

The Capacity Performance concept reforms are intended to encourage commitment of capacity

resources that have secure fuel and other performance characteristics to provide PJM confidence

that

units

will

be

available

when

dispatched

to

meet

peak

summer

and

winter

load

o

PJM proposes to increase the capacity market offer cap to Net CONE, and to substantially raise

penalties for performance failure

o

PJM suggests transition mechanisms for delivery years in which it has already made forward

capacity procurements (2015-16, 2016-17, and 2017-18)

o

PJM

proposes

a

method

of

integrating

“wholesale”

demand

response

through

PJM

Load

Serving

Entities in a manner that would clear by adjusting the RPM demand curve

59

2014 EEI Financial Conference

Capacity Performance Impact on PJM Fleet

Total Potential CP

Resources

Procurement Quantity

(80% of RPM

Reliability Target)

Source: NorthBridge Analysis; Includes FRR resources/Loads; PJM proposal is to fully procure CP for 2016/17 and 2017/18 but to incrementally procure up to 10 GW of base capacity for

2015/16; Potential 2015/16 all-in CP procurement quantity shown for comparison purposes

Only qualifies

with

significant 

cost

Qualifies

without

significant

capital cost

Exelon’s fleet is well positioned to benefit from Capacity Performance due to

significant investment in reliability

60

2014 EEI Financial Conference

2014 EEI Financial Conference

Exelon Generation Disclosures

As of September 30, 2014

61

2014 EEI Financial Conference

2014 EEI Financial Conference

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

Note:

Hedge

strategy

has

not

changed

as

a

result

of

recent

and

pending

asset

divestitures

Credit Rating

Capital

Structure

Capital &

Operating

Expenditure

Dividend

•Aligns hedging program with financial

policies and financial outlook

•Establish minimum hedge targets to

meet financial objectives of the

company (dividend, investment-grade

credit rating)

•Hedge enough commodity risk to

meet future cash requirements

under a stress scenario

•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

•

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

Three-Year Ratable Hedging

Bull / Bear Program

Strategic Policy Alignment

62

2014 EEI Financial Conference

2014 EEI Financial Conference

Components of Gross Margin Categories

Open Gross

Margin

•Retail, Wholesale

planned gas sales

•Load Response

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

•Retail, Wholesale 

executed gas

sales

•Load Response

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Retail, Wholesale

planned electric

sales

•Portfolio

Management new

business

•Mid marketing

new business

•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

•Generation Gross

Margin at current

market prices,

including capacity

& ancillary

revenues, nuclear

fuel amortization

and fossils fuels

expense

•Exploration and

Production

(4)

•PPA Costs &

Revenues

•Provided at a

consolidated level

for all regions

(includes hedged

gross margin for

South, West &

Canada

(1)

)

MtM of

Hedges

(2)

“Power”

New

Business

“Non Power”

Executed

“Non Power”

New Business

Margins move from new business to MtM of hedges over

the course of the year as sales are executed

(5)

Margins move from “Non power new business”

to

“Non power executed”

over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

(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

generally

remain

within

“Non

Power”

New

Business

category

and

only

move

to

“Non

Power”

Executed

category

upon

management

discretion

(4)

Gross

margin

for

these

businesses

are

net

of

direct

“cost

of

sales”

(5)

Margins

for

South,

West

&

Canada

regions

and

optimization

of

fuel

and

PPA

activities

captured

in

Open

Gross

Margin

63

2014 EEI Financial Conference

2014 EEI Financial Conference

ExGen Disclosures 

Gross Margin Category ($M)

(1)

2014

2015

2016

2017

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

7,300

6,750

6,500

6,650

Mark

to

Market

of

Hedges

(3,4)

(350)

-

150

150

Power New Business / To Go

50

400

550

750

Non-Power Margins Executed

350

100

50

50

Non-Power New Business / To Go

50

300

350

350

Total

Gross

Margin

(2,6)

7,400

7,550

7,600

7,950

Reference Prices

(5)

2014

2015

2016

2017

Henry Hub Natural Gas ($/MMbtu)

$4.44

$4.00

$4.08

$4.22

Midwest: NiHub ATC prices ($/MWh)

$39.45

$33.70

$33.21

$33.62

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

$51.38

$42.75

$40.69

$40.06

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$3.02

$6.47

$6.14

$6.27

New York: NY Zone A ($/MWh)

$49.00

$42.14

$38.94

$38.37

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

ALQN Gas, 7.5HR, $0.50 VOM

$3.04

$8.95

$7.64

$5.48

(1)

Gross

margin

categories

rounded

to

nearest

$50M

(2)

Total

Gross

Margin

(Non-GAAP)

is

defined

as

operating

revenues

less

purchased

power

and

fuel

expense,

excluding

revenue

related

to

decommissioning,

gross

receipts

tax,

Exelon

Nuclear

Partners

and

variable

interest

entities.

Total

Gross

Margin

is

also

net

of

direct

cost

of

sales

for

certain

Constellation

businesses.

(3)

Excludes

EDF’s

equity

ownership

share

of

the

CENG

Joint

Venture

(4)

Mark

to

Market

of

Hedges

assumes

mid-point

of

hedge

percentages

(5)

Based

on

September

30,

2014

market

conditions

(6)

Reflects

the

divestiture

impact

of

Fore

River,

Quail

Run

and

West

Valley.

Does

not

include

divestiture

of

Keystone/Conemaugh

or

the

Integrys

acquisition

64

2014 EEI Financial Conference

2014 EEI Financial Conference

ExGen Disclosures

Generation and Hedges

(6)

2014

2015

2016

2017

Exp. Gen (GWh)

(1)

205,300

200,800

202,200

205,000

Midwest

97,000

96,600

97,500

95,800

Mid-Atlantic

(2)

74,300

71,300

72,100

68,900

ERCOT

11,400

16,400

16,900

25,300

New York

(2)

12,700

9,400

9,300

9,300

New England

9,900

7,100

6,400

5,700

% of Expected Generation Hedged

(3)

98-101%

86-89%

55-58%

27-30%

Midwest

97-100%

83-86%

49-52%

20-23%

Mid-Atlantic

(2)

98-101%

88-91%

55-58%

28-31%

ERCOT

101-104%

99-102%

82-85%

46-49%

New York

(2)

98-101%

87-90%

62-65%

42-45%

New England

102-105%

82-85%

62-65%

25-28%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$36.50

$33.50

$34.50

$36.00

Mid-Atlantic

(2)

$48.50

$42.50

$43.00

$46.50

ERCOT

(5)

$20.00

$8.50

$5.50

$6.00

New York

(2)

$42.50

$42.50

$40.00

$38.50

New England

(5)

$6.00

$11.50

$4.50

($2.50)

(1) Expected

generation

is

the

volume

of

energy

that

best

represents

our

financial

exposure

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

14

refueling

outages

in

2014

and

2015,

12

in

2016,

and

15

in

2017

at

Exelon-operated

nuclear

plants,

and

Salem.

Expected

generation

assumes

capacity

factors

of

93.6%,

93.5%,

94.1%

and

93.4%

in

2014,

2015

,

2016

and

2017

respectively

at

Exelon-operated

nuclear

plants,

at

ownership.

These

estimates

of

expected

generation

in

2015,

2016

and

2017

do

not

represent

guidance

or

a

forecast

of

future

results

as

Exelon

has

not

completed

its

planning

or

optimization

processes

for

those

years.

(2)

Excludes

EDF’s

equity

ownership

share

of

CENG

Joint

Venture.

(3)

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.

(4)

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.

(5)

Spark

spreads

shown

for

ERCOT

and

New

England.

(6)

Reflects

the

divestiture

impact

of

Fore

River,

Quail

Run

and

West

Valley.

Does

not

include

divestiture

of

Keystone/Conemaugh

or

the

Integrys

acquisition

65

2014 EEI Financial Conference

2014 EEI Financial Conference

ExGen Hedged Gross Margin Sensitivities

(1) Based on September 30, 2014 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; Sensitivities based on commodity exposure which includes open generation and all committed transactions; Excludes EDF’s equity share of CENG

Joint Venture; Reflects the divestiture impact of Fore River, Quail Run and West Valley; Does not include divestiture of Keystone/Conemaugh or the Integrys acquisition

Gross Margin Sensitivities (With Existing Hedges)

(1)

2014

2015

2016

2017

Henry Hub Natural Gas ($/MMbtu)

+ $1/Mmbtu

$15

$120

$440

$830

-

$1/Mmbtu

$10

$(60)

$(400)

$(750)

NiHub ATC Energy Price

+ $5/MWh

$-

$85

$265

$390

-

$5/MWh

$-

$(85)

$(260)

$(390)

PJM-W ATC Energy Price

+ $5/MWh

$(5)

$30

$165

$260

-

$5/MWh

$5

$(25)

$(155)

$(255)

NYPP Zone A ATC Energy Price

+ $5/MWh

$-

$5

$15

$25

-

$5/MWh

$-

$(10)

$(20)

$(25)

Nuclear Capacity Factor

+/-

1%

+/-

$15

+/-

$50

+/-

$45

+/-

$45

66

2014 EEI Financial Conference

2014 EEI Financial Conference

Exelon Generation Hedged Gross Margin Upside/Risk

(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

2015,

2016

and

2017

do

not

represent

earnings

guidance

or

a

forecast

of

future

results

as

Exelon

has

not

completed

its

planning

or

optimization

processes

for

those

years;

The

price

distributions

that

generate

this

range

are

calibrated

to

market

quotes

for

power,

fuel,

load

following

products,

and

options

as

of

September

30,

2014

(2)

Gross

Margin

Upside/Risk

based

on

commodity

exposure

which

includes

open

generation

and

all

committed

transactions

$7,450

$7,300

$8,000

$7,050

Note:

Reflects

the

divestiture

impact

of

Fore

River,

Quail

Run

and

West

Valley;

Does

not

include

divestiture

of

Keystone/Conemaugh

or

the

Integrys

acquisition

67

2014 EEI Financial Conference

2014 EEI Financial Conference

(1)

Mark-to-market rounded to the nearest $5 million

(2)

Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear

Partners and variable interest entities; Total Gross Margin is also net of direct cost of sales for certain Constellation businesses.

Note:  Reflects the divestiture impact of Fore River, Quail Run and West Valley; Does not include divestiture of Keystone/Conemaugh

Illustrative Example of Modeling Exelon Generation             

2015 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$6.75 billion

(B)

Expected Generation (TWh)

97.0

71.3

16.4

9.4

7.1

(C)

Hedge % (assuming mid-point of range)

84.5%

89.5%

100.5%

88.5%

83.5%

(D=B*C)

Hedged Volume (TWh)

82.0

63.8

16.4

8.3

5.9

(E)

Effective Realized Energy Price ($/MWh)

$33.50

$42.50

$8.50

$42.50

$11.50

(F)

Reference Price ($/MWh)

$33.70

$42.75

$6.47

$42.14

$8.95

(G=E-F)

Difference ($/MWh)

$(0.20)

$(0.25)

$2.03

$0.36

$2.55

(H=D*G)

Mark-to-market value of hedges  ($ million)

(1)

$(15) million

$(15) million

$30 million

$5 million

$15 million

(I=A+H)

Hedged Gross Margin ($ million)

$6,750 million

(J)

Power New Business / To Go ($ million)

$400 million

(K)

Non-Power Margins Executed ($ million)

$100 million

(L)

Non-

Power New Business / To Go ($ million)

$300 million

(N=I+J+K+L)

Total Gross Margin

(2)

$7,550 million

Generation

69

2014 EEI Financial Conference

2014 EEI Financial Conference

Exelon Generation Fleet

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

EPA regulations

(1)

Reflects owned generation less announced divestitures of Fore River, Quail Run and West Valley and Keystone Conemaugh

National Scope

•

Power generation assets in 20 states and

Canada

•

Low-cost generation capacity provides

unparalleled leverage to rising commodity

prices

Large and Diverse

•

32 GW of diverse generation

(1)

—

19 GW of Nuclear

—

8 GW of Gas

—

2 GW of Hydro

—

2 GW of Oil

—

1 GW of Wind/Solar/Other

Clean

•

One of nation’s cleanest fleets as

measured by CO2, SO2 and NOx intensity

•

Less than 5% of generation capacity will

require capital expenditures to comply

with Air Toxic rules

70

Exelon Nuclear Fleet Overview (including CENG and Salem)

Plant Location

Type/

Containment

Water Body

License Extension Status / License

Expiration

(1)

Ownership

Spent Fuel Storage/

Date to lose full core

discharge

capacity

(2)

Braidwood, IL

(Units 1 and 2)

PWR

Concrete/Steel Lined

Kankakee River

Filed application in May 2013 (decision

expected in 2015)/ 2026, 2027

100%

Dry Cask

Byron, IL

(Units 1 and 2)

PWR

Concrete/Steel Lined

Rock River

Filed application in May 2013 (decision

expected in 2015)/ 2024, 2026

100%

Dry Cask

Clinton, IL

(Unit 1)

BWR

Concrete/Steel Lined / Mark III

Clinton Lake

2026

100%

Dry Cask

(2016)

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

Application will be filed Dec 2014(decision

expected 2017)/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

Limerick, PA

(Units 1 and 2)

BWR

Concrete/Steel Lined / Mark II

Schuylkill River

Renewed

/

2044,

2049

(5)

100%

Dry Cask

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

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

Nine Mile Point, NY

(Units 1 and 2)

BWR

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

(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

(5)

Limerick Received a 20 year license renewal in October 2014

2014 EEI Financial Conference

71

2014 EEI Financial Conference

World Class Nuclear Operator

(1)

31%

36%

14%

14%

1,208

1,169

1,104

(1)

Exelon fleet averages exclude Salem and CENG

(2)

Source: 2013 Electric Utility Cost Group (EUCG) survey. Includes

Fuel Cost plus Direct O&M divided by net generation

(3)

Source: Platts Nuclear News, Nuclear Energy Institute and Energy

Information Administration (Department of Energy)

Nuclear Production Cost ($/MWh)

(2)

Capacity Factor  (%)

(3)

EXC

EXC

Exelon is consistently one of the lowest-cost and most efficient producers of

electricity in the nation

2014 EEI Financial Conference

72

2014 EEI Financial Conference

Net

nuclear

generation

data

at

ownership

excluding

Salem

for

all

years

CENG excluded thru 2006 -

2014, but included in 2015 and beyond at ownership

2016 includes Clinton Refueling Only outage of shortened duration.

Nuclear Output and Refueling Outages

Fleet Average Refueling Outage Duration (Days)

31%

36%

14%

14%

Nuclear Output

Nuclear Refueling Cycle

•

All Exelon-owned units are on a 24 month cycle

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

Ginna, and Salem U1/U2, which are on 18

month cycles

•

Starting in 2015 Clinton will be on annual

cycles

Actual

Target

# of Refueling Outages

2014 Refueling Outage Impact (Includes CENG)

•

14 planned refueling outages, including 2 at

Salem

•

8 spring refueling outages (average

duration of 25 days)

•

4 fall refueling outages

•

Salem -

1 refueling outage in the spring

and 1 in the fall

•

14 planned refueling outages, including 1 at

Salem

•

7 spring refueling outages and 6 Fall

refueling outages

•

1 Salem fall refueling outage

Exelon fleet averages exclude Salem and CENG

EXC

2014 EEI Financial Conference

2015 Refueling Outage Impact

73

2014 EEI Financial Conference

Nuclear Fuel Costs

(1)

Projected Exelon Uranium Demand

Components of Fuel Expense in 2014

2014 –

2016: 100% hedged in volume

2017:

~96% hedged in volume

2018:

~87% hedged in volume

2019:

~64% hedged in volume

2

1

0

11

10

9

8

7

6

5

4

3

2019E

2018E

2017E

2016E

2015E

2014

Enrichment

33%

Tax/Interest

2%

Conversion

4%

Uranium

40%

Nuclear Waste

6%

Fabrication

15%

(1)

All charts exclude Salem. Includes CENG as of 4/1/2014

(2)

At ownership. Excludes costs reimbursed under the settlement agreement with the DOE

Projected

Total

Nuclear

Fuel

Spend

(2)

0

200

400

600

800

1,000

1,200

2019E

1048

2018E

1027

2017E

1020

2016E

1016

2015E

988

2014E

1000

Nuclear Fuel Capex

Nuclear Fuel Expense (Amortization + Spent Fuel)

2014 EEI Financial Conference

74

2014 EEI Financial Conference

Exelon

Power

Fleet

Overview

(owned

generation,

excludes

wind

and

solar)

(1)  100%, unless otherwise indicated

(2)  Fossil/Hydro Capacity values shown represent summer ratings.  Net Generation Capacity (MW) is stated at proportionate ownership share

Station

Location

Number of

Units

Primary Fuel

Type

Percent

Owned

(1)

Net Generation

Capacity (MW)

(2)

Muddy Run

Drumore, PA

8

Hydro

1070

Notch Cliff

Baltimore, MD

8

Gas

118

Pennsbury

Morrisville, PA

2

Landfill Gas

6

Perryman

Belcamp, MD

5

Oil/Gas

353

Philadelphia Road

Baltimore, MD

4

Oil

61

Richmond

Philadelphia, PA

2

Oil

98

Riverside

Baltimore, MD

3

Oil/Gas

113

Salem

Lower Alloways

Creek Twp, NJ

1

Oil

42.59

16

Schuylkill

Philadelphia, PA

2

Oil

30

Southwark

Philadelphia, PA

4

Oil

52

Westport

Baltimore, MD

1

Gas

115

Southeast Chicago

Chicago, IL

8

Gas

296

Framingham

Framingham, MA

3

Oil

33

Medway

West Medway, MA

3

Oil/Gas

117

Mystic 7

Charlestown, MA

1

Oil/Gas

575

Mystic 8, 9

Charlestown, MA

2

Gas

1418

Mystic Jet

Charlestown, MA

1

Oil

9

New Boston

South Boston, MA

1

Oil

16

Wyman

Yarmouth, ME

1

Oil

5.9

36

Grand Prairie

Alberta, Canada

1

Gas

75

Hillabee

Alexander City, AL

1

Gas

670

Sunnyside

Sunnyside, UT

1

Waste Coal

50

26

Station

Location

Number of

Units

Primary Fuel

Type

Percent

Owned

(1)

Net Generation

Capacity (MW)

(2)

Colorado Bend

Wharton, TX

1

Gas

498

Handley 3

Fort Worth, TX

1

Gas

395

Handley 4, 5

Fort Worth, TX

2

Gas

870

LaPorte

Laporte, TX

4

Gas

152

Mountain Creek 6, 7

Dallas, TX

2

Gas

240

Mountain Creek 8

Dallas, TX

1

Gas

565

Wolf Hollow 1, 2, 3

Granbury, TX

3

Gas

704

Chester

Chester, PA

3

Oil

39

Colver

Colver Twp., PA

1

Waste Coal

25

26

Conowingo

Darlington, MD

11

Hydro

572

Croydon

West Bristol, PA

8

Oil

391

Delaware

Philadelphia, PA

4

Oil

56

Eddystone

Eddystone, PA

4

Oil

60

Eddystone 3, 4

Eddystone, PA

2

Oil/Gas

760

Fairless Hills

Fairless Hills, PA

2

Landfill Gas

60

Falls

Morrisville, PA

3

Oil

51

Gould Street

Baltimore, MD

1

Gas

97

Handsome Lake

Kennerdell, PA

5

Gas

268

Moser

Lower

PottsgroveTwp.,

PA

3

Oil

51

2014 EEI Financial Conference

75

2014 EEI Financial Conference

2014 EEI Financial Conference

Investment in New Generation Technology

Exelon is investing in an innovative, carbon-free, gas-fired technology through an investment in NET Power to

support the development of an 11.4MWe demonstration facility to prove the technology

NET

Power’s

system

has

the

potential

to

transform

both

the

electricity

and

the

oil

and

gas

markets.

Using

a

novel,

supercritical

CO

2

-

power

cycle

known

as

the

Allam

Cycle,

the

technology

is

projected

to

match

or

lower

the

current

cost

of

electricity

from

natural

gas

generation

technologies

while

also

capturing

all

carbon

dioxide

emissions.

The

system

produces

carbon

dioxide

as

a

low-cost,

pipeline-quality

byproduct

as

opposed

to

a

gas

emitted

through

a

stack

in

conventional

power

plants.

The

produced

CO

2

is

ready

for

sequestration

or

use

in

enhanced

oil

recovery.

Exelon is an equity investor in the NET

Power entity and will operate the

demonstration plant

8Rivers developed and patented the

technology and holds an equity stake

in NET Power

CB&I is an equity investor in NET

Power and will provide EPC services

for the demonstration plant

Toshiba is investing in the

development and manufacturing of a

novel supercritical CO2

turbine