Commonwealth Edison 8K Cautionary Statements Regarding Forward-Looking Information | SEC 9 Nov 15

Edison Electric Institute

Financial Conference

November 8–11, 2015

Exhibit 99.1

2015 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 2014 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 2015 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 19; 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.

2015 EEI Financial Conference

2015: An Exceptional Year of Performance

Our utilities are performing at their best levels, our generation business is world class and our

Constellation

business

maximizes

its

value.

will

deliver

earnings

between

$2.40

$2.60

(1)

per share.

•

On track to invest $3.7 billion this year to make the grid smarter, more reliable, and more resilient

•

Exceeding $1 billion in net income this year at Exelon Utilities

•

Constructive regulatory environments across our jurisdictions

–

PECO rate case settlement

–

ComEd formula rate

–

Recent BGE unanimous rate case settlement

•

Industry leading operational excellence

–

Quartile SAIFI performance

–

Quartile

CAIDI

performance

ComEd

and

PECO,

Quartile

BGE

–

Quartile Customer Satisfaction

–

Top Decile

Gas Odor Response

•

Successful generation to load matching strategy is protecting earnings

•

Active role in policy development to deliver Capacity Performance construct

•

Provider

retail

electricity,

serving

TWhs

than

our

nearest

competitor

•

Top 10 marketer of natural gas

•

World Class Operator

–

2015 Nuclear capacity factor through 3Q: 93.8%

–

2015 Power dispatch match through 3Q: 98.7%

–

2015 Renewables energy capture 3Q: 95.6%

(1)

Represents adjusted (non-GAAP) operating earnings. Refer to slide 31 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating earnings

2015 EEI Financial Conference

Looking Ahead

•

The Exelon Strategy

•

Addressing Key Immediate Issues

Capital Allocation

Pepco Holdings Acquisition

Extending Clinton One Year

Cost Management Initiative

•

The Foundation for Exelon’s Growth

The Exelon Strategy

2015 EEI Financial Conference

Our Key Objectives

Employ our integrated model to deliver stable growth, sustainable

earnings and an attractive dividend

•

Stable Growth

–

Grow our

regulated and contracted businesses and

optimize our existing generation portfolio

•

Sustainable Earnings –

Utilities, contracted assets, and balanced

generation to load strategy profits are an engine for predictable earnings

and our generation business positions us to capture market upside

•

Attractive Dividend

–

Dividend will be covered by the utilities, insulated

from the earnings volatility of the generation business

2015 EEI Financial Conference

How We Will Meet Our Objectives

We will produce stable earnings growth of 3-5% per year from 2015 to 2018

(1)

•

Investing more than $18 billion in Exelon’s current utilities through 2020 to modernize the grid and

better serve our customers ($11 billion from 2016-2018)

We will sustain

earnings growth while also preserving the benefit of market upside

through:

•

Ensuring operating excellence across every business

•

Shifting our earnings mix to be more regulated through investments in Exelon’s utilities and the

acquisition of Pepco Holdings (Expect earnings to be ~60% regulated in 2018)

•

Effectively managing our costs

•

Growing the amount of contracted assets in our Exelon Generation portfolio

•

Maximizing the value of our generation fleet and customer base through our proven generation to

load matching strategy

•

Hedging our generation in a manner that preserves upside from our fundamental price view

We will continue to deliver an attractive

dividend

of $1.24 per share

(2)

•

Targeting dividend funding entirely from regulated utilities

•

Our business mix protects our dividend regardless of changing phases of the commodities cycle

(1)

Growth target is a net income compounded annual growth rate (CAGR), assumes September 30, 2015 market prices, and does not include our fundamental market view

of prices

(2)

Dividends are subject to declaration by the Exelon Board of Directors

2015 EEI Financial Conference

We Are Well Down the Path of Delivering on Our Key Objectives

2011

(Pre-CEG Merger)

•

25,544 MW (Total

Capacity)

•

67% Nuclear

•

151 TWh

Generation

•

5.4M Electric Customers

•

0.5M Gas Customers

•

$791M Net Income

(1)

•

$13B Rate Base

•

6,054 Miles of

Transmission Lines

2011 Earnings

(1)

•

29% Utilities

•

71% Generation

World Class

Generator

Top Performing

Utilities

Preeminent

Competitive

Energy

Company

Transforming

the Business

Mix

2014

(Post-CEG Merger)

•

32,753 MW (Total

Capacity)

•

59% Nuclear

(3)

•

205 TWh

Generation

•

6.7M Electric Customers

•

1.2M Gas Customers

•

$962M

Net Income

(1)

•

$20B Rate Base

•

7,435 Miles of

Transmission Lines

2014 Earnings

(1)

•

47% Utilities

•

53% Generation

2018

(Post-PHI Merger)

•

34,800 MW (Total

Capacity)

•

56% Nuclear

(3)

•

206 TWh

Generation

•

8.6M Electric Customers

•

1.3M Gas Customers

•

$1.5B-1.7B Net Income

(1,2)

•

$38B Rate Base

•

~12,000 Miles of

Transmission Lines

•

48 States, DC, & Canada

•

~210 TWh/yr

•

6-8 Bcf

of Gas

2018 Earnings

(1,4)

•

~60% Utilities

•

~40% Generation

(1)

Represents adjusted (non-GAAP) operating earnings. Refer to slide 31 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating earnings.

(2)

Includes after-tax interest expense of (~$150M) for debt held at Corporate related to utility investment

(3)

Includes CENG at ownership; does not assume put exercised

(4)

Based on September 30, 2015 market prices

•

4 States

•

~59 TWh/yr

•

<1 Bcf

of Gas per day

•

48 States, DC & Canada

•

~155 TWh/yr

•

4-6 Bcf

of Gas per day

Addressing Key Immediate Issues

Capital Allocation

Pepco Holdings Acquisition

Extending Clinton One Year

Cost Management Initiative

Capital Allocation

2015 EEI Financial Conference

Delivering Value to Shareholders Through a Principled Capital

Allocation Policy

•

Every

capital

decision

made

maximize

value

our

customers

and

shareholders

•

We are harvesting free cash flow from Exelon Generation to:

–

First, invest in utilities where we can earn an appropriate return,

–

Invest in contracted assets where we can meet return thresholds, and/or

–

Return capital to shareholders by retiring debt, repurchasing our shares, or

increasing our dividend if required investment returns are not met

•

We are committed to maintaining an attractive dividend

•

Our strong balance sheet underpins our capital allocation policy

2015 EEI Financial Conference

Redeploying Exelon Generation’s Free Cash Flow to Maximize Shareholder

Value

2016-2018 Exelon Generation Free Cash Flow

(1,2,3)

and Planned Growth Investment ($M)

~$2,700

~$4,150

Committed Contracted

Generation Growth CapEx

Available for Investing in

Utilities, Contracted Assets

or Returning Capital to

Shareholders

($750)

Committed Non-Contracted

Generation Growth CapEx

($700)

Cumulative ExGen

FCF 2016-18

If investments do not meet our thresholds, we will return capital to shareholders

(1)

Free Cash Flow = Adjusted Cash Flow from Operations less Base CapEx and Nuclear Fuel. Free Cash Flow is midpoint of a range based on September 30, 2015 market prices. 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.

Reconciliation of Free Cash Flow to GAAP can be found on slide 32.

(2)

Does not include an extension of bonus depreciation. A two year extension of bonus depreciation would add ~$200 million of Free Cash Flow

(3)

Does not include impacts of PHI, which would decrease Free Cash Flow by (~$100M)

2015 EEI Financial Conference

Capital Allocation —

Disciplined Commitment to Growth

We will prioritize investment in assets that minimize earnings volatility and support

stable earnings growth

Note: Including PHI would increase combined rate base by $10 billion in 2018; Exelon Utilities 2016-2018 capital investment is $11 billion for existing

Exelon utilities ($15 billion including PHI); Exelon Generation 2016-2018 investment opportunities total $1.6 billion

No incremental equity issuance needed to fund investment

Exelon Utilities

Exelon Generation

•

Investing in utility infrastructure to

benefit our customers by making the grid

smarter, more reliable, and more

resilient

$18 billion from 2016 to 2020

(existing Exelon Utilities)

$25 billion

from 2016 to 2020

(including PHI)

•

Targeting long-term ROE of

10%

•

Growing existing rate base from $22

billion

in 2015 to $28 billion in 2018

•

Earnings

CAGR of 7-9%

from 2015-2018

•

Going forward, we will invest in assets

with contracted cash flows

We are reviewing development

opportunities that may result in

investment of $2.8 billion from

2016 through 2020

Approximately half of any growth

investment will be funded through

structured financing

•

Projects must earn attractive return

(

10% ROE)

Pepco Holdings Acquisition

2015 EEI Financial Conference

Projected Earnings Accretion at Various Earned ROE Levels

(1,2,3)

PHI Acquisition Increases Sustainability of Earnings Growth

Operational improvements should drive enhanced regulatory

outcomes, positively

impacting EPS

$0.06

$0.10

$0.13

2017

$0.02

~$0.00

9% ROE

8% ROE

7% ROE

6% ROE

10% ROE

Base Plan

(1)

~$0.10

$0.12

2018

$0.16

$0.20

~$0.18

2019

$0.21

$0.25

$0.29

$0.25

2020

~$0.20

(~$0.05)

2016

Q3 2015 Guidance

PHI Accretion

2017

~$0.00

2018

$0.07 to $0.12

2019

$0.15 to $0.20

(1)

Base Plan accretion figures represent midpoint of updated guidance range from Q3 2015 earnings call and reflect current PHI business plan

(2)

Chart above illustrates accretion at various weighted average distribution earned ROEs for PHI

(3)

Accretion is measured against Exelon standalone plan, which excludes the impact of PHI acquisition debt and equity

Note: Represents adjusted (non-GAAP) operating earnings. Refer to slide 31 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating earnings

2015 EEI Financial Conference

BGE: A Proven Track Record of Enhancing Utility Value

•

Increased reliability by 10% per year and customer

satisfaction by 3% per year

•

Increased ROE by more than 250 basis points from 2011

to 2015 and grew net income 15% annually over same

period

•

Continued system investments in reliability and safety

necessitate continued rate cases for capital recovery

Delivering value to our customers and regulators by improving reliability while providing

investors with predictable cost recovery and earnings growth

2015E

2014

2013

2012

2011

Operating Net Income

Operating ROE

SAIFI and Customer Satisfaction Index

Operating ROE (%) and Net Income ($M)

10%

100

150

200

250

300

1.2

1.0

0.9

0.8

6.8

7.2

7.7

7.6

7.7

5.0

5.5

6.0

6.5

7.0

7.5

8.0

0.0

0.4

0.8

1.2

1.6

2011

2012

2013

2014

2015E

SAIFI (2.5 Beta)

Customer Satisfaction Index

Note: 2012 ROE and Net Income normalized by excluding one-time $112M rate credit as part of EXC-CEG merger. Operating net income represents adjusted

(non-GAAP) operating earnings. Refer to slide 31 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating earnings

Extending Clinton One Year

2015 EEI Financial Conference

We Will Continue to Operate Clinton for Another Year

What has changed in 2015?

•

Recent

upward

movement

MISO

capacity

prices

$150/MWd

MISO

2015

auction and Illinois Power Authority Zone 4 procurement auction

•

Fleet capacity revenue uplift due to Capacity Performance of $1.4B, beyond our

expectations; MISO will now consider similar market reforms

•

EPA’s Clean Power Plan finalized. Development of Illinois compliance program in

2016, could facilitate significant upside from implementation

•

Legislative engagement on Illinois Low Carbon Portfolio Standard. Resolution of

budget crisis should facilitate legislative consideration in 2016

•

Improved operating efficiency and agile nuclear fuel procurement strategy

•

Over the last 2 years Clinton has deferred approximately $100M of strategic

capital, minimizing the cost of maintaining the optionality at Clinton

•

Significant potential NiHub

upside in the out-years not yet reflected in illiquid

forward markets

“If we do not see a path to sustain profitability for these units . . . we will be forced

to retire them.” -- Chris Crane, July 31, 2014

2015 EEI Financial Conference

More Progress Necessary for Clinton to Operate Beyond 2017

MISO Reforms:

•

MISO is

committed to evaluate Zone 4 market design

•

Illinois Commerce Commission is holding workshops to examine

potential fixes to address Zone 4

•

Reforms must provide strong revenues like the PJM reforms

effectuated

Areas of Additional Progress Needed:

•

Passage of Low Carbon Portfolio Standard

•

Illinois implementation of EPA’s Clean Power Plan must fully recognize

the value of Clinton

Cost Management Initiative

2015 EEI Financial Conference

The Sustainability and Growth of Our Earnings Will be

Supported by an Aggressive Cost Management Program

•

Exelon has launched a cost management program across to provide

sustainable improvement to the Company’s earnings trajectory

•

Estimated EPS benefit of $0.13 to $0.18

(1,2)

•

An additional $50 million of nuclear fuel savings already reflected in hedge

disclosures

•

Savings

begin

2016

and

will

fully

realized

2018

(1)

Based on projected 2018 share count of 965M shares, which assumes PHI merger closes

(2)

Represents adjusted (non-GAAP) operating earnings. Refer to slide 31 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating earnings

The initiative will achieve $300-$350 million of annual cost savings at

Exelon Generation and Corporate

Financial Data

The Foundation for Exelon’s

Growth

2015 EEI Financial Conference

2015 Operating Earnings Guidance

2015 Initial Guidance

$2.25 -

$2.55

(1)

$1.15 -

$1.35

$0.45 -

$0.55

$0.35 -

$0.45

$0.20 -

$0.30

ExGen

ComEd

PECO

BGE

2015 Revised Guidance

(Disclosed on Q3 2015 Earnings Call)

$2.40 -

$2.60

(1)

$1.35 -

$1.45

$0.45 -

$0.55

$0.35 -

$0.45

$0.25 -

$0.35

~($0.10)

ExGen

PECO

ComEd

BGE

HoldCo

(1)

Earnings guidance for OpCos

may not add up to consolidated EPS guidance. Represents adjusted (non-GAAP) operating earnings. Refer to slide 31 for a list of adjustments

from GAAP EPS to adjusted (non-GAAP) operating earnings

2015 EEI Financial Conference

Exelon Utilities ($M)

Exelon Generation($M)

(1)

2018E

3,575

2017E

3,800

2016E

3,950

2015E

3,700

Smart Grid/Smart Meter

Gas Delivery

Electric Transmission

Electric Distribution

2016E

3,025

2015E

3,675

1,950

2017E

2018E

100

2,575

Base

Nuclear Fuel

Committed Growth

Our Capital Plan Drives Stable Earnings Growth

475

350

300

400

450

825

975

650

550

2,100

2,225

2,500

2,400

175

250

1,225

1,100

925

950

1,300

1,225

1,000

900

1,150

700

650

Note: Numbers rounded to nearest $25M

(1)

Figures reflect cash CapEx and CENG fleet at 100%; 2014 EEI presentation showed CENG fleet at ownership; Does not include potential pipeline of contracted

generation growth mentioned on slides 11 and 12

2015 EEI Financial Conference

Exelon’s Existing Utilities Drive Stable Earnings Growth

$1,400

$1,250

$1,450

$1,350

$1,300

$1,200

$1,150

$1,100

$1,050

$1,000

$1,425

2018

2017

2015

$1,250

$1,150

2016

$1,350

$1,275

$1,200

$1,000

Projected average earnings growth of ~7-9% per year from 2015-2018

$1,100

Note: Does not include PHI net income and represents adjusted (non-GAAP) operating earnings. Refer to slide 31 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating

earnings. Does not include an extension of bonus depreciation. Impact of a 2-year bonus depreciation extension for 2015 and 2016 would be ~($10M) in 2015 and ~($25M) a year in 2016-

2018. Excludes after-tax interest expense held at Corporate for debt associated with existing utility investment, which is (~$25M) a year.

2015 EEI Financial Conference

Continued Focus on Our Balance Sheet

Our strong balance sheet supports our disciplined commitment to growth

Exelon Consolidated

(1)

FFO/Debt

Exelon Consolidated FFO/Debt

S&P Threshold

(2)

Solid investment grade credit ratings are a financial priority

(1)

Metrics include PHI financing. Because of ring-fencing, S&P deconsolidates BGE's and PHI’s financial profile from Exelon and analyzes them solely as equity investments

(2)

Exelon Consolidated threshold of 18% is based on the S&P Exelon Corp Summary Report published on August 5, 2015

(3)

Current senior unsecured ratings as of 11/3/2015 for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd and PECO

(4)

All ratings are “Stable” outlook, except for at Fitch, which has ComEd on “Positive” and Exelon on “Ratings Watch Negative,” and Moody’s, which has ComEd on “Positive” outlook

20%

15%

16%

17%

18%

19%

20%

21%

2016

2017

2018

Current Ratings

(3,4)

ExCorp

ComEd

PECO

BGE

ExGen

Recent Commentary

Moody’s

Baa2

Aa3

Baa2

“Exelon maintains a strong consolidated financial profile…which should

produce steady

ratios of cash flow to debt in the low 20% range which, when combined with adequate

liquidity reserves and a growing focus on regulated investment opportunities, positions

Exelon firmly within its current rating category.” Moody’s Issuer Comment, June 11, 2015

S&P

BBB-

A-

BBB

“ExGen

generates

significant

portion

earnings

from

its

retail

operations.

Through

retail

and wholesale channels, ExGen now provides nearly 5% of total U.S. power demand, and

enjoys regional diversity. The company's generation units are well positioned to grow where

capacity available for competitive supply has room to grow. We expect these incremental

revenue streams to make the consolidated Exelon somewhat more resilient to commodity

prices.” S&P Summary Analysis; March 9, 2015

Fitch

BBB+

A-

BBB

“The majority of capital investment is allocated to EXC’s three utility subsidiaries, which

should provide a more stable earnings base.“ Fitch Full Ratings Report; October 15, 2015

“Exgen’s

financial position has stabilized in recent years, and remains solidly within the

investment-grade category. ” Fitch Full Ratings Report; September 11, 2015

2015 EEI Financial Conference

Exelon-PHI Debt Maturity Profile

(1)

2023

800

2021

2022

1,425

900

2020

3,650

2019

950

2018

1,600

2017

2,925

2016

1,575

100

2015

PHI Regulated

EXC Regulated

PHI Holdco

ExCorp

ExGen

As of 10/31/15

($M)

Debt Exchange Underway on Exelon Corp Notes due 2025, 2035 and 2045

(1)

ExCorp debt includes acquisition debt, including $1,150M mandatory convertible units remarketing in 2017; ExGen debt includes legacy CEG debt; Excludes securitized debt

and non-recourse debt

2015 EEI Financial Conference

EPS Sensitivities

(1)

Based on September 30, 2015 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. Represents adjusted (non-GAAP) operating earnings. Refer to slide 31 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating earnings

(2)

Assumes 2018/2019 auction cleared volumes

(3)

Share count used to calculated EPS impact assumes PHI transaction closes

2015

2016

2017

2018

Fully Open

Henry Hub Natural Gas

+$1/MMBtu

($0.00)

$0.08

$0.31

$0.46

$0.56

-$1/MMBtu

$0.01

($0.08)

($0.30)

($0.46)

($0.55)

NiHub ATC Energy Price

+$5/MWh

($0.00)

$0.07

$0.19

$0.28

$0.31

-$5/MWh

$0.00

($0.07)

($0.19)

($0.28)

($0.31)

PJM-W ATC Energy Price

+$5/MWh

($0.00)

$0.03

$0.09

$0.16

$0.19

-$5/MWh

$0.00

($0.03)

($0.09)

($0.16)

($0.19)

PJM Capacity Market

(2)

+$10/MW-day

$0.04

-$10/MW-day

($0.04)

30 Year Treasury Rate

+50 basis points

$0.02

$0.03

-50 basis points

($0.02)

($0.03)

Share Count

(3)

(millions)

893

927

947

965

2015 EEI Financial Conference

Modeling Combined Exelon & Pepco Holdings Pro Forma EPS

2016

2017

2018

Source of Data

Exelon

Utilities Net Income

($M)

$1,175

$1,275

$1,350

Model using midpoint of Net

Income

guidance

from slide

Exelon

Generation Net Income

($M)

$X,XXX

Model using Gross Margin disclosure

from slide 45

Corporate Net Income

($M)

($25)

Model using interest

expense

information in note on slide 25

Exelon Standalone Net Income

($M)

$X,XXX

Standalone Share Count

(millions)

877

881

886

Approximate share

count when PHI

equity issuance is excluded

Standalone EPS

$X.XX

Take

Exelon standalone Net Income and

divide by standalone share count

PHI Accretion

Guidance

($0.05)

$0.00

$0.10

Midpoint

of Q3 2015 guidance for PHI

accretion from slide 14

Pro

Forma EPS

$X.XX

Take Exelon

standalone Net Income and

add PHI accretion

Pro

Forma

Share Count

(millions)

927

947

965

From slide 28

2015 EEI Financial Conference

•

Exelon’s pension funding and investment strategies have continued to drive improvements

in the overall funded status of Exelon’s pension plans

•

Given the continued improvements in the funded status of the Exelon Corporation

Retirement Program (ECRP), traditional defined benefit plan (87% funded at October 31,

2015), and its positive exposure to an improving rate environment; Exelon is evaluating

opportunities to optimize our pension contribution strategy going forward

•

Exelon’s standard Pension/OPEB assumptions and sensitivities will be provided as part of

Q4 2015 earnings disclosures

Pension and OPEB Update

Pension Funded Status: % Funded

(1)

Pension Unfunded Status ($B)

Note: October 2015 numbers are preliminary estimates and are subject to change

$500M

(1) Assets as a % of PBO Liability

December

31,

2014

October 31, 2015

$3.4B

$2.9B

December

31,

2014

October 31, 2015

81%

84%

2015 EEI Financial Conference

GAAP to Operating Adjustments

•

Exelon’s 2015 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:

–

Mark-to-market adjustments from economic hedging activities

–

Unrealized losses from NDT fund investments to the extent not offset by contractual accounting as

described in the notes to the consolidated financial statements

–

Certain

costs

incurred

associated

with

the

Integrys

and

pending

Pepco

Holdings,

Inc.

acquisitions

–

Mark-to-market adjustments from forward-starting interest rate swaps related to anticipated financing for

the pending PHI acquisition

–

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

the

date

acquisition

Integrys

2014

–

Non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation

related to the non-regulatory units

–

Impairment of investment in long-term generating leases

–

Favorable settlement of certain income tax positions on Constellation’s pre-acquisition tax returns

–

Generation’s non-controlling interest related to CENG exclusion items

–

Other unusual items

2015 EEI Financial Conference

Free Cash Flow GAAP to Non-GAAP Reconciliation

2016-2018 ExGen

Free Cash Flow Calculation ($M)

2016-2018

Estimate

Adjusted Cash from Operations

(1)

$10,250

Non-Growth Capital Expenditures

($2,975)

Nuclear Fuel Capital Expenditures

($3,125)

Free

Cash Flow before Growth CapEx

and Dividend

$4,150

(1)

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

Exelon Utilities

2015 EEI Financial Conference

Operations

Metric

At CEG Merger (2012)

Post CEG Merger (2015)

BGE

PECO

ComEd

BGE

PECO

ComEd

Electric Operations

OSHA Recordable Rate

OSHA Severity Rate

2.5 Beta SAIFI (Outage

Frequency)

2.5 Beta CAIDI (Outage Duration)

Customer

Operations

Customer Satisfaction

Service Level % of Calls

Answered in <30 sec

Abandon Rate

Gas Operations

Percent of Calls Responded to in

<1 Hour

Gas

Operations

Gas

Operations

3rd Party Damages per 1000 Gas

Locates

Overall Rank

Electric Utility Panel of 24

Utilities

Operational Excellence Drives Value for Customers, Communities,

and Shareholders

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

2015 EEI Financial Conference

2018E

950

2017E

875

2016E

825

2015E

700

2018E

725

2017E

725

2016E

700

2015E

600

2018E

1,900

2017E

2,200

2016E

2,425

2015E

2,425

Exelon Utilities: Capital Plan

Smart Grid/Smart Meter

(1)

Gas Delivery

Electric Transmission

Electric Distribution

($ in millions)

(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

125

175

225

250

575

625

375

300

100

175

225

200

1,450

1,475

1,625

1,475

350

400

475

300

350

400

475

125

200

325

400

2015 EEI Financial Conference

Exelon Utilities: Rate Base

(1,4)

and ROE Targets

2015E

Long-Term Target

Equity Ratio

52%

~50-53%

Earned ROE

9-10%

10%

2015E

Long-Term Target

Equity Ratio

~46%

~50-53%

(2)

Earned ROE

~8%

Based on 30-yr

US Treasury

(3)

($ 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)

Rate base does not include extension of bonus depreciation

2015E

Long-Term Target

Equity Ratio

54%

~50-53%

Earned ROE

11-12%

10%

1.5

1.7

1.5

1.6

8.0

8.9

9.8

10.5

3.9

4.2

4.4

4.7

3.1

3.2

3.4

3.6

2.8

3.2

3.6

3.7

0.8

0.9

1.0

1.1

1.4

1.2

1.4

1.3

2018E

6.4

2017E

5.9

2016E

5.3

0.7

2015E

5.0

0.6

2018E

7.3

2017E

6.9

2016E

6.5

6.0

2015E

2018E

14.2

2017E

13.4

12.1

2016E

2015E

10.8

Gas

Transmission

Distribution

2015 EEI Financial Conference

BGE

2015 load growth is greater

than 2014, attributed to

improving economic conditions

and moderate customer

growth, partially offset by

energy efficiency.

Exelon Utilities Load

2015E

2014

PECO

2015 load growth is flat to

2014, driven by slowly

improving economic conditions

coupled with solid residential

customer growth, offset by

energy efficiency.

(0.6%)

2015E

2014

Philadelphia GMP

1.8%

Philadelphia

Unemployment

5.2%

Baltimore GMP

2.3%

Baltimore Unemployment

5.5%

2015E

(0.1%)

2014

Large C&I

Residential

Small C&I

All Customers

ComEd

2015 load growth is lower than

2014 (impacts of energy

efficiency partially offset by

slowly improving economy)

with Residential and Large C&I

trending downward.

Chicago GMP

2.1%

Chicago Unemployment

5.4%

0.0%

0.1%

0.5%

0.2%

0.0%

0.1%

(0.1%)

(1.6%)

(1.2%)

0.5%

1.0%

(0.8%)

1.2%

0.1%

(0.7%)

0.2%

(0.8%)

0.3%

(0.3%)

(1.3%)

0.7%

Notes: Data is weather normalized. Source of economic outlook data is IHS (September 2015). Assumes 2015 GDP of 2.5% and U.S. unemployment of 5.1%.

ComEd has the ROE collar as part of the distribution formula rate and BGE is decoupled which mitigates the load risk. QTD and YTD actual data can be found in earnings release tables.

BGE amounts have been adjusted for prior quarter true-ups.

2015 EEI Financial Conference

ComEd April 2015 Distribution Formula Rate

Docket #

15-0287

Filing Year

2014

Calendar

Year

Actual

Costs

and

2015

Projected

Net

Plant

Additions

are

used

set

the

rates

for

calendar

year

2016. Rates currently in effect (docket 14-0312) for calendar year 2015 were based on 2013 actual costs and 2014

projected net plant additions

Reconciliation Year

Reconciles

Revenue

Requirement

reflected

rates

during

2014

Actual

Costs

Incurred.

Revenue

requirement

for

2014

based

docket

13-0318

(2012

actual

costs

and

2013

projected

net

plant

additions)

approved

December

2013 and reflects the impacts of PA 98-0015 (SB9)

Common Equity Ratio

~ 46%

for

both

the

filing

and

reconciliation

year

ROE

9.14%

for the filing year (2014

30-yr

Treasury Yield of 3.34% + 580 basis point risk premium) and 9.09% for the

reconciliation

year

(2014

30-yr

Treasury

Yield

3.34%

580

basis

point

risk

premium

–

basis

points

performance

metrics penalty). For

2015 and 2016, 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)

$8,277

million

–

Filing

year

(represents

projected

year-end

rate

base

using

2014

actual

plus

2015

projected

capital

additions). 2015 and 2016 earnings will reflect 2015 and 2016 year-end rate base respectively.

$7,082 million -

Reconciliation year (represents

year-end rate base for 2014)

Revenue Requirement

Decrease

(1)

$55M decrease ($145M decrease due to the 2014 reconciliation offset by a $90M increase related to the filing year).

The 2014 reconciliation impact on net income was recorded in 2014 as a regulatory asset.

Timeline

•

04/15/15 Filing Date

•

240 Day Proceeding

•

ICC order expected to be issued by December 11, 2015

The

2015

distribution

formula

rate

filing

establishes

the

net

revenue

requirement

used

set

the

rates

that

will

take

effect

January

2016

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 (2014) and current year (2015) projected plant additions.

•

Annual Reconciliation: For the prior calendar year (2014), this amount reconciles the revenue requirement reflected in rates during the prior year

(2014)

effect

the

actual

costs

for

that

year.

The

annual

reconciliation

impacts

cash

flow

the

following

year

(2016)

but

the

earnings

impact

has been recorded in the prior year (2014) as a regulatory asset.

Given the retroactive ratemaking provision in the Energy Infrastructure Modernization Act 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

Note: Disallowance of any items in the 2015 distribution formula rate filing could impact 2015 earnings in the form of a regulatory asset adjustment

(1)

Amounts represent ComEd’s position filed in surrebuttal testimony on August 20, 2015

2015 EEI Financial Conference

PECO Electric Distribution Rate Case & Proposed Settlement

Docket #

R-2015-2468981

Test Year

2016 Calendar Year

Requested

Revenue Requirement

$190M

Requested

Common Equity Ratio

(1)

53.36%

Requested Rate of Return

ROE: 10.95%; ROR:

8.19%

Proposed Rate Base

$4.1B

Proposed

Revenue

Requirement

Settlement

Increase

$127M

Authorized Returns

(2)

N/A

System Average Increase as % of overall bill

2.9%

Timeline

•

3/27/15 –

PECO filed electric distribution rate case with PaPUC

•

9/10/15 Settlement filed with all intervening parties

•

10/28/15 –

ALJ issued

Recommended

Decision that settlement be approved

•

December 2015 –

PUC Decision

•

Increased rates effective on January 1, 2016

The proposed Revenue Requirement increase of $127M represents 67% of the

Company’s original proposal

(1)

Reflects PECO’s expected capital structure as of 12/31/2016

(2)

Due to the “black box” nature of the settlement, Authorized Return was not agreed upon by the parties in determining the ultimate revenue requirement increase

2015 EEI Financial Conference

PECO Electric LTIIP -

System 2020

•

PECO filed its Electric Long Term Infrastructure Improvement Plan (“LTIIP”) along with its

associated recovery mechanism the Distribution System Improvement Charge (“DSIC”) on

March 27, 2015 (with Electric Distribution Rate Case)

LTIIP includes $275 million in incremental capital spending from 2016-2020 focusing

on the following areas:

Cable Replacement

Storm Hardening Programs

Substation replacement and upgrades

DSIC mechanism will allow recovery of eligible LTIIP spend between rate cases if the

electric distribution ROE falls below the DSIC ROE established by PaPUC. The current

Electric DSIC ROE is 10.0%.

Approved on 10/22/15

•

PECO

also

proposed

the

concept

constructing

one

pilot

microgrid

projects

part of a future LTIIP update ($50-$100M). The objective is to evaluate and test emerging

microgrid

technologies that could enhance reliability and resiliency by replacing obsolete

infrastructure as an alternative to traditional solutions.

LTIIP guarantees at least 10% ROE on capital improvements made on behalf of

PECO customers

2015 EEI Financial Conference

PHI Capital Plan and Rate Base

675

700

725

700

350

375

275

325

275

2018E

1,350

2017E

1,400

2016E

1,375

2015E

(2)

1,300

Pepco

DPL

ACE

4.0

4.4

4.8

5.1

2.4

2.5

2.7

3.0

1.7

1.9

2.2

2.1

10.2

2018E

2017E

9.6

2016E

8.8

2015E

8.1

(1)

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

(2)

Denotes year end rate base

(3)

CapEx

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

Capital Expenditures ($M)

(1,3)

Rate Base ($B)

(1,2)

2015 EEI Financial Conference

Settlement

Party

testimony

(Oct 30)

Non-

settling

party

testimony

(Nov 17)

Public Interest

Hearings

(Dec 2-4)

Initial

Briefs Due

(Dec 11)

Reply Briefs

Due

(Dec 18)

Expected

PSC Order

(Q1 2016)

Pepco Holdings: DCPSC Procedural Timeline

Exelon Generation

2015 EEI Financial Conference

Our Generation to Load Strategy Delivers Sustainable Earnings

in Volatile Markets

•

Since the Constellation merger, we have improved our generation to load match through growing our customer load business, both

organically and through disciplined acquisitions like Integrys

•

This strategy and hedging with a fundamentals driven approach has meaningfully benefitted earnings over the last two years

•

High volatility: We captured higher prices for our generation during periods of extreme weather while managing our load obligations. During

periods of high volatility, generation availability is of utmost importance. During the polar vortex of 2014, our 2 GW of peaking capability created

significant

value

the

energy

and

ancillary

markets.

During

the

polar

vortex,

made

~$100

million

(3)

•

Low volatility: During periods of low volatility, we captured higher margins as we realized a lower cost to serve our customers and we optimized

the

value

our

dispatchable

fleet

through

load

sales.

This

year

alone,

have

made

~$250

million

result

lower

cost

serve

load

•

Generation to Load match also provides us with an important channel to market for our hedging activities which is important in times of low

liquidity and in places where there is not an active market

(1)

Owned

and

contracted

generation

capacity

converted

from

MWh

assuming

100%

capacity

factor

(CF)

for

all

technology

types,

except

for

renewable

capacity

which

shown

estimated

(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 9/30/2015

(3)

Excludes the impact of plant outages, primarily at Calvert Cliffs prior to us operating the plant

2012 Generation Load Match (TWh)

(1,2)

116

118

Midwest

New England

Canada

South/West/

New York

Mid-Atlantic

ERCOT

Intermediate

Baseload

Peaking

Renewables

Expected Generation

Expected Load

Generation Capacity:

111

2016 Generation Load Match (TWh)

(1,2)

Midwest

New England

Canada

South/West/

New York

Mid-Atlantic

ERCOT

2015 EEI Financial Conference

Exelon Generation –

Optimizing the Portfolio and Positioning it

for Market Upside

(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, operating services agreement with Fort Calhoun 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

•

Capacity Performance added approximately $1B in gross margin over the 2016 to 2018

period

•

Timing of hedge decisions creates value

•

Positioning

portfolio

reflect

our

fundamental

views

–

currently

carrying

larger

open

position in 2017 and 2018

•

Intra-year hedging flexibility to take advantage of volatility

•

Using cross-commodity spreads in NiHub: 7-10% of the portfolio in 2017 is in

cross-commodity hedges and 3-6% in 2018

Gross Margin Category ($M)

(1)

2015

2016

2017

2018

Open Gross Margin(including South, West, & Canada hedged

GM)

(3)

$5,150

$5,650

$5,800

$6,100

Mark-to-Market of Hedges

(3,4)

$2,200

$1,200

$750

$250

Power New Business / To Go

$50

$500

$800

$1,000

Non-Power Margins Executed

$400

$200

$100

$50

Non-Power New Business / To Go

$50

$250

$350

$450

Total Gross Margin

(2)

$7,850

$7,800

$7,850

2015 EEI Financial Conference

Electric Load Serving Business: Market Landscape

Total

U.S.

Power

Market

2015

(3,725

TWh

load)

(1)

Eligible Non-

Switched

Eligible

Switched

Muni/Co-Op Market

Other

Ineligible

Constellation Active Retail Electric Markets

Improved competitive landscape observed across many markets

•

Conditions have improved in many markets as impacts of the Polar

Vortex have played out

•

Some suppliers have taken steps to reduce exposure to weather-

sensitive customer loads following the Polar Vortex

Retail transactions and new entrant activity down in 2015

•

M&A, exits and divestiture activity down from 2014 levels

•

Fewer new entrants have entered the market in 2015

Competitive retail market expected to grow modestly over the

next five years (2015-2019)

•

C&I switched market to grow by about 8%

•

Residential switched market to grow by about 7%

Market Landscape

(1)

(1) Sources are EIA, DNV GL, and internal estimates

Existing suppliers continue to expand market footprint and

product portfolio

•

Several existing suppliers have expanded into new states

•

Energy efficiency and distributed energy among most popular for

cross-selling opportunities

Constellation is the #1 Provider of Retail Electricity in the United States

2015 EEI Financial Conference

Our Electric Load Serving Business Provides Sustainable

Earnings and Stable Earnings Growth

70-80%

20-30%

2016E

165

70-80%

20-30%

2015E

165

60-70%

30-40%

2017E

165

2018E

210

75-85%

15-25%

2017E

70-80%

20-30%

2015E

195

65-75%

25-35%

210

75-85%

15-25%

2016E

210

Retail Load

(2)

Total Contracted

Wholesale Load

2015 EEI

Commercial Load Projections

(1)

2015 –

2018 TWh

2014 EEI

Commercial Load Projections

(1,3)

2015 –

2017 TWh

(1)

Numbers and percentages are rounded to the nearest 5

(2)

Index load expected to be 25% to 35% of total forecasted retail load

(3)

Excludes Integrys

acquisition completed in November 2014

Our growing load business provides a channel to market that reduces the reliance on lower margin over-

the-counter products

100

120

140

160

180

200

220

100

120

140

160

180

200

220

2015 EEI Financial Conference

Our NiHub

Strategy Recognizes the Lack of Liquidity and

Disconnect Between our Fundamental View of Prices

Incremental coal retirements will lead to continued volatility and higher dispatch costs, creating $2-$3/MWh

of power price

upside in NiHub

in 2017-2018

Forward market heat rates expanded again through 2015

•

Our portfolio is positioned to take advantage of

expected volatility and power price upside

•

2017-2018 average upside of $2-$3/MWh

•

Power

exposure

NiHub

above

purely

ratable:

•

17-20% behind ratable in 2017

•

13-15% behind ratable

in 2018

•

The increased reliance on natural gas as coal plants retire

has impacted prices

•

Our PJM forecast includes 20+GW of new CCGTs, full

compliance with state renewables requirements and

essentially flat load growth, in addition to coal retirements

2012-2014

2015

2016

PJM/MISO Coal Retirements

PJM & MISO Annual Coal Retirements

PJM & MISO Cumulative Coal Retirements

2017

2018

Nihub ATC Prices ($/MWh)

Nihub Forecast (09/30)

Nihub Market (09/30)

8.0

8.5

9.0

9.5

10.0

10.5

11.0

2016_NiHub_HR

2017_NiHub_HR

2018_NiHub_HR

2015 EEI Financial Conference

Capacity Markets: PJM

$142

$136

$135

$181

$1,400

$1,300

$1,200

$1,100

$1,000

$900

$800

$200

$150

$100

$50

2018

2017

2016

2015

Exelon Fleet Weighted Price ($/MWd)

Revenue ($M)

PJM Capacity Revenues

(1,2,3)

(1) Revenues reflect capacity cleared in Base, CP transitional & incremental auctions and are for calendar years

(2) Revenues reflect owned and contracted generation

(3) Reflects 50.01% ownership at CENG

(4) Volumes at ownership. Rounded.

Cleared Volumes

(MWs)

(4)

Price

Base

Price

ComEd

Fossil/Other

$134.00

$151.50

$215.00

$200.21

Nuclear

9,950

$134.00

9,975

$151.50

8,625

$215.00

$200.21

Total

9,950

$134.00

9,975

$151.50

8,625

$215.00

$200.21

EMAAC

Fossil/Other

$134.00

850

$151.50

2,075

$225.42

1,050

$210.63

Nuclear

3,950

$134.00

4,950

$151.50

4,325

$225.42

$210.63

Total

3,975

$134.00

5,800

$151.50

6,400

$225.42

1,050

$210.63

SWMAAC

Fossil/Other

$134.00

$151.50

$164.77

$149.98

Nuclear

425

$134.00

825

$151.50

850

$164.77

$149.98

Total

425

$134.00

825

$151.50

850

$164.77

$149.98

BGE

Fossil/Other

$134.00

150

$151.50

300

$164.77

425

$149.98

Nuclear

$134.00

$151.50

$164.77

$149.98

Total

$134.00

150

$151.50

300

$164.77

425

$149.98

Rest of MAAC/RTO

Fossil/Other

$134.00

$151.50

265

$164.77

$149.98

Nuclear

775

$134.00

800

$151.50

$164.77

$149.98

Total

775

$134.00

800

$151.50

265

$164.77

$149.98

GRAND TOTAL

Fossil/Other

100

1,000

2,640

1,550

Nuclear

15,100

16,550

13,800

Total

15,200

17,550

16,440

1,550

16/17

Transition

Auction

17/18

Transition

Auction

18/19

Base Auction

2015 EEI Financial Conference

Capacity Markets: ISO-NE, NYISO, MISO

(1)

ISO-NE: ISO New England; NEMA: Northeastern Massachusetts and Boston; SEMA: Southeastern Massachusetts

(2)

NYISO: New York Independent System Operator

(3)

Represents offered capacity at ownership

(4)

AMIL: Ameren Illinois AMIL capacity price represents PRA auction clearing price for Zone 4 in $/MWd

2015/2016

2016/2017

2017/2018

2018/2019

ISO-NE

(1)

NEMA

Capacity

(3)

(MW)

2,100

Price ($/MWd)

$104

$222

$500

$318

SEMA

Capacity

(3)

(MW)

230

Price ($/MWd)

$104

$105

$234

$557

NYISO

(2)

Capacity

(3)

(MW)

1,100

MISO

Zone 4

Capacity

(3)

(MW)

1,100

Price ($/MWd)

(4)

$150

2015 EEI Financial Conference

Natural Gas Marketing Platform

Active Natural Gas Markets

Supply

~4-6

Bcf

per

day

delivered

competitive

markets

growing

6-8

Bcf

2018

Transportation

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

Trading

Active

participant

all

major

supply

basins,

markets,

and

trading

points

North

America

Volume Management

Schedule, nominate and balance behind more than 120 LDCs

Gas Generation

Gas Toll

Owned gas storage

contracts

Major office locations

2015 EEI Financial Conference

•

States distribute allowances equal to the number of CO2

emissions allowed

•

At the end of each compliance period, affected electric

generating units (EGUs) must surrender allowances equal to

their emissions

•

States may allow affected EGUs to buy or sell allowances

with other parties

One

one

ton

CO2

emissions

allowance

State Mass Goal

A facility that produces more

emissions than it has allowances may

purchase allowances from another

facility that has extra allowances

State Rate Standard: 1,000 lb/MWh

Rate

Standard

ERC

Rate

Standard

Emissions Rate: 0 lb/MWh

Emissions Rate: 2,000 lb/MWh

•

Emission rate credits (ERCs) are created when incremental

nuclear or incremental renewables generate electricity

•

Emitting generators must purchase sufficient ERCs to

reduce their emission rate to the target level

EPA Clean Power Plan: Compliance Pathways

Mass Budget

Emissions Rate

Exelon recommends that states adopt mass-based plans that include both existing and new units because that is

the best way to level the playing field and ensure that clean resources like nuclear receive value for the carbon-

free, always-on electricity that Exelon provides. It is also the best way to minimize overall costs to consumers and

preserve electric reliability while achieving verifiable carbon reductions

2015 EEI Financial Conference

Exelon Nuclear Fleet Overview (including CENG and Salem)

Plant Location

Type/

Containment

Net Generation

Capacity (MW)

(5)

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

2,389

Filed application in May 2013 (decision

expected in early 2016)/ 2026, 2027

100%

Dry Cask

Byron, IL

(Units 1 and 2)

PWR

Concrete/Steel Lined

2,347

Filed application in May 2013 (decision

expected in 2015)/ 2024, 2026

100%

Dry Cask

Clinton, IL

(Unit 1)

BWR

Concrete/Steel Lined / Mark III

1,069

2026

100%

Dry Cask

(2016)

Dresden, IL

(Units 2 and 3)

BWR

Steel Vessel / Mark I

1,845

Renewed / 2029, 2031

100%

Dry Cask

LaSalle, IL

(Units 1 and 2)

BWR

Concrete/Steel Lined / Mark II

2,320

Filed application December 2014

(decision expected 2017)/2022, 2023

100%

Dry Cask

Quad Cities, IL

(Units 1 and 2)

BWR

Steel Vessel / Mark I

1,403

Renewed / 2032

75% Exelon, 25% Mid-

American Holdings

Dry Cask

Limerick, PA

(Units 1 and 2)

BWR

Concrete/Steel Lined / Mark II

2,317

Renewed / 2044, 2049

100%

Dry Cask

Oyster Creek, NJ

(Unit 1)

BWR

Steel Vessel / Mark I

625

Renewed / 2029(3)

100%

Dry Cask

Peach Bottom, PA

(Units 2 and 3)

BWR

Steel Vessel / Mark I

1,221

Renewed / 2033, 2034

50% Exelon, 50% PSEG

Dry Cask

TMI, PA

(Unit 1)

PWR

Concrete/Steel Lined

837

Renewed / 2034

100%

2023

Salem, NJ

(Units 1 and 2)

PWR

Concrete/Steel Lined

1,005

Renewed / 2036, 2040

42.6% Exelon, 57.4%

PSEG

Dry Cask

Calvert Cliffs, MD

(Units 1and 2)

PWR

Concrete/Steel Lined

878

Renewed / 2034, 2036

100% CENG(4)

Dry Cask

R.E. Ginna, NY

(Unit 1)

PWR

Concrete/Steel Lined

288

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

838

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. EDF has a 49.99% ownership interest in CENG.

(5)

Net generation capacity is stated at proportionate ownership share. Based on 2015 projected full year

2015 EEI Financial Conference

World

Class

Nuclear

Operator

(1)

31%

14%

1,208

1,169

1,104

Nuclear

Total

Generating

Cost

($/MWh)

(2)

Capacity Factor

(%)

(3)

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

Over the next five years, Exelon Nuclear projects a negative cost CAGR, while maintaining strong

generation performance

$31.37

2014

Exelon

2010

2011

2012

2013

2014

65%

70%

75%

80%

85%

90%

95%

100%

2010

2011

2012

2013

2014

(1)

2010 – 2013 Exelon fleet averages exclude Salem, Ft. Calhoun, and CENG; 2014 Exelon fleet averages exclude Salem and Ft. Calhoun

(2)

Total Generating Cost is defined as cost to produce one MWh of energy, including fuel, materials, labor, contracting, capital expenditures, insurance and the majority of

overhead expenses including benefit costs associated with labor but excludes property taxes, unit contingent costs and risks, costs due to unknown future regulatory changes,

and suspended DOE nuclear waste storage fee (effective May 2014)

(3)

Source: Platts Nuclear News, Nuclear Energy Institute and Energy Information Administration (Department of Energy)

2015 EEI Financial Conference

Net nuclear generation data at ownership excluding Salem for all years

CENG excluded in years 2007–2014 but included in 2015 and beyond

2016 and 2018 include Clinton Refueling Only outage of shortened duration

Nuclear Output and Refueling Outages

Fleet Average Refueling Outage Duration (Days)

31%

36%

14%

Nuclear Output

1,208

1,169

1,104

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 is on annual cycles

Actual / Forecast

Target

# of Refueling Outages

2015 Refueling Outage Impact

•

14 planned refueling outages, including 1 at

Salem

•

7 spring refueling outages and 6 fall

refueling outages

•

1 Salem fall refueling outage

2016 Refueling Outage Impact

•

12 planned refueling outages, including 1 at

Salem

•

7 spring refueling outages and 4 fall

refueling outages

•

1 Salem spring refueling outage

2010-2013 Exelon fleet averages exclude Salem and CENG. 2014 Exelon fleet average excludes Salem

125

130

135

140

145

150

155

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

105

2010

2011

2012

2013

2014

Exelon

2015 EEI Financial Conference

Nuclear Fuel Costs

(1)

Projected Exelon Uranium Demand

(2)

Components of Fuel Expense in 2015

2015 –

2020: 100% hedged in volume

2020E

2019E

2018E

2017E

2016E

2015E

Enrichment

32%

Tax/Interest

Conversion

Uranium

46%

Fabrication

16%

Projected Exelon Average

Uranium Cost vs. Mar

Projected

Total

Nuclear

Fuel

Spend

(3)

200

400

600

800

1,000

1,200

2020E

887

2019E

949

2018E

953

2017E

964

2016E

975

2015E

971

Nuclear Fuel Capex

Nuclear Fuel Expense (Amortization)

Over the last year, Exelon has reduced capital requirements for nuclear fuel by ~$265M (2015 to 2019)

(1)

All charts exclude Salem

(2)

Includes 100% of requirements

(3)

CENG included at ownership. Including Salem and 100% of CENG total cash capital expenditures are $1.3B, $1.2B, $1.0B, $0.9B, $0.9B, and $0.9B for 2015 - 2020

2015 EEI Financial Conference

Constellation Energy Nuclear Group (CENG) Operating Service

Agreement Terms

•

Nuclear Operating services agreement

•

Integrated CENG and their 3 plants into Exelon Nuclear with transfer of operating licenses

•

Loan to CENG and distributions to EDF/Exelon Generation

•

CENG $400M special distribution paid to EDF on April 1, 2014

•

Exelon Generation made $400M loan to CENG at 5.25% annual interest rate to fund special distribution to

EDF (As of September 30, 2015, the loan balance, including interest, was $296M)

•

Exelon Generation receives priority payment from CENG’s available cash flows until loan is fully repaid

•

Exelon Generation also entitled to receive aggregate preferred distributions of $400M plus a return of

8.5% per annum from April 1, 2014 (No amounts have been paid on this special distribution)

•

Option for EDF to sell its 49.99% interest in CENG to Exelon Generation

•

Exercisable from January 2016 to June 2022

•

Process and timeline allows for possible negotiated agreement on price

•

If no negotiated agreement on price, price is determined by arbitration process to determine fair market

value

•

Arbitration process could take up to 10 months or longer before binding decision is made on price

•

Price would be adjusted for EDF share of remaining loan balance and special distribution to Exelon

Generation

•

Regulatory approvals could take several months but might run concurrently with arbitration process

•

Exelon has limited rights to defer closing up to 6 months

2015 EEI Financial Conference

Exelon Fossil Generation Fleet Overview

(1) 100%, unless otherwise indicated

(2)

Fossil/Hydro Capacity values shown represent summer ratings as of September 2015. Net Generation Capacity (MW) is stated at proportionate ownership share

(3)

Includes Perryman 2 (51MW), which will retire on in Q1 2016. Includes Perryman 6 (110MW) that went COD in June 2015

(4)

Includes Riverside 4 (74MW), which is scheduled for retirement in May 2016

Station

Location

Number

Units

Primary Fuel

Type

Percent

Owned

(1)

Net Generation

Capacity (MW)

(2)

Notch Cliff

Baltimore, MD

Gas

118

Pennsbury

Morrisville, PA

Landfill Gas

Perryman

(3)

Belcamp, MD

Oil/Gas

463

Philadelphia Road

Baltimore, MD

Oil

Richmond

Philadelphia, PA

Oil

Riverside

(4)

Baltimore, MD

Oil/Gas

113

Salem

Lower Alloways

Creek Twp, NJ

Oil

42.59

Schuylkill

Philadelphia, PA

Oil

Southwark

Philadelphia, PA

Oil

Westport

Baltimore, MD

Gas

116

Southeast Chicago

Chicago, IL

Gas

296

Framingham

Framingham, MA

Oil

Medway

West Medway, MA

Oil/Gas

117

Mystic 7

Charlestown, MA

Oil/Gas

575

Mystic 8, 9

Charlestown, MA

Gas

1418

Mystic Jet

Charlestown, MA

Oil

New Boston

South Boston, MA

Oil

Wyman

Yarmouth, ME

Oil

5.9

Grand Prairie

Alberta, Canada

Gas

Hillabee

Alexander City, AL

Gas

722

Sunnyside

Sunnyside, UT

Waste Coal

Station

Location

Number

Units

Primary Fuel

Type

Percent

Owned

(1)

Net Generation

Capacity (MW)

(2)

Colorado Bend

Wharton, TX

Gas

498

Handley 3

Fort Worth, TX

Gas

395

Handley 4, 5

Fort Worth, TX

Gas

870

LaPorte

Laporte, TX

Gas

152

Mountain Creek 6, 7

Dallas, TX

Gas

240

Mountain Creek 8

Dallas, TX

Gas

565

Wolf Hollow 1, 2, 3

Granbury, TX

Gas

704

Chester

Chester, PA

Oil

Conowingo

Darlington, MD

Hydro

572

Croydon

West Bristol, PA

Oil

391

Delaware

Philadelphia, PA

Oil

Eddystone

Eddystone, PA

Oil

Eddystone

3, 4

Eddystone, PA

Oil/Gas

760

Fairless Hills

Fairless Hills, PA

Landfill Gas

Falls

Morrisville, PA

Oil

Gould Street

Baltimore, MD

Gas

Handsome Lake

Kennerdell, PA

Gas

268

Moser

Lower

PottsgroveTwp., PA

Oil

Muddy Run

Drumore, PA

Hydro

1070

2015 EEI Financial Conference

Summer Texas Heat Brings Return of Volatility to ERCOT

Demand is Growing

•

Summer 2015 was hot; record load pushed summer

2015 spot power prices up and led summer forwards

higher

•

Average demand in ERCOT has risen 2-3% in 2015 from

2014

•

Reserve margins reserve were as much as 10% lower

than projected, falling below 4 GW in August

Exelon captured ~$20M of value from this summer’s volatility and our new CCGTs will

be well positioned to replicate this success

Generation assets will be valuable going forward

•

Wind generation is forecasted to grow from 13 GW

today to nearly 20 GW by 2020, which will increase

volatility of the ERCOT dispatch stack

•

New

gas

generation

development

has

slowed

–

with

600MW of peakers

in 2016 and Exelon CCGTs in

2017 the only visible gas additions through 2018

•

The Public Utilities Commission of Texas has

requested that ERCOT examine the Operating Reserve

Demand Curve

ERCOT Weather: July-September

ERCOT Scarcity Indicators: July-September

2015 EEI Financial Conference

Texas CCGTs: Unique Opportunity to Grow in ERCOT

Key Facts

Sites

Wharton County and Granbury, TX

Total Capacity

~2,200MW

Construction Cost

$1,475M (~$700/kW); $700M remaining

Heat Rate

~6,500 mmBtu/MWh

EPC / OEMs

Zachry

/ GE and Alstom

Cooling System

Air Cooled

Commercial Operation

By Summer 2017

Expected Economics

ROE

12%

ERCOT Dispatch

Key Messages

•

Two of the cleanest, most efficient Combined Cycle Gas Turbines (CCGT) in the nation

•

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

•

Plants use air cooling which mitigates water constraint issues

•

Ramp rate of 100 MW/minute can respond quickly to depressed wind or unexpected outages (market ramp

rate ~50 MW/minute)

•

Capacity factor will average 75-85%

•

Demand continues to grow at more than 1% per year, which results in the need for roughly 700MW of

incremental capacity every year and potential for real-time prices to go to $9,000/MWh

•

New units should see sustainably high spark spreads and returns, especially if natural gas prices recover

•

Potential for coal units in the state to add costly controls or shutdown could further boost returns as the

Mercury & Air Toxics (MATS) and Regional Haze rules take effect

Efficient

Cost Effective

Environmental

Versatile

Constructive

Market

100

50,000

100,000

Capacity at peak (MW)

Coal

Gas

Uranium

Renewables

Exelon New Build

2015 EEI Financial Conference

Exelon Renewable Generation Fleet Overview

Station

Location

Number

of Units

Primary

Fuel Type

Percent

Owned

(1)

Net Generation

Capacity (MW)

(2)

AgriWind

Bureau Co., IL

Wind

Beebe 1A & 1B

Gratiot, MI

Wind

131

Blue

Breezes/Moore

Blue Earth, MN

Wind

Cisco

Jackson Co., MN

Wind

Cowell

Pipestone Co., MN

Wind

CP Windfarm

Faribault Co., MN

Wind

Ewington

Jackson Co.,

Wind

EXC City

Solar

Cook Co., IL

Solar

Harvest I & II

Huron Co.,

Wind

112

Marshall

Lyon Co., MN

Wind

Michigan

Wind I

Bingham

Township,

Wind

Michigan Wind II

Minden City, MI

Wind

Norgaard

Lincoln Co.,

Wind

Wolf

Nobles Co., MN

Wind

Bluegrass Ridge

Gentry Co., MO

Wind

Conception

Nodaway Co., MO

Wind

Cow Branch

Atchinson

Co., MO

Wind

Greensburg

Kiowa Co., KS

Wind

Loess Hills

Atchinson

Co., MO

Wind

Shooting Star

Kiowa Co., KS

Wind

104

Station

Location

Number

of Units

Primary

Fuel Type

Percent

Owned

(1)

Net Generation

Capacity (MW)

(2)

EXC Wind 1,2,3,4

Hansford Co., TX

Wind

110

EXC

Wind 5,6

Sherman Co., TX

Wind

EXC Wind 7,8,9,10,11

Moore Co., TX

Wind

High Plains

Moore Co., TX

Wind

99.5

Whitetail

Webb,

Wind

Conowingo

Hartfort

Co., MD

Hydroelectric

572

Criterion

Oakland, MD

Wind

Fairless

Falls Twp, PA

Landfill Gas

Fourmile

Garrett Co., MD

Wind

Muddy Run

Lancaster Co., PA

Hydro

1,070

Pennsbury

Falls Twp, PA

Landfill Gas

Antelope Valley

Solar Ranch

LA Country., CA

Solar

242

Cassia

Twin Falls Co., ID

Wind

Echo I

Umatilla Co., OR

Wind

Echo II

Morrow

Co., OR

Wind

Echo III

Morrow Co., OR

Wind

High Mesa

Twin Fall Co., ID

Wind

Mountain Home

Elsmore

Co., ID

Wind

Threemile

Canyon

Morrow Co., OR

Wind

Tuana

Springs

Twin Fall Co., ID

Wind

Wildcat

Lea, NM

Wind

(1) 100%, unless otherwise indicated

(2)

Fossil/Hydro Capacity values shown represent summer ratings as of September 2015. Net Generation Capacity (MW) is stated at proportionate ownership share

(3)

Constellation Solar is an operation that constructs, owns, and operates solar facilities at various customer locations.

2015 EEI Financial Conference

Exelon Generation Disclosures

September 30, 2015

2015 EEI Financial Conference

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

Strategic Policy Alignment

•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

Three-Year Ratable Hedging

•Ensure stability in near-term cash

flows and earnings

•Disciplined approach to hedging

•Tenor aligns with customer

preferences and market liquidity

•Multiple channels to market that

allow us to maximize margins

•Large open position in outer years

to benefit from price upside

Bull / Bear Program

•Ability to exercise fundamental

market views to create value within

the ratable framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat

rate positions, options, etc.)

•Delivery locations, regional and

zonal spread relationships

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 &

Operating

Expenditure

Capital &

Operating

Expenditure

Dividend

Capital

Structure

Capital

Structure

2015 EEI Financial Conference

Margins move from new business to MtM

of hedges over

the course of the year as sales are executed

(5)

Components of Gross Margin Categories

Open Gross

Margin

•Generation Gross

Margin at current

market prices,

including capacity

and ancillary

revenues, nuclear

fuel amortization

and fossils fuels

expense

•Exploration and

Production

(4)

•Power Purchase

Agreement (PPA)

Costs and

Revenues

•Provided at a

consolidated level

for all regions

(includes hedged

gross margin for

South, West and

Canada

(1)

)

MtM

Hedges

(2)

•Mark-to-Market

(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

Effective Realized

Energy Price

(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

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

“Non Power”

New Business

•Retail, Wholesale

planned gas sales

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

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

2015 EEI Financial Conference

ExGen Disclosures

(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, operating services agreement with Fort Calhoun 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, 2015 market conditions

Gross Margin Category ($M)

(1)

2015

2016

2017

2018

Open Gross Margin

(including South, West & Canada hedged

GM)

(3)

$5,150

$5,650

$5,800

$6,100

Mark-to-Market of Hedges

(3,4)

$2,200

$1,200

$750

$250

Power New Business / To Go

$50

$500

$800

$1,000

Non-Power Margins Executed

$400

$200

$100

$50

Non-Power New Business / To Go

$50

$250

$350

$450

Total

Gross

Margin

(2)

$7,850

$7,800

$7,850

Reference Prices

(5)

2015

2016

2017

2018

Henry Hub Natural Gas ($/MMbtu)

$2.75

$2.80

$2.99

$3.05

Midwest: NiHub ATC prices ($/MWh)

$28.80

$29.58

$28.95

$28.57

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

$37.05

$36.82

$35.36

$33.99

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$3.12

$4.62

$4.47

$3.83

New York: NY Zone A ($/MWh)

$33.55

$33.52

$33.22

$32.70

New England: Mass Hub ATC Spark Spread

($/MWh)

ALQN Gas, 7.5HR, $0.50 VOM

$5.57

$9.33

$10.73

$11.84

2015 EEI Financial Conference

ExGen

Disclosures

(1)

Expected

generation

the

volume

energy

that

best

represents

our

commodity

position

energy

markets

from

owned

contracted

for

capacity

based

upon

simulated

dispatch

model

that

makes

assumptions

regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 12 refueling outages in 2016, 15 in 2017, and 14 in

2018

Exelon-operated

nuclear

plants,

and

Salem.

Expected

generation

assumes

capacity

factors

94.1%,

93.3%

and

93.7%

2016,

2017

and

2018

respectively

Exelon-operated

nuclear

plants,

ownership. These estimates of expected generation in 2016, 2017 and 2018 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

expected

generation

hedged

the

amount

equivalent

sales

divided

expected

generation.

Includes

all

hedging

products,

such

wholesale

and

retail

sales

power,

options

and

swaps

(4)

Effective

realized

energy

price

representative

all-in

hedged

price,

per

MWh

basis,

which

expected

generation

has

been

hedged.

developed

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.

can

compared

with

the

reference

prices

used

calculate

open

gross

margin

order

determine

the

mark-to-market

value

Exelon

Generation's energy hedges

(5)

Spark spreads shown for ERCOT and New England

Generation and Hedges

2015

2016

2017

2018

Exp. Gen (GWh)

(1)

186,700

199,400

205,300

206,200

Midwest

96,600

97,300

95,700

96,200

Mid-Atlantic

(2)

61,700

63,100

61,200

60,500

ERCOT

11,600

17,200

26,400

31,100

New York

(2)

9,300

9,200

9,100

New England

7,500

12,500

12,800

9,300

% of Expected Generation Hedged

(3)

97%-100%

81%-84%

51%-54%

20%-23%

Midwest

97%-100%

79%-82%

45%-48%

15%-18%

Mid-Atlantic

(2)

95%-98%

84%-87%

57%-60%

26%-29%

ERCOT

99%-102%

86%-89%

65%-68%

25%-28%

New York

(2)

94%-97%

72%-75%

46%-49%

30%-33%

New England

115%-118%

81%-84%

37%-40%

11%-14%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$36.00

$34.50

Mid-Atlantic

(2)

$51.50

$47.00

$45.50

$45.00

ERCOT

(5)

$23.50

$11.00

$7.50

$2.50

New York

(2)

$47.50

$45.50

$42.00

$35.00

New England

(5)

$42.00

$20.00

$18.00

$11.00

2015 EEI Financial Conference

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges)

(1)

2015

2016

2017

2018

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$110

$445

$690

- $1/Mmbtu

$20

$(115)

$(430)

$(680)

NiHub ATC Energy Price

+ $5/MWh

$100

$275

$410

- $5/MWh

$(95)

$(275)

$(410)

PJM-W ATC Energy Price

+ $5/MWh

$45

$130

$235

- $5/MWh

$(40)

$(125)

$(230)

NYPP Zone A ATC Energy Price

+ $5/MWh

$10

$25

$30

- $5/MWh

$(10)

$(25)

$(30)

Nuclear Capacity Factor

+/- 1%

+/- $10

+/- $40

(1)

Based on September 30, 2015 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

2015 EEI Financial Conference

ExGen Hedged Gross Margin Upside/Risk

5,000

5,500

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

11,000

2015

2016

2017

2018

$10,200

$6,150

$7,900

$7,800

$8,250

$7,350

$6,900

$9,050

(1)

Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is

sold into the spot market; Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and

potential modeling changes; These ranges of approximate gross margin in 2016, 2017 and 2018 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, 2015

(2)

Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions

(3)

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, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses.

Excludes EDF’s equity ownership share of the CENG Joint Venture

2015 EEI Financial Conference

Illustrative Example of Modeling Exelon Generation

2016 Gross Margin

(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 operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses

Row

Item

Midwest

Mid-Atlantic

ERCOT

New York

New England

South, West

& Canada

(A)

Start with fleet-wide open gross margin

(B)

Expected Generation (TWh)

97.3

63.1

17.2

9.3

12.5

(C)

Hedge % (assuming mid-point of range)

80.5%

85.5%

87.5%

73.5%

82.5%

(D=B*C)

Hedged Volume (TWh)

78.3

54.0

15.1

6.8

10.3

(E)

Effective Realized Energy Price ($/MWh)

$34.50

$47.00

$11.00

$45.50

$20.00

(F)

Reference Price ($/MWh)

$29.58

$36.82

$4.62

$33.52

$9.33

(G=E-F)

Difference ($/MWh)

$4.92

$10.18

$6.38

$11.98

$10.67

(H=D*G)

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

(1)

$385

$550

$95

$80

$110

(I=A+H)

Hedged Gross Margin ($ million)

(J)

Power New Business / To Go ($ million)

(K)

Non-Power Margins Executed ($ million)

(L)

Non-Power New Business / To Go ($ million)

(N=I+J+K+L)

Total Gross Margin

(2)

$200

$250

$7,800 million

$5.65 billion

$6,850

$500

Commonwealth Edison 8-KCautionary Statements Regarding Forward-Looking Information