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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 9, 2015

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)

10 South Dearborn Street

P.O. Box 805379

Chicago, Illinois 60680-5379

(800) 483-3220

   23-2990190

333-85496

  

EXELON GENERATION COMPANY, LLC

(a Pennsylvania limited liability company)

300 Exelon Way

Kennett Square, Pennsylvania 19348-2473

(610) 765-5959

   23-3064219

1-1839

  

COMMONWEALTH EDISON COMPANY

(an Illinois corporation)

440 South LaSalle Street

Chicago, Illinois 60605-1028

(312) 394-4321

   36-0938600

000-16844

  

PECO ENERGY COMPANY

(a Pennsylvania corporation)

P.O. Box 8699

2301 Market Street

Philadelphia, Pennsylvania 19101-8699

(215) 841-4000

   23-0970240

1-1910

  

BALTIMORE GAS AND ELECTRIC COMPANY

(a Maryland corporation)

2 Center Plaza

110 West Fayette Street

Baltimore, Maryland 21201

(410) 234-5000

   52-0280210

 

 

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 8-11, 2015, 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 Current Report 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 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 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 Current Report. 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 Current Report.

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 9, 2015

EXHIBIT INDEX

 

Exhibit
No.

   

Description

99.1    Presentation slides and handouts
EX-99.1
Edison Electric Institute
Financial Conference
November 8–11, 2015
Exhibit 99.1

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.

2
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.
We
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
–
1
st
Quartile SAIFI performance
–
1
st
Quartile
CAIDI
performance
at
ComEd
and
PECO,
2
nd
Quartile
at
BGE
–
1
st
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
•
#1
Provider
of
retail
electricity,
serving
34
TWhs
more
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

3
2015 EEI Financial Conference
Looking Ahead
•
The Exelon Strategy
•
Addressing Key Immediate Issues
1)
Capital Allocation
2)
Pepco Holdings Acquisition
3)
Extending Clinton One Year
4)
Cost Management Initiative
•
The Foundation for Exelon’s Growth

The Exelon Strategy

5
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

6
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

7
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
1)
Capital Allocation
2)
Pepco Holdings Acquisition
3)
Extending Clinton One Year
4)
Cost Management Initiative

Capital Allocation

10
2015 EEI Financial Conference
Delivering Value to Shareholders Through a Principled Capital
Allocation Policy
•
Every
capital
decision
is
made
to
maximize
value
to
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

11
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)

12
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

14
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

15
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)
0%
2%
4%
6%
8%
10%
0
50
100
150
200
250
300
1.2
1.0
0.9
0.8
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

17
2015 EEI Financial Conference
We Will Continue to Operate Clinton for Another Year
What has changed in 2015?
•
Recent
upward
movement
in
MISO
capacity
prices
--
$150/MWd
in
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

18
2015 EEI Financial Conference
More Progress Necessary for Clinton to Operate Beyond 2017
1)
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
2)
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

20
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
to
begin
in
2016
and
will
be
fully
realized
in
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

23
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
.

24
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
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

25
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
$0
$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.

26
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%
20%
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
A2
Aa3
A3
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-
A-
A-
BBB
“ExGen
generates
a
significant
portion
of
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-
A
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

27
2015 EEI Financial Conference
Exelon-PHI Debt Maturity Profile
(1)
2023
800
2021
2022
1,425
900
2020
3,650
2019
950
25
2018
1,600
2017
2,925
25
75
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

28
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
$0.03
-50 basis points
($0.02)
($0.03)
($0.03)
Share Count
(3)
(millions)
893
927
947
965

29
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
$1,350
Model using midpoint of Net
Income
guidance
from slide
25
Exelon
Generation Net Income
($M)
$X,XXX
$X,XXX
$X,XXX
Model using Gross Margin disclosure
from slide 45
Corporate Net Income
($M)
($25)
($25)
($25)
Model using interest
expense
information in note on slide 25
Exelon Standalone Net Income
($M)
$X,XXX
$X,XXX
$X,XXX
Standalone Share Count
(millions)
877
881
886
Approximate share
count when PHI
equity issuance is excluded
Standalone EPS
$X.XX
$X.XX
$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
$X.XX
$X.XX
Take Exelon
standalone Net Income and
add PHI accretion
Pro
Forma
Share Count
(millions)
927
947
965
From slide 28

30
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%

31
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
of
acquisition
of
Integrys
in
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

32
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

34
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
No
Gas
Operations
No
Gas
Operations
3rd Party Damages per 1000 Gas
Locates
Overall Rank
Electric Utility Panel of 24
Utilities
23
rd
2
nd
2
nd
2
nd
2
nd
2
nd
Operational Excellence Drives Value for Customers, Communities,
and Shareholders
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

35
2015 EEI Financial Conference
2018E
950
2017E
875
2016E
825
2015E
700
2018E
725
75
2017E
725
75
2016E
700
2015E
600
75
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
175
175
175
225
225
250
575
625
375
300
100
175
225
225
200
1,450
1,475
1,625
1,475
350
400
475
475
300
350
400
475
125
200
325
400
50
25
50
25
25
25

36
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
0.9
1.0
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

37
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%
0.1%
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.

38
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
to
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
in
rates
during
2014
to
2014
Actual
Costs
Incurred.
Revenue
requirement
for
2014
is
based
on
docket
13-0318
(2012
actual
costs
and
2013
projected
net
plant
additions)
approved
in
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
of
3.34%
+
580
basis
point
risk
premium
–
5
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
to
set
the
rates
that
will
take
effect
in
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)
in
effect
to
the
actual
costs
for
that
year.
The
annual
reconciliation
impacts
cash
flow
in
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 

39
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 

40
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)
o
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
o
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%.
o
Approved on 10/22/15
•
PECO
also
proposed
the
concept
of
constructing
one
or
more
pilot
microgrid
projects
as
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

41
2015 EEI Financial Conference
PHI Capital Plan and Rate Base
675
700
725
700
350
350
350
375
275
325
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)

42
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

44
2015 EEI Financial Conference
15
11
6
12
17
14
17
18
48
75
25
97
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
in
the
energy
and
ancillary
markets.
During
the
polar
vortex,
we
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
of
our
dispatchable
fleet
through
load
sales.
This
year
alone,
we
have
made
~$250
million
as
result
of
lower
cost
to
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
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 9/30/2015
(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
14
New England
Canada
South/West/
26
New York
43
Mid-Atlantic
30
ERCOT
Intermediate
Baseload
Peaking
Renewables
Expected Generation
Expected Load
Generation Capacity:
8
14
8
9
20
13
13
17
64
63
38
97
38
95
18
10
111
25
2016 Generation Load Match (TWh)
(1,2)
Midwest
New England
Canada
South/West/
New York
Mid-Atlantic
ERCOT

45
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 $1B in gross margin over the 2016 to 2018
period
•
Timing of hedge decisions creates value
•
Positioning
portfolio
to
reflect
our
fundamental
views
–
currently
carrying
a
larger
open
position in 2017 and 2018
•
Intra-year hedging flexibility to take advantage of volatility
•
Using cross-commodity spreads in NiHub:  7-10% of the portfolio in 2017 is in
cross-commodity hedges and 3-6% in 2018
Gross Margin Category ($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
$7,800
$7,850

46
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

47
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
0
20
40
60
80
100
120
140
160
180
200
220
0
20
40
60
80
100
120
140
160
180
200
220

48
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-$3/MWh
•
Power
exposure
in
NiHub
above
purely
ratable:
•
17-20% behind ratable in 2017
•
13-15% behind ratable
in 2018
•
The increased reliance on natural gas as coal plants retire
has impacted prices
•
Our PJM forecast includes 20+GW of new CCGTs, full
compliance with state renewables requirements and
essentially flat load growth, in addition to coal retirements
0
5
10
15
20
25
30
35
2012-2014
2015
2016
PJM/MISO Coal Retirements
PJM & MISO Annual Coal Retirements
PJM & MISO Cumulative Coal Retirements
26
27
28
29
30
31
32
2017
2018
Nihub ATC Prices ($/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

49
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
$0
2018
2017
2016
2015
Exelon Fleet Weighted Price ($/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)
CP
Price
CP
Price
CP
Price
Base
Price
ComEd
Fossil/Other
-
$134.00
-
$151.50
-
$215.00
25
$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
25
$200.21
EMAAC
Fossil/Other
25
$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
75
$134.00
150
$151.50
300
$164.77
425
$149.98
Nuclear
-
$134.00
-
$151.50
-
$164.77
-
$149.98
Total
75
$134.00
150
$151.50
300
$164.77
425
$149.98
Rest of MAAC/RTO
Fossil/Other
-
$134.00
-
$151.50
265
$164.77
50
$149.98
Nuclear
775
$134.00
800
$151.50
-
$164.77
-
$149.98
Total
775
$134.00
800
$151.50
265
$164.77
50
$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

50
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 $/MWd
2015/2016
2016/2017
2017/2018
2018/2019
ISO-NE
(1)
NEMA
Capacity
(3)
(MW)
2,100
2,100
2,100
2,100
Price ($/MWd)
$104
$222
$500
$318
SEMA
Capacity
(3)
(MW)
35
35
35
230
Price ($/MWd)
$104
$105
$234
$557
NYISO
(2)
Capacity
(3)
(MW)
1,100
1,100
1,100
1,100
MISO
Zone 4
Capacity
(3)
(MW)
1,100
1,100
1,100
1,100
Price ($/MWd)
(4)
$150

51
2015 EEI Financial Conference
Natural Gas Marketing Platform
Active Natural Gas Markets
Supply
~4-6
Bcf
per
day
delivered
in
competitive
markets
growing
to
6-8
Bcf
by
2018
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 120 LDCs
Gas Generation
Gas Toll
Owned gas storage
contracts
Major office locations

52
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
of
CO2
emissions
allowance
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
or
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

53
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

54
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
Exelon
20
25
30
35
40
45
50
55
60
65
70
75
80
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) 

55
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%
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
7
8
9
10
11
12
13
14
125
130
135
140
145
150
155
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
15
25
35
45
55
65
75
85
95
105
2010
2011
2012
2013
2014
Exelon

56
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
2
1
0
11
10
9
8
7
6
5
4
3
2020E
2019E
2018E
2017E
2016E
2015E
Enrichment
32%
Tax/Interest
2%
Conversion
4%
Uranium
46%
Fabrication
16%
Projected Exelon Average
Uranium Cost vs. Mar
Projected
Total
Nuclear
Fuel
Spend
(3)
0
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  

57
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

58
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
of
Units
Primary Fuel
Type
Percent
Owned
(1)
Net Generation
Capacity (MW)
(2)
Notch Cliff
Baltimore, MD
8
Gas
118
Pennsbury
Morrisville, PA
2
Landfill Gas
6
Perryman
(3)
Belcamp, MD
6
Oil/Gas
463
Philadelphia Road
Baltimore, MD
4
Oil
61
Richmond
Philadelphia, PA
2
Oil
98
Riverside
(4)
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
116
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
722
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
6
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
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
Muddy Run
Drumore, PA
8
Hydro
1070

59
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

60
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
0
10
20
30
40
50
60
70
80
90
100
0
50,000
100,000
Capacity at peak (MW)
Coal
Gas
Uranium
Renewables
Exelon New Build

61
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
4
Wind
99
8
Beebe 1A & 1B
Gratiot, MI
55
Wind
131
Blue
Breezes/Moore
Blue Earth, MN
2
Wind
3
Cisco
Jackson Co., MN
4
Wind
99
8
Cowell
Pipestone Co., MN
1
Wind
99
2
CP Windfarm
Faribault Co., MN
2
Wind
4
Ewington
Jackson Co.,
MN
10
Wind
99
21
EXC City
Solar
Cook Co., IL
1
Solar
8
Harvest I & II
Huron Co.,
MI
65
Wind
112
Marshall
Lyon Co., MN
9
Wind
99
19
Michigan
Wind I
Bingham
Township,
MI
46
Wind
69
Michigan Wind II
Minden City, MI
50
Wind
90
Norgaard
Lincoln Co.,
MN
7
Wind
99
9
Wolf
Nobles Co., MN
5
Wind
99
6
Bluegrass Ridge
Gentry Co., MO
27
Wind
57
Conception
Nodaway Co., MO
24
Wind
50
Cow Branch
Atchinson
Co., MO
24
Wind
50
Greensburg
Kiowa Co., KS
10
Wind
13
Loess Hills
Atchinson
Co., MO
4
Wind
5
Shooting Star
Kiowa Co., KS
65
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
62
Wind
110
EXC
Wind 5,6
Sherman Co., TX
16
Wind
20
EXC Wind 7,8,9,10,11
Moore Co., TX
40
Wind
50
High Plains
Moore Co., TX
8
Wind
99.5
10
Whitetail
Webb,
TX
57
Wind
91
Conowingo
Hartfort
Co., MD
11
Hydroelectric
572
Criterion
Oakland, MD
28
Wind
70
Fairless
Falls Twp, PA
2
Landfill Gas
60
Fourmile
Garrett Co., MD
16
Wind
40
Muddy Run
Lancaster Co., PA
8
Hydro
1,070
Pennsbury
Falls  Twp, PA
2
Landfill Gas
6
Antelope Valley
Solar Ranch
LA Country., CA
1
Solar
242
Cassia
Twin Falls Co., ID
14
Wind
29
Echo I
Umatilla Co., OR
21
Wind
99
35
Echo II
Morrow
Co., OR
10
Wind
20
Echo III
Morrow Co., OR
6
Wind
99
10
High Mesa
Twin Fall Co., ID
19
Wind
40
Mountain Home
Elsmore
Co., ID
20
Wind
42
Threemile
Canyon
Morrow Co., OR
6
Wind
10
Tuana
Springs
Twin Fall Co., ID
8
Wind
17
Wildcat
Lea, NM
13
Wind
27
(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.

62
2015 EEI Financial Conference
Exelon Generation Disclosures
September 30, 2015

63
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
Credit Rating
Capital &
Operating
Expenditure
Capital &
Operating
Expenditure
Dividend
Dividend
Capital
Structure
Capital
Structure

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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
of
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

65
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
$7,800
$7,850
Reference Prices
(5)
2015
2016
2017
2018
Henry Hub Natural Gas ($/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

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2015 EEI Financial Conference
ExGen
Disclosures
(1)
Expected
generation
is
the
volume
of
energy
that
best
represents
our
commodity
position
in
energy
markets
from
owned
or
contracted
for
capacity
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 12 refueling outages in 2016, 15 in 2017, and 14 in
2018
at
Exelon-operated
nuclear
plants,
and
Salem.
Expected
generation
assumes
capacity
factors
of
94.1%,
93.3%
and
93.7%
in
2016,
2017
and
2018
respectively
at
Exelon-operated
nuclear
plants,
at
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
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
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
9,300
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
$34.50
$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

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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
+/- $40
+/- $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

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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

69
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