EXELON CORP - FORM 8-K - EX-99.2 - EARNINGS CONFERENCE CALL PRESENTATION SLIDES - October 30, 2015

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Earnings Conference Call
3
rd
Quarter 2015
October 30, 2015
Exhibit 99.2

2
Q3 2015  Earnings Release Slides
Cautionary Statements Regarding Forward-Looking Information
This presentation contains certain forward-looking statements within the meaning of
the Private Securities Litigation Reform Act of 1995, that are subject to risks and
uncertainties. The factors that could cause actual results to differ materially from the
forward-looking statements made by Exelon Corporation, Commonwealth Edison
Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon
Generation Company, LLC (Registrants) include those factors discussed herein, as well
as the items discussed in (1) Exelon’s 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 (to be filed on October 30, 2015) 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.

Delivering Value through Strong Financial and Operational
Performance
Exelon
Utilities
Exelon
Generation
Exelon:
On track for best year of earnings since 2012
Q3 earnings of $0.83 per share, 6% higher than the same quarter last year
Raising full-year guidance to $2.40 to $2.60 per share despite delay in closing Pepco
3
Q3 2015
Earnings Release
Slides
•
Successful Generation to Load matching
strategy is meaningfully contributing to
earnings
•
#1 Provider of retail electricity, serving 34
TWhs
more than our nearest competitor
•
Serving 195 TWhs
of wholesale and retail
load
•
Top 10 marketer of natural gas
•
Delivering on average 4-6 Bcfs
of gas daily
•
World Class Operator
•
Q3 Nuclear Capacity Factor: 95.5%
•
Q3 Power dispatch match: 99.0%
•
Q3 Renewables energy capture: 94.8%
•
On track to invest $3.7 billion this year to
make the grid smarter, more reliable, and
more resilient
•
Exceeding $1B in net income this year
•
Constructive regulatory environments
•
PECO rate case settlement
•
ComEd formula rate
•
Recent BGE unanimous rate case
settlement
•
An industry leader of 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

Aligning our Hedging Strategy with Our Fundamental Views
•
Midwest (Nihub) power continues to discount the impact of coal
retirements and the potential for even modest load growth in
PJM and the surrounding regions over the next five years
•
Prices could get an additional boost from $0.25-$0.75 higher
gas prices, primarily driven by increased export and industrial
demand
Power prices remain undervalued from 2017 onward, even absent a recovery in gas; our portfolio
management actions reflect this view
NiHub
Market versus Fundamental View
($/MWh)
•
We continue to align our hedging strategies with our
fundamental views by leaving portfolio exposure to power price
upside
•
We continue to leave a significant amount of our portfolio open
to moves in the power market, when considering our behind
ratable and cross commodity strategies
•
Generation ~46-49% open in 2017
•
~6-9%
behind
ratable
--
even
further
behind
in
the
Midwest
2017: Maintaining a More Open Position Across
Entire Portfolio
$31
$27
$29
$30
$26
$28
$32
2016
2017
NiHub Forecast 9/30
NiHub Market 9/30
20%
25%
30%
35%
40%
45%
50%
55%
60%
Q4-14
Q1-15
Q2
-
15
Q3-15
2017-Actual
2017-Ratable
2017-Actual (excl. NG hedges)
4
Q3 2015
Earnings Release
Slides

5
Q3 2015  Earnings Release Slides
Exelon Generation: Gross Margin Update
1)
Gross margin categories rounded to nearest $50M
2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and
fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon
Nuclear Partners, operating services agreement with Fort Calhoun and variable interest
entities. Total Gross Margin is also net of direct cost of sales for certain Constellation
businesses.
See
Slide
29
for
a
Non-GAAP
to
GAAP
reconciliation
of
Total
Gross
Margin.
Gross Margin Category ($M)
(1)
2015
2016
2017
2015
2016
2017
Open Gross Margin
(3)
(including South, West, Canada hedged gross
margin)
$5,150
$5,650
$5,800
$(100)
$(50)
$50
Mark-to-Market of Hedges
(3,4)
$2,200
$1,200
$750
$350
$300
$250
Power New Business / To Go
$50
$500
$800
$(50)
$50
$(100)
Non-Power Margins Executed
$400
$200
$100
$50
-
-
Non-Power New Business / To Go
$50
$250
$350
$(50)
-
-
Total Gross Margin
(2)
$7,850
$7,800
$7,800
$200
$300
$200
September 30, 2015
Change from June 30, 2015
3)
Excludes EDF’s equity ownership share of the CENG Joint Venture
4)
Mark-to-Market of Hedges assumes mid-point of hedge percentages
Recent Developments
•
Capacity Performance auction results reflected in 2016 and 2017 gross margin updates
•
Load serving business had a strong quarter driven by our generation to load matching
strategy
•
Behind ratable reflecting the fundamental upside we see in power prices in 2016 and
2017

6
Q3 2015  Earnings Release Slides
Key Financial Messages
Q3 2015 Adjusted Operating EPS
(1,2)
2015 Full-Year Guidance 
(3.4)
$0.45 -
$0.55
$0.35 -
$0.45
$0.25 -
$0.35
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
ExGen
ComEd
PECO
BGE
2015 Revised
Guidance
$1.35 -
$1.45
HoldCo
~($0.10)
$2.40 -
$2.60
(1)
$0.17
$0.10
PECO
Q3 2015
$0.83
($0.04)
$0.55
HoldCo
BGE
ExGen
ComEd
$0.06
Raising
full-year
guidance
range
to
$2.40
-
$2.60/share
(3,4)
(1)
Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS
(2)
Amounts may not add due to rounding
(3)
ComEd ROE based on 30 Year average Treasury yield of 2.82% as of 9/30/15
(4)
2015 earnings guidance based on expected average outstanding shares of ~893M.  Refer to Appendix for a reconciliation of adjusted non-GAAP operating EPS guidance to
GAAP EPS.

7
Q3 2015  Earnings Release Slides
2015 Projected Sources and Uses of Cash
(1)
All amounts rounded to the nearest
$25M. Figures may not add due to
rounding.
(2)
Excludes counterparty collateral activity.
(3)
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 at
ownership.
(4)
Other Financing primarily includes
expected changes in short-term debt
and tax-exempt bond issuance at ExGen.
(5)
Dividends are subject to declaration by
the Board of Directors.
(6)
Includes cash flow activity from Holding
Company, eliminations, and other
corporate entities.
Consistent and reliable free cash flows
Enable growth & value creation
Supported by a strong balance sheet
Strong balance sheet enables flexibility to
raise and deploy capital for growth
Completed financing for PHI Acquisition
including:
$4.2B Long-term debt issuance
$1.9B Equity issuance
HoldCo: Retired $0.8B LTD note at
maturity in June
Operational excellence and financial
discipline drives free cash flow reliability
Generating ~$4.3B of free cash flow in
2015,
including
$0.9B
at
ExGen
and
$3.5B at the Utilities
Creating value for customers, communities
and shareholders
Investing $4.8B, with $3.7B at the
Utilities and $1.1B at ExGen
($ in millions)
(1)
BGE
ComEd
PECO
Total
Utilities
ExGen
Corp
(6)
Exelon
2015E
Cash
Balance
Beginning Cash Balance
(2)
3,575
Adjusted Cash Flow from Operations
(3)
650
2,175
700
3,550
3,325
(50)
6,800
Base CapEx and Nuclear Fuel
0
0
0
0
(2,375)
(50)
(2,450)
Free Cash Flow
650
2,175
700
3,550
925
(125)
4,350
Debt Issuances
0
850
350
1,200
750
4,200
6,150
Debt Retirements
(75)
(250)
0
(325)
(550)
(800)
(1,675)
Project Financing
n/a
n/a
n/a
n/a
0
n/a
0
Equity Issuance
0
0
0
0
0
1,875
1,875
Contribution from Parent
0
200
0
200
0
(200)
0
Other Financing
(4)
225
(275)
25
(25)
1,400
(50)
1,300
Financing
150
525
375
1,050
1,600
5,000
7,650
Total Free Cash Flow and Financing Growth
800
2,700
1,075
4,600
2,525
4,875
12,000
Utility Investment
(700)
(2,425)
(600)
(3,700)
0
0
(3,700)
ExGen Growth
0
0
0
0
(1,100)
0
(1,100)
Dividend
(5)
(1,100)
(1,100)
Other CapEx and Dividend
(700)
(2,425)
(600)
(3,700)
(1,100)
(1,100)
(5,925)
Total Cash Flow, excl. Collateral
125
300
475
900
1,425
3,775
6,075
Ending Cash Balance
(2)
9,650

8
Q3 2015  Earnings Release Slides
Exelon Generation Disclosures
September 30, 2015

Portfolio Management Strategy
Protect Balance Sheet
Ensure Earnings Stability
Create Value
Exercising Market Views
Purely ratable
Actual hedge %
Market views on timing, product
allocation, and regional spreads
reflected in actual hedge %
High End of Profit
Low End of Profit
% Hedged
Open Generation
with LT Contracts
Portfolio Management &
Optimization
Portfolio Management Over Time
Align Hedging & Financials
Establishing Minimum Hedge Targets
9
Q3 2015
Earnings Release
Slides
•Ensure stability in near-term cash
flows and earnings
•Disciplined approach to hedging
•Tenor aligns with customer
preferences and market liquidity
•Multiple channels to market that
allow us to maximize margins
•Large open position in outer years
to benefit from price upside
•Ability to exercise fundamental market
views to create value within the ratable
framework
•Modified timing of hedges versus
purely ratable
•Cross-commodity hedging (heat rate
positions, options, etc.)
•Delivery locations, regional and zonal
spread relationships
•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
Bull / Bear Program
Three-Year Ratable Hedging
Strategic Policy Alignment
Credit Rating
Capital
Structure
Capital &
Operating
Expenditure
Dividend

10
Q3 2015  Earnings Release Slides
Components of Gross Margin Categories
Margins move from new business to MtM of hedges over
the course of the year as sales are executed
(5)
Margins move from “Non power new business” to
“Non power executed” over the course of the year
Gross margin linked to power production and sales
Gross margin from
other business activities
•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)
)
•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
•Retail, Wholesale
planned electric
sales
•Portfolio
Management new
business
•Mid marketing new
business
•Retail, Wholesale 
executed gas sales
•Energy Efficiency
(4)
•BGE Home
(4)
•Distributed Solar
•Retail, Wholesale
planned gas sales
•Energy Efficiency
(4)
•BGE Home
(4)
•Distributed Solar
•Portfolio
Management /
origination fuels
new business
•Proprietary
trading
(3)
Open Gross
Margin
MtM of
Hedges
(2)
“Power” New
Business
“Non-Power”
Executed
“Non-Power”
New Business
(1) Hedged gross margins for South, West & Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region
(2) MtM of hedges provided directly for the five larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh
(3) Proprietary trading gross margins will 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

11
Q3 2015  Earnings Release Slides
ExGen Disclosures 
(1)
Gross margin categories rounded to nearest $50M  
(2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and
fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon
Nuclear Partners, operating services agreement with Fort Calhoun and variable interest
entities. Total Gross Margin is also net of direct cost of sales for certain Constellation
businesses.  See Slide 29 for a Non-GAAP to GAAP reconciliation of Total Gross Margin.
(3)
Excludes EDF’s equity ownership share of the CENG Joint Venture
(4)
Mark-to-Market of Hedges assumes mid-point of hedge percentages
(5)
Based on September 30, 2015 market conditions
Gross Margin Category ($M)
(1)
2015
2016
2017
Open Gross Margin
(including South, West & Canada hedged GM)
(3)
$5,150
$5,650
$5,800
Mark-to-Market of Hedges
(3,4)
$2,200
$1,200
$750
Power New Business / To Go
$50
$500
$800
Non-Power Margins Executed
$400
$200
$100
Non-Power New Business / To Go
$50
$250
$350
Total Gross Margin
(2)
$7,850
$7,800
$7,800
Reference Prices
(5)
2015
2016
2017
Henry Hub Natural Gas ($/MMbtu)
$2.75
$2.80
$2.99
Midwest: NiHub ATC prices ($/MWh)
$28.80
$29.58
$28.95
Mid-Atlantic: PJM-WATC prices ($/MWh)
$37.05
$36.82
$35.36
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$3.12
$4.62
$4.47
New York: NY Zone A ($/MWh)
$33.55
$33.52
$33.22
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$5.57
$9.33
$10.73

12
Q3 2015  Earnings Release Slides
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 14
refueling outages in 2015, 12 in 2016, and 15 in 2017 at Exelon-operated nuclear plants, and Salem.  Expected generation assumes capacity factors of  93.5%, 94.1% and 93.3% in 2015 ,
2016 and 2017 respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2016 and 2017 do not represent guidance or a forecast of future
results as Exelon has not completed its planning or optimization processes for those years. (2) Excludes EDF’s equity ownership share of CENG Joint Venture. (3) Percent of expected generation
hedged is the amount of equivalent sales divided by expected generation.  Includes all hedging products, such as wholesale and retail sales of power, options and swaps.  (4) Effective realized
energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged.  It is developed by considering the energy revenues and costs
associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market
value of capacity contracted at prices other than RPM clearing prices including our load obligations.  It can be compared with the reference prices used to calculate open gross margin in order
to determine the mark-to-market value of Exelon Generation's energy hedges. (5) Spark spreads shown for ERCOT and New England.
Generation and Hedges
2015
2016
2017
(1)
186,700
199,400
205,300
Midwest
96,600
97,300
95,700
Mid-Atlantic
(2)
61,700
63,100
61,200
ERCOT
11,600
17,200
26,400
New York
(2)
9,300
9,300
9,200
New England
7,500
12,500
12,800
% of Expected Generation Hedged
(3)
97%-100%
81%-84%
51%-54%
Midwest
97%-100%
79%-82%
45%-48%
Mid-Atlantic
(2)
95%-98%
84%-87%
57%-60%
ERCOT
99%-102%
86%-89%
65%-68%
New York
(2)
94%-97%
72%-75%
46%-49%
New England
115%-118%
81%-84%
37%-40%
(4)
Midwest
$36.00
$34.50
$34.50
Mid-Atlantic
(2)
$51.50
$47.00
$45.50
ERCOT
(5)
$23.50
$11.00
$7.50
New York
(2)
$47.50
$45.50
$42.00
New England
(5)
$42.00
$20.00
$18.00
Effective Realized Energy Price ($/MWh)
Exp. Gen (GWh)

13
Q3 2015  Earnings Release Slides
ExGen Hedged Gross Margin Sensitivities
Gross Margin Sensitivities (With Existing Hedges)
(1)
2015
2016
2017
Henry Hub Natural Gas ($/Mmbtu)
+ $1/Mmbtu
-  
$110
$445
- $1/Mmbtu
$20
$(115)
$(430)
NiHub ATC Energy Price
+ $5/MWh
-  
$100
$275
- $5/MWh
-  
$(95)
$(275)
PJM-W ATC Energy Price
+ $5/MWh
-  
$45
$130
- $5/MWh
-  
$(40)
$(125)
NYPP Zone A ATC Energy Price
+ $5/MWh
-  
$10
$25
- $5/MWh
-  
$(10)
$(25)
Nuclear Capacity Factor
+/- 1%
+/- $10
+/- $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

14
Q3 2015  Earnings Release Slides
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
$9,050
$6,900
$7,900
$7,800
$8,250
$7,350
(1)
Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged
supply is sold into the spot market; Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future
transactions and potential modeling changes; These ranges of approximate gross margin in 2016 and 2017 do not represent earnings guidance or a forecast of future results
as Exelon has not completed its planning or optimization processes for those years; The price distributions that generate this range are calibrated to market quotes for power,
fuel, load following products, and options as of September 30, 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.  See Slide 29 for a Non-GAAP to GAAP reconciliation of Total Gross Margin. Excludes EDF’s equity ownership share of the CENG Joint Venture.

15
Q3 2015  Earnings Release Slides
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.  See Slide 29
for a Non-GAAP to GAAP reconciliation of Total Gross Margin.

16
Q3 2015  Earnings Release Slides
Additional Disclosures

17
Q3 2015  Earnings Release Slides
Exelon Utilities Adjusted Operating EPS Contribution
(1)
Key
Drivers
–
3Q15
vs.
3Q14:
BGE
(+0.01):
•
Increased distribution revenue due to increased rates and
lower storm costs: $0.01
PECO
(+0.01):
•
Favorable weather: $0.02
ComEd
(+0.02)
(2)
:
•
Favorable weather: $0.01
•
Increased distribution
earnings due to increased capital
investments: $0.02
•
Decreased distribution
earnings due to lower return on
common equity: $(0.01)
Exelon Utilities (-0.01):
•
Share differential: $(0.01)
3Q 2015
$0.33
$0.17
$0.10
$0.06
3Q 2014
$0.29
$0.15
$0.09
$0.05
BGE
ComEd
PECO
Numbers may not add due to rounding.
(1)
Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(2)
Due to the distribution formula rate, changes in ComEd’s earnings are driven primarily by changes in 30-year U.S. Treasury rates  (inclusive  of ROE), rate base and capital
structure in addition to weather, load and changes in customer mix.

18
Q3 2015  Earnings Release Slides
ExGen Adjusted Operating EPS Contribution
(1)
$0.55
Q3
$0.50
2015
2014
Numbers may not add due to rounding
(1)
Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(excludes Salem)
Q3
2014 Actual
Q3
2015
Actual
Planned Refueling Outage
Days
18
27
Non-refueling Outage Days
20
11
Nuclear Capacity Factor
96.5%
95.5%
Key
Drivers
–
3Q15
vs.
3Q14:
ExGen
(+0.05)
•
Increased RNF primarily due to the benefit of lower cost to serve
load in the Mid-Atlantic, Midwest, and New England regions and
the benefit from Integrys
acquisition, partially offset by the
absence of various generating units sold in 2014 and 2015: $0.10
•
Realized NDT fund losses in 2015 as compared to gains in 2014:
$(0.02)
•
Increased contracting costs primarily due to growth development
projects: $(0.02)
•
Other: $0.02
•
Share differential: $(0.03)

19
Q3 2015  Earnings Release Slides
ComEd April 2015 Distribution Formula Rate
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 (EIMA) legislation, ComEd net income during
the year will be based on actual costs with a regulatory asset/liability recorded to reflect any under/over recovery reflected in rates. 
Revenue Requirement in rate filings impacts cash flow.
Revenue Requirement 
Decrease
Rate Base
(1)
(1)
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
$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)
$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
(1)
Amounts represent ComEd’s position filed in surrebuttal testimony on August 20, 2015.
Note:  Disallowance of any items in the 2015 distribution formula rate filing could impact 2015 earnings in the form of a regulatory asset adjustment.

20
Q3 2015  Earnings Release Slides
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
•
October 2015 –
ALJ Recommended Decision
•
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. 

21
Q3 2015  Earnings Release Slides
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.

22
Q3 2015  Earnings Release Slides
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
2015 load growth is flat to
2014, driven by slowly
improving economic conditions
coupled with solid residential
customer growth, offset by
energy efficiency.
(1.2%)
(0.8%)
1.2%
0.1%
(1.6%)
2015E
1.0%
0.5%
2014
(0.6%)
Baltimore GMP
2.3%
Baltimore Unemployment
5.5%
Large C&I
Small C&I
Residential
All Customers
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.
0.0%
0.1%
0.1%
0.5%
0.2%
0.0%
0.1%
(0.1%)
Philadelphia GMP
1.8%
Philadelphia
Unemployment
5.2%
(0.7%)
0.2%
(0.8%)
0.3%
(0.3%)
(1.3%)
0.7%
(0.1%)
2015E
2014
Chicago GMP
2.1%
Chicago Unemployment
5.4%
PECO
BGE
ComEd
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.

23
Q3 2015  Earnings Release Slides
Appendix
Reconciliation of Non-GAAP
Measures

24
Q3 2015  Earnings Release Slides
3Q GAAP EPS Reconciliation
Three Months Ended September 30, 2015
ExGen
ComEd
PECO
BGE
Other
Exelon
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.55
$0.17
$0.10
$0.06
$(0.04)
$0.83
Mark-to-market impact of economic hedging activities
(0.09)
-
-
-
-
(0.09)
Unrealized losses related to NDT fund investments
(0.15)
-
-
-
-
(0.15)
Merger and integration costs
(0.01)
-
-
-
-
(0.02)
Asset retirement obligation
0.01
-
-
-
-
0.01
Tax settlements
0.06
-
-
-
-
0.06
CENG Non-Controlling Interest
0.05
-
-
-
-
0.05
3Q 2015 GAAP Earnings (Loss) Per Share
$0.41
$0.17
$0.10
$0.06
$(0.04)
$0.69
NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.
Three Months Ended September 30, 2014
ExGen
ComEd
PECO
BGE
Other
Exelon
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.50
$0.15
$0.09
$0.05
$(0.01)
$0.78
Mark-to-market impact of economic hedging activities
0.19
-
-
-
-
0.18
Unrealized losses related to NDT fund investments
(0.03)
-
-
-
-
(0.03)
Merger and integration costs
(0.05)
-
-
-
(0.01)
(0.06)
Mark-to-market impact of PHI merger related interest rate swaps
-
-
-
-
(0.01)
(0.01)
Amortization of commodity contract intangibles
0.01
-
-
-
-
0.01
Long-lived asset impairment
(0.03)
-
-
-
-
(0.03)
Plant retirement and divestitures
0.23
-
-
-
-
0.23
Asset retirement obligation
0.02
-
-
-
-
0.02
Tax settlements
0.08
-
-
-
-
0.08
CENG Non-Controlling Interest
(0.02)
-
-
-
-
(0.02)
3Q 2014 GAAP Earnings (Loss) Per Share
$0.90
$0.15
$0.09
$0.05
$(0.03)
$1.15

25
Q3 2015  Earnings Release Slides
3Q YTD GAAP EPS Reconciliation
NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.
Nine Months Ended September 30, 2014
ExGen
ComEd
PECO
BGE
Other
Exelon
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.07
$0.39
$0.30
$0.17
$(0.02)
$1.91
Mark-to-market impact of economic hedging activities
(0.34)
-
-
-
-
(0.34)
Unrealized gains related to NDT fund investments
0.07
-
-
-
-
0.07
Merger and integration costs
(0.09)
-
-
-
(0.02)
(0.11)
Mark-to-market impact of PHI merger related interest rate swaps
-
-
-
-
(0.01)
(0.01)
Amortization of commodity contract intangibles
(0.05)
-
-
-
-
(0.06)
Long-lived asset impairment
(0.10)
-
-
-
(0.02)
(0.11)
Plant retirements and divestitures
0.23
-
-
-
-
0.23
Asset retirement obligation
0.02
-
-
-
-
0.02
Tax settlements
0.12
-
-
-
-
0.12
Gain on CENG integration
0.18
-
-
-
-
0.18
CENG Non-Controlling Interest
(0.04)
-
-
-
-
(0.04)
3Q 2014 GAAP Earnings (Loss) Per Share
$1.07
$0.39
$0.30
$0.17
$(0.07)
$1.86

26
Q3 2015  Earnings Release Slides
3Q YTD GAAP EPS Reconciliation (continued)
Nine Months Ended September 30, 2015
ExGen
ComEd
PECO
BGE
Other
Exelon
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.26
$0.39
$0.34
$0.23
$(0.09)
$2.13
Mark-to-market impact of economic hedging activities
0.18
-
-
-
-
0.18
Unrealized losses related to NDT fund investments
(0.19)
-
-
-
-
(0.19)
Merger and integration costs
(0.02)
(0.01)
-
-
(0.03)
(0.06)
Mark-to-market impact of PHI merger related interest rate swaps
-
-
-
-
0.03
0.03
Amortization of commodity contract intangibles
0.01
-
-
-
-
0.01
Long-lived asset impairment
-
-
-
-
(0.02)
(0.02)
Asset retirement obligation
0.01
0.01
Tax settlements
0.06
0.06
Midwest Generation bankruptcy recoveries
0.01
-
-
-
-
0.01
CENG Non-Controlling Interest
0.06
-
-
-
-
0.06
3Q 2015 GAAP Earnings (Loss) Per Share
$1.38
$0.38
$0.34
$0.23
$(0.11)
$2.22
NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

27
Q3 2015  Earnings Release Slides
GAAP to Operating Adjustments
NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.
•
Exelon’s 2015 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:
Mark-to-market adjustments from economic hedging activities
Unrealized gains and losses from NDT fund investments to the extent not offset by contractual
accounting as described in the notes to the consolidated financial statements
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

28
Q3 2015  Earnings Release Slides
ExGen
Total Gross Margin Reconciliation to GAAP
Total
Gross Margin Reconciliation (in $M)
(4)
2015
2016
2017
Revenue Net of Purchased Power and Fuel Expense
(1)(5)
$8,350
$8,350
$8,300
Other Revenues
(2)
$(200)
$(250)
$(250)
Direct cost of sales incurred to generate revenues for certain
Constellation businesses
(3)
$(300)
$(300)
$(250)
Total Gross Margin (Non-GAAP, as shown on slide 6)
$7,850
$7,800
$7,800
(1)
Revenue net of purchased power and fuel expense (RNF), a non-GAAP measure, is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased
power and fuel expense. ExGen does not forecast the GAAP components of RNF separately. RNF also includes the RNF of our proportionate ownership share of CENG
(2)
Reflects revenues from operating services agreement with Fort Calhoun, variable interest entities, funds collected through revenues for decommissioning the former PECO
nuclear plants through regulated rates and gross receipts tax revenues
(3)
Reflects the cost of sales and depreciation expense of certain Constellation businesses of Generation
(4)
All amounts rounded to the nearest $50M
(5)
Excludes the impact of the operating exclusion for mark-to-market due to the volatility and unpredictability of the future changes to power prices

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