EXELON CORP - FORM 8-K - EX-99.2 - July 29, 2015

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Earnings Conference Call
2
nd
Quarter 2015
July 29, 2015
Exhibit 99.2

2
Q2 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 Second Quarter 2015 Quarterly Report on
Form 10-Q (to be filed on July 29, 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.

3
Q2 2015  Earnings Release Slides
•
Pepco Holdings Merger
o
Received regulatory approval in
Maryland and Delaware
•
Nuclear capacity factor of 93.1%
(2)
•
Power dispatch match of 99.2%
and renewables energy capture of
96.1%
•
1
st
quartile Customer Satisfaction
Index (CSI) scores across all
utilities
•
Capacity Performance
•
Illinois Low Carbon Portfolio
Standard legislation
•
EPA Clean Power Plan
•
PECO and ComEd rate cases
•
Delivered Q2 adjusted operating
earnings of $0.59 per share,
exceeding our guidance range
(1)
Q2 2015 in Review
(1)
Represents
adjusted
(non-GAAP)
operating
EPS.
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)
Exelon operated plants at ownership, excluding Salem   
Delivered another strong quarter of financial results and operational performance across the
company
Financial
Discipline
Operational
Excellence
Regulatory
and Policy
Efforts
Opportunistic
Growth

4
Q2 2015  Earnings Release Slides
Forward Market Outlook
Q2 2015  Lower Volatility and Lower Prices
Forward Markets Reacted To Spot Prices
Impacts on Forward Markets
•
While forward natural gas prices stayed relatively flat during
the quarter, we saw a significant decrease in power prices and
subsequently heat rates in 2016 and 2017
•
The lack of liquidity in the forward power markets has
exacerbated the drops in forward power prices and heat rates
Spot Market Update
•
The spot power market in 2015 has been less volatile compared
to 2014
•
Spot market conditions are driving weaker prices:
•
Cooling  degree days
this summer have been below the 30-year
average in Chicago and near normal on the East Coast 
•
NYMEX  gas prices
averaged $2.72 in Q2 2015, while gas prices in
Q2
2014
averaged
$4.64,
a
$1.92
MMBtu
difference
year
over
year
•
TETCo
M3 basis prices
continue to stay weak with Q2 2015
averaging a $1.05 discount to NYMEX
Cool weather in the Midwest has pressured power prices across the region.  Our fundamental
view is that gas and power prices will be stronger in the forward years.
8
9
10
11
12
13
14
15
16
PJMW_HR_2016
PJMW_HR_2017
PJMNiHub_HR_2016
PJMNiHub_HR_2017
Cooling Degree Days -
Chicago
0
2
4
6
8
10
12
30-yr Average
2015
Week Number

5
Q2 2015  Earnings Release Slides
Forward Markets and Hedging Activity
(1)
Mid-point of disclosed total portfolio hedge % range was used
•
Our fundamental view remains relatively unchanged
•
We expect further upside in NiHub
forward market
based on our fundamental forecast given current
natural gas prices, expected retirements, new
generation resources, and load assumptions
We are deploying a behind ratable strategy and a cross–commodity position to broaden
exposure to power upside
•
We align our hedging strategies with our fundamental
views by leaving portfolio exposure to power price
upside
•
We have left a significant amount of our portfolio open
to moves in the power market, when considering our
behind ratable and cross commodity strategies
•
Generation 54-56% open in 2017
•
7-8% behind ratable
NiHub
Market versus Fundamental View
2017: Maintaining a More Open Position
(1)
$/MWh
27.00
28.00
29.00
30.00
31.00
32.00
33.00
34.00
35.00
2016
2017
Market as of 3/31/2015
Internal View
Market as of 6/30/2015
Approximately
$1.00/MWh
upside
Approximately
$3.00/MWh
upside
20%
25%
30%
35%
40%
45%
50%
Q4-14
Q1-15
Q2-15
2017 -
Actual
2017 -
Ratable
2017 -
Actual (excl NG hedges)

6
Q2 2015  Earnings Release Slides
Exelon Generation: Gross Margin Update
1)
Gross margin categories rounded to nearest $50M
2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power
and fuel expense, excluding revenue related to decommissioning, gross receipts tax,
Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable
interest entities. Total Gross Margin is also net of direct cost of sales for certain
Constellation
businesses.
See
Slide
29
for
a
Non-GAAP
to
GAAP
reconciliation
of
Total
Gross Margin.
3)
Excludes EDF’s equity ownership share of the CENG Joint Venture
4)
Mark-to-Market of Hedges assumes mid-point of hedge percentages
•
Load serving business had a strong quarter driven by our generation to load matching
strategy
•
Power prices declined, natural gas prices were relatively flat, and heat rates contracted during
the quarter
•
Behind ratable reflecting the fundamental upside we see in power prices in 2016 and 2017
Recent Developments
Gross Margin Category ($M)
(1)
2015
2016
2017
2015
2016
2017
Open Gross Margin
(3)
(including South, West, Canada hedged gross
margin)
$5,250
$5,700
$5,750
$(350)
$(200)
$(300)
Mark-to-Market of Hedges
(3,4)
$1,850
$900
$500
$550
$300
$150
Power New Business / To Go
$100
$450
$900
$(150)
$(50)
$100
Non-Power Margins Executed
$350
$200
$100
$50
$50
$50
Non-Power New Business / To Go
$100
$250
$350
$(50)
$(50)
$(50)
Total Gross Margin
(2)
$7,650
$7,500
$7,600
$50
$50
$(50)
June 30, 2015
Change from Mar 31, 2015

7
Q2 2015  Earnings Release Slides
Key Financial Messages
Expect
Q3
2015
earnings
of
$0.65
-
$0.75/share
and
narrowing
full-year
guidance
range
from
$2.25
-
$2.55/share
to
$2.35
-
$2.55/share
(3,4)
(1)
(2)
Amounts may not add due to rounding
(3)
ComEd ROE based on 30 Year average Treasury yield of 2.94% as of 6/30/15. 25 basis point move in 30 Year Treasury Rate equates to +/-$0.01 impact to EPS.
(4)
2015 earnings guidance based on expected average outstanding shares of ~892M.  Refer to Appendix for a reconciliation of adjusted non-GAAP operating EPS guidance to GAAP EPS.
HoldCo
BGE
ExGen
ComEd
PECO
Q2 2015
$0.59
-$0.01
$0.36
$0.12
$0.08
$0.05
Adjusted Operating EPS Results
(1,2)
•
Delivered adjusted (non-GAAP) operating
earnings in Q2 of $0.59/share exceeding
our guidance range of $0.45-$0.55/share
•
Utilities
Increased distribution revenues
Lower uncollectible expense at BGE
Net neutral weather impacts
•
ExGen
Lower costs to serve load
Strong portfolio management
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

8
Q2 2015  Earnings Release Slides
2015 Projected Sources and Uses of Cash
(1)
All amounts rounded to the
nearest $25M.
(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 ~$4B of free cash flow in
2015, including $0.9B at ExGen
and
$3.3B at the Utilities
Creating value for customers, communities
and shareholders
Investing $4.7B, with $3.7B at the
Utilities and $1B at ExGen
($ in millions)
(1)
BGE
ComEd
PECO
Total
Utilities
ExGen
Corp
(6)
Exelon
2015E
Cash
Balance
3,575
Adjusted Cash Flow from Operations
(3)
600
2,000
675
3,300
3,275
25
6,600
Base CapEx and Nuclear Fuel
0
0
0
0
(2,375)
(50)
(2,450)
Free Cash Flow
600
2,000
675
3,300
900
(25)
4,175
Net Financing (excluding items below)
(75)
500
350
775
200
3,400
4,375
Project Financing
n/a
n/a
n/a
n/a
(50)
n/a
(50)
Equity Issuance
0
0
0
0
0
1,875
1,875
Contribution from Parent
0
100
0
100
0
(100)
0
Other Financing
(4)
300
75
0
350
1,125
300
1,800
Financing
225
675
350
1,225
1,275
5,475
7,975
825
2,675
1,025
4,525
2,175
5,425
12,150
Utility Investment
(700)
(2,400)
(600)
(3,700)
0
0
(3,700)
ExGen Growth
0
0
0
0
(1,050)
0
(1,050)
Dividend
(5)
(1,100)
Other CapEx and Dividend
(700)
(2,400)
(600)
(3,700)
(1,050)
0
(5,850)
Total Cash Flow
125
275
450
825
1,125
5,425
6,300
Ending Cash Balance
9,850
Total Free Cash Flow and Financing Growth
Beginning Cash Balance
(2)
(2)

9
Q2 2015  Earnings Release Slides
Exelon Generation Disclosures
June 30, 2015

10
Q2 2015  Earnings Release Slides
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
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
Credit Rating
Capital &
Operating
Expenditure
Dividend
Capital
Structure

11
Q2 2015  Earnings Release Slides
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
•Load Response
•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 new business to MtM
of hedges over
the course of the year as sales are executed
(5)
Margins move from “Non power new business” to
“Non power executed” over the course of the year
Gross margin linked to power production and sales
Gross margin from
other business activities
(1) Hedged
gross
margins
for
South,
West
&
Canada
region
will
be
included
with
Open
Gross
Margin,
and
no
expected
generation,
hedge
%,
EREP
or
reference
prices
provided
for
this
region
(2) MtM
of
hedges
provided
directly
for
the
five
larger
regions;
MtM
of
hedges
is
not
provided
directly
at
the
regional
level
but
can
be
easily
estimated
using
EREP,
reference
price
and
hedged
MWh
(3) Proprietary
trading
gross
margins
will
generally
remain
within
“Non
Power”
New
Business
category
and
only
move
to
“Non
Power”
Executed
category
upon
management
discretion
(4) Gross margin for these businesses are net of direct “cost of sales”
(5) Margins for South, West & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin

12
Q2 2015  Earnings Release Slides
ExGen Disclosures 
(1)
Gross margin categories rounded to nearest $50M  
(2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and
fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon
Nuclear Partners, operating services agreement with Fort Calhoun and variable interest
entities. Total Gross Margin is also net of direct cost of sales for certain Constellation
businesses.  See Slide 29 for a Non-GAAP to GAAP reconciliation of Total Gross Margin.
(3)
Excludes EDF’s equity ownership share of the CENG Joint Venture
(4)    Mark-to-Market of Hedges assumes mid-point of hedge percentages
(5)    Based on June 30, 2015 market conditions
Gross Margin Category ($M)
(1)
2015
2016
2017
Open
Gross
Margin
(including
South,
West
&
Canada
hedged
GM)
(3)
$5,250
$5,700
$5,750
Mark-to-Market of Hedges
(3,4)
$1,850
$900
$500
Power New Business / To Go
$100
$450
$900
Non-Power Margins Executed
$350
$200
$100
Non-Power New Business / To Go
$100
$250
$350
Total Gross Margin
(2)
$7,650
$7,500
$7,600
Reference Prices
(5)
2015
2016
2017
Henry Hub Natural Gas ($/MMbtu)
$2.86
$3.17
$3.36
Midwest: NiHub ATC prices ($/MWh)
$28.75
$30.65
$30.17
Mid-Atlantic: PJM-W ATC prices ($/MWh)
$37.89
$38.27
$36.99
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$3.43
$3.82
$4.06
New York: NY Zone A ($/MWh)
$33.12
$34.03
$33.52
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$4.85
$8.77
$9.87

13
Q2 2015  Earnings Release Slides
ExGen Disclosures
Generation and Hedges
2015
2016
2017
Exp. Gen (GWh)
(1)
190,300
198,500
204,200
Midwest
96,500
97,300
95,900
Mid-Atlantic
(2)
61,700
63,000
61,000
ERCOT
12,700
16,300
25,300
New York
(2)
9,300
9,300
9,300
New England
10,100
12,600
12,700
% of Expected Generation Hedged
(3)
77%-80%
46%-49%
Midwest
97%-100%
72%-75%
38%-41%
Mid-Atlantic
(2)
100%-103%
82%-85%
55%-58%
ERCOT
99%-102%
93%-96%
60%-63%
New York
(2)
94%-97%
76%-79%
48%-51%
New England
99%-102%
67%-70%
28%-31%
Effective Realized Energy Price ($/MWh)
(4)
Midwest
$35.00
$34.00
$34.00
Mid-Atlantic
(2)
$49.50
$45.50
$44.50
ERCOT
(5)
$19.50
$10.00
$7.00
New York
(2)
$46.50
$41.50
$39.00
New England
(5)
$32.50
$19.00
$17.00
(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  93.3%, 94.1% and 93.4% 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. 
98%-101%

14
Q2 2015  Earnings Release Slides
ExGen Hedged Gross Margin Sensitivities
(1)
Based on June 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 
Gross
Margin
Sensitivities
(With
Existing
Hedges)
(1)
2015
2016
2017
Henry Hub Natural Gas ($/Mmbtu)
+ $1/Mmbtu
$(80)
$140
$400
-
$1/Mmbtu
$90
$(135)
$(385)
NiHub ATC Energy Price
+ $5/MWh
-
$135
$305
-
$5/MWh
-
$(135)
$(305)
PJM-W ATC Energy Price
+ $5/MWh
$(10)
$60
$145
-
$5/MWh
$10
$(55)
$(140)
NYPP Zone A ATC Energy Price
+ $5/MWh
-
$5
$20
-
$5/MWh
-
$(10)
$(20)
Nuclear Capacity Factor
+/-
1%
+/-
$20
+/-
$45
+/-
$40

15
Q2 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
$8,950
$6,500
$7,750
$7,500
$8,050
$7,000
(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 June 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.

16
Q2 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.
Row
Item
Midwest
Mid-Atlantic
ERCOT
New York
New England
South, West &
Canada
(A)
(B)
97.3
63.0
16.3
9.3
12.6
(C)
73.5%
83.5%
94.5%
77.5%
68.5%
(D=B*C)
71.5
52.6
15.4
7.2
8.6
(E)
$34.00
$45.50
$10.00
$41.50
$19.00
(F)
$30.65
$38.27
$3.82
$34.03
$8.77
(G=E-F)
$3.35
$7.23
$6.18
$7.47
$10.23
(H=D*G)
$240
$380
$95
$55
$90
(I=A+H)
(J)
(K)
(L)
Start with fleet-wide open gross margin  
Expected Generation (TWh)
Hedge % (assuming mid-point of range)
Hedged Volume (TWh)
Effective Realized Energy Price ($/MWh)
Reference Price ($/MWh)
Difference ($/MWh)
Mark-to-market value of hedges  ($ million)
(1)
Hedged Gross Margin ($ million)
Power New Business / To Go ($ million)
Non-Power Margins Executed ($ million)
Non-Power New Business / To Go ($ million)
$200
$250
$5.7 billion
$6,600
$450
(N=I+J+K+L)
Total Gross Margin
(2)
$7,500 million

17
Q2 2015  Earnings Release Slides
Additional Disclosures

18
Q2 2015  Earnings Release Slides
Exelon Utilities Adjusted Operating EPS Contribution
(1)
Key Drivers  –
2Q15 vs. 2Q14
:
BGE
(+0.03):
•
Decreased uncollectible expense: $0.02
•
Increased distribution revenue due to increased rates: $0.01
PECO (-0.02):
•
Increased storm costs: ($0.01)
ComEd
(-0.01):
•
Unfavorable weather
(2)
: $(0.01)
•
Increased distribution
(2)
earnings due to increased capital
investments: $0.01
2Q 2015
$0.25
$0.12
$0.08
$0.05
2Q 2014
$0.25
$0.13
$0.10
$0.02
BGE
ComEd
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.
PECO
(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.

19
Q2 2015  Earnings Release Slides
ExGen Adjusted Operating EPS Contribution
(1)
$0.36
Q2
$0.27
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)
Q2
2014 Actual
Q2
2015
Actual
Planned
Refueling
Outage
Days
108
71
Non-refueling
Outage
Days
44
18
Nuclear
Capacity
Factor
91.8%
93.1%
Key Drivers –
Q2 2015 vs. Q2 2014
ExGen
(+0.09)
•
Increased RNF: $0.10
•
Increased nuclear output in 2015, primarily due to a reduction in
outage days: $0.07
•
Favorability from portfolio management optimization activities,
partially offset by the absence of various generating units sold in
2014 and 2015: $0.02
•
Increased capacity revenue: $0.01
•
Higher realized NTDF gains: $0.03
•
Increased income tax expense due to decreased domestic production
activities deduction: ($0.03)
•
Increased interest expense: ($0.01)

20
Q2 2015  Earnings Release Slides
2015 Regulatory and Legislative Timelines
Settlement Filed
in New Jersey
(Jan 14)
New Jersey
Approval
(Feb 11)
Settlement
filed in
Delaware
(Feb 13)
Multi-party
Settlement
filed in
Maryland
(March 16)
Maryland
Settlement
Hearings (April
15-21)
DC Initial
Briefs Due
(May 13)
Maryland PSC
Approval (May
15)
DC Reply
Briefs Due
(May 27)
Delaware
Approval
(June 2)
Expected
Transaction
Close (Q3)
Illinois Legislative
Session Begins
(Jan 14)
IL Senate
Committee
approves LCPS &
ComEd legislation
(March 27)
MATS Rule in
Effect (April)
Supreme Court
decision on cert in
EPSA v. FERC
(Demand
Response) (May)
Illinois Regular
Legislative
Session Ends
(May 31)
Supreme Court
Decision in
Michigan vs. EPA
(MATS) (June)
FERC Approves
Capacity
Performance
(June 9)
PJM BRA Auction
Results (Aug. 21)
Final Clean Power
Rule (111d)
Issued (Aug/Sept)
Illinois Legislative
Veto Session (TBD
Oct/Nov)
ExGen
Exelon Utilities
PHI Acquisition
PECO Electric Rate
Case and LTIIP Filing
(March 27)
ComEd Formula
Rate Filing (April15)
BGE Electric and
Gas Rate Case Filing
(TBD) MD PSC
Ruling Expected 7
Months after Filing
PaPUC
Ruling
Expected on LTIIP
Filing (Q3)
PaPUC
Ruling
Expected on PECO
Electric Rate Case
(Dec)
ICC Rules on ComEd
Formula Rate Filing
(Dec)

21
Q2 2015  Earnings Release Slides
ComEd April 2015 Distribution Formula Rate
Amounts represent ComEd’s
position filed in rebuttal testimony on July 22, 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.
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.
(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)
$54M decrease  ($145M decrease due to the 2014 reconciliation offset by a $91M 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.
Revenue 
Requirement 
Decrease
Rate Base
(1)
(1)

22
Q2 2015  Earnings Release Slides
PECO Electric Distribution Rate Case
Docket #
R-2015-2468981
Fully Projected Future Test Year
2016
Common Equity Ratio
53%
10.95%
Overall Rate of Return
8.2%
Proposed Rate Base
$4.1B
$190M
System Average Increase as % of overall bill
4.4%
Timeline
•
3/27/15 –
PECO
filed electric distribution rate case with PaPUC
•
8/11/15 –
8/14/15 –
Evidentiary Hearings
•
October 2015 –
ALJ Recommended Decision
•
December 2015 –
PUC Decision
•
Increased rates effective on January 1, 2016
Basis for Rate Case
•
Since last rate case (2010):
–
Electric Distribution Rate base increased by one third (approximately $1B)
–
Sales declined by 0.6%
–
Operating expenses were essentially flat (less than 1% annually)
•
Proposed investment maintains strong reliability performance with targeted
investment to address pockets with reliability issues
First Electric Distribution Rate Case since 2010
Requested Return on Equity
Revenue Requirement Increase Ask

23
Q2 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
Expected approval in 3Q15
•
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.

24
Q2 2015  Earnings Release Slides
Exelon Utilities Load
2015E
2014
PECO
2015 load growth is driven by
modest economic growth
coupled with solid residential
customer growth, partially
offset by energy efficiency
Philadelphia GMP
1.7%
Philadelphia
Unemployment
5.3%
Notes: Data is not adjusted for leap year.  Source of economic outlook data is IHS (June 2015) and Bureau of Economic Analysis.  Assumes 2015 GDP of 2.1% and U.S. unemployment of
5.3%. 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.
2015E
2014
Large C&I
Small C&I
Residential
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
1.7%
Chicago Unemployment
6.2%
BGE
2015 load growth is greater
than 2014, attributable to
slowly improving
economic
conditions and moderate
customer growth, partially
offset by energy efficiency
Baltimore GMP
1.3%
Baltimore Unemployment
5.6%
2015E
2014
0.3%
0.1%
1.1%
0.5%
0.0%
0.0%
0.2%
-0.1%
(0.6%)
0.2%
(0.9%)
0.3%
(0.2%)
(0.3%)
(0.9%)
0.7%
-1.2%
0.1%
-0.8%
0.1%
1.1%
-0.6%
0.0%
-1.6%

25
Q2 2015  Earnings Release Slides
Appendix
Reconciliation of Non-GAAP
Measures

26
Q2 2015  Earnings Release Slides
Three Months Ended June 30, 2015
ExGen
ComEd
PECO
BGE
Other
Exelon
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.36
$0.12
$0.08
$0.05
$(0.01)
$0.59
Mark-to-market impact of economic hedging activities
0.16
-
-
-
-
0.16
Unrealized losses related to NDT fund investments
(0.06)
-
-
-
-
(0.06)
Merger and integration costs
(0.01)
-
-
-
(0.01)
(0.02)
Mark-to-market impact of PHI merger related interest rate swaps
-
-
-
-
0.08
0.08
Amortization of commodity contract intangibles
(0.01)
-
-
-
-
(0.01)
Long-lived asset impairment
-
-
-
-
(0.02)
(0.02)
CENG Non-Controlling Interest
0.02
-
-
-
-
0.02
2Q 2015 GAAP Earnings Per Share
$0.46
$0.12
$0.08
$0.05
$0.04
$0.74
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 June 30, 2014
ExGen
ComEd
PECO
BGE
Other
Exelon
2014 Adjusted (non-GAAP) Operating Earnings Per Share
$0.27
$0.13
$0.10
$0.02
$-
$0.51
Mark-to-market impact of economic hedging activities
(0.01)
-
-
-
-
(0.01)
Unrealized gains related to NDT fund investments
0.09
-
-
-
-
0.09
Merger and integration costs
(0.02)
-
-
-
(0.01)
(0.03)
Amortization of commodity contract intangibles
(0.03)
-
-
-
-
(0.03)
Long-lived asset impairment
(0.06)
-
-
-
(0.02)
(0.08)
Gain on CENG integration
0.18
-
-
-
-
0.18
CENG Non-Controlling Interest
(0.03)
-
-
-
-
(0.03)
2Q 2014 GAAP Earnings Per Share
$0.39
$0.13
$0.10
$0.02
$-
$0.60
2Q GAAP EPS Reconciliation

27
Q2 2015  Earnings Release Slides
2Q YTD GAAP EPS Reconciliation
Six Months Ended June 30, 2015
ExGen
ComEd
PECO
BGE
Other
Exelon
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.71
$0.22
$0.24
$0.18
$(0.05)
$1.30
Mark-to-market impact of economic hedging activities
0.27
-
-
-
-
0.27
Unrealized losses related to NDT fund investments
(0.04)
-
-
-
-
(0.04)
Merger and integration costs
(0.01)
-
-
-
(0.03)
(0.04)
Mark-to-market impact of PHI merger related interest rate swaps
-
-
-
-
0.03
0.03
Amortization of commodity contract intangibles
0.02
-
-
-
-
0.02
Long-lived asset impairment
-
-
-
-
(0.02)
(0.02)
Midwest Generation bankruptcy recoveries
0.01
-
-
-
-
0.01
CENG Non-Controlling Interest
0.01
-
-
-
-
0.01
2Q 2015 GAAP Earnings (Loss) Per Share
$0.97
$0.22
$0.24
$0.18
$(0.07)
$1.54
NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.
Six Months Ended June 30, 2014
ExGen
ComEd
PECO
BGE
Other
Exelon
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.57
$0.24
$0.20
$0.12
$(0.01)
$1.12
Mark-to-market impact of economic hedging activities
(0.52)
-
-
-
-
(0.52)
Unrealized gains related to NDT fund investments
0.10
-
-
-
-
0.10
Merger and integration costs
(0.03)
-
-
-
(0.01)
(0.04)
Amortization of commodity contract intangibles
(0.06)
-
-
-
-
(0.06)
Long-lived asset impairment
(0.06)
-
-
-
(0.02)
(0.08)
Tax settlements
0.04
-
-
-
-
0.04
Gain on CENG integration
0.18
-
-
-
-
0.18
CENG Non-Controlling Interest
(0.03)
-
-
-
-
(0.03)
2Q 2014 GAAP Earnings (Loss) Per Share
$0.18
$0.24
$0.20
$0.12
$(0.04)
$0.71

28
Q2 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 the 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
Impairment of investment in long-term generating leases
Generation’s non-controlling interest related to CENG exclusion items
Other unusual items

29
Q2 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)
$8,200
$8,100
$8,300
Other revenues
(2)
$(250)
$(250)
$(250)
Direct cost of sales incurred to generate revenues for certain
Constellation businesses
(3)
$(300)
$(350)
$(450)
Total Gross Margin (Non-GAAP, as shown on slide (6)
$7,650
$7,500
$7,600
(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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