ATLANTIC CITY ELECTRIC CO - FORM 8-K - EX-99.2 - EARNINGS CONFERENCE CALL PRESENTATION SLIDES - May 6, 2016

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EX-99.1 - PRESS RELEASE AND EARNINGS RELEASE ATTACHMENTS - ATLANTIC CITY ELECTRIC COd51816dex991.htm
8-K - FORM 8-K - ATLANTIC CITY ELECTRIC COd51816d8k.htm
Earnings Conference Call
1
st
Quarter 2016
May 6, 2016
Exhibit 99.2

2
Q1 2016  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, Exelon Generation Company,
LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and
Electric Company,  Pepco Holdings LLC (PHI), Potomac Electric Power Company,
Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants)
include those factors discussed herein, as well as the items discussed in (1)  Exelon’s
2015 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 23; (2)
PHI’s 2015 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 16;
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
Q1 2016  Earnings Release Slides
Combined Company at a Glance

4
Q1 2016  Earnings Release Slides
Exelon Utilities are an Industry Leader
8.1
14.0
14.9
17.5
18.6
21.6
22.3
23.3
24.3
29.7
32.6
44.0
48.5
32.7
Legacy
PHI
PPL
FE
ETR
D
Legacy
EXC
XEL
EIX
ED
Combined
EXC
PGE
AEP
SO
DUK
Total Utility Rate Base ($B)
(1)
Total Capital Expenditures 2016-2018 ($B)
(1)
4.1
8.3
9.6
9.9
11.5
12.3
15.0
16.1
17.7
17.9
18.9
23.0
26.3
Combined
EXC
(2)
DUK
Legacy PHI
XEL
ETR
PPL
PEG
EIX
AEP
D
PGE
SO
Legacy
EXC
US Utility Customers (millions)
2.0
2.8
3.8
4.0
4.5
4.8
4.8
5.0
5.3
5.5
6.0
7.9
8.0
8.2
9.7
10.0
Legacy
PHI
ETR
D
PEG
SO
NEE
ED
EIX
PGE
Combined
EXC
AEP
XEL
FE
DUK
Legacy
EXC
SRE
Source:  Company Filings
(1)
Includes utility and generation
(2)
$23B includes $15.6B of utility capital expenditures and $7.4B of generation capital expenditures

5
Q1 2016  Earnings Release Slides
Exelon Generation is an Industry Leader
Retail Load Served (TWhs)
(2)
Carbon Intensity (lb/MWh)
(1)
54.4
60.8
68.8
88.6
93.9
96.5
99.4
103.0
129.4
153.1
175.7
180.1
195.1
243.4
PEG
DYN
XEL
PPL/TLN
D
FE
NRG
CPN
ETR
AEP
NEE
SO
EXC
(3)
DUK
Total Generation Output (TWh)
(1)
16
18
19
19
20
24
33
38
41
41
53
64
67
124
139
Talen
ConEd
Solutions
Gexa
Energy
MidAmerican
Energy
EDF
Energy
Services
Dynegy
Just
Energy
Champion
Energy
Services
Noble
Solutions
TXU
Energy
GDF Suez
First
Energy
Solutions
NRG
Energy
Direct
Energy
Constellation
(1) Includes
regulated
and
non-regulated
generation.
Source:
Benchmarking
Air
Emissions,
July
2015;
http://mjbradley.com/sites/default/files/Benchmarking-Air-Emissions-2015.pdf
(2) Source:  DNV GL Retail Landscape April  2016
(3) Excludes EDF’s equity ownership share of the CENG Joint Venture
1,878
1,752
1,686
1,552
1,507
1,390
1,194
1,126
815
779
594
564
555
200
PPL/TLN
FE
SO
DYN
AEP
NRG
XEL
DUK
CPN
D
ETR
PEG
NEE
EXC
(3)

6
Q1 2016  Earnings Release Slides
Operations
Metric
2015
YE
BGE
PECO
ComEd
Electric
Operations
OSHA Recordable 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
Overall Rank
Electric Utility Panel of 24
Utilities
3
rd
2
nd
3
rd
Best in Class Operations
Q1
Q2
Q3
Q4
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
Legacy Exelon Utilities Operational Metrics
ExGen
Operational Metrics
•
Continued best in class performance across
our Nuclear fleet:
o
Q1 Nuclear Capacity Factor: 95.8%
o
Q1 average refueling outage duration of
24 days versus industry average
refueling outage duration of 36 days
•
Strong performance across our Fossil and
Renewable fleet:
o
Q1 Renewables energy capture: 96.2%
o
Q1 Power dispatch match: 93.5%
o
No employee OSHA or DART recordable
events in Q1

Early Retirement of Clinton and Quad Cities
We will shut down Clinton Power Station on June 1, 2017 and Quad Cities
Generating Station on June 1, 2018 if Illinois does not pass adequate
legislation by May 31, 2016 and if Quad Cities does not clear the 19/20
PJM capacity auction in May
Impact on Illinois of Plant Closures
(1)
•
The gross impact of shutting down
Clinton and Quad Cities would be:
•
$1.2 billion annually in lost economic
activity in Illinois
•
4,200 jobs lost, many of which are
highly skilled, good paying jobs
•
According to independent analyses by
PJM and MISO, there would be a
significant increase in electricity prices
for Illinois residents and businesses
•
Economic damages associated with an
incremental increase in the release of
carbon dioxide emissions would cost
Illinois consumers nearly $10 billion over
10 years
Nuclear Plant Economics Deteriorating
•
Illinois legislation aimed at leveling the
playing field for zero carbon resources
has failed to advance in the past two
legislative sessions
•
PJM power prices hit 15 year record low
in March
•
Illinois forward energy prices have
declined by roughly 10% in the last year
•
From 2009 to 2015, Quad Cities and
Clinton have sustained more than $800
million in cash flow losses on a pre-tax
basis
(2)
(1)
Source:  January 5, 2015 Response to the IL General Assembly Concerning House Resolution 1146 prepared by Illinois Commerce Commission, Illinois Power Agency, Illinois Environmental
Protection Agency, and Illinois Department of Commerce and Economic Opportunity
(2)
Revenues include realized energy and capacity revenue excluding any hedges; costs include all site expenses (including taxes other than income taxes), DOE spent fuel fees prior to their
suspension in mid-2014, charged and allocated overhead, fuel capex, and non-fuel capex. Losses only reflect the extent to which revenues fell short of cash costs and do not reflect the
absence of expected investor return on investment
7
Q1
2016
Earnings Release
Slides

Q1 2016 Financial Results
ExGen
Q1 2016
$0.68
$(0.02)
$0.12
$0.14
HoldCo
ComEd
PECO
PHI
BGE
$0.00
$0.11
$0.34
Adjusted Operating EPS Results
(1,2)
•
Delivered adjusted (non-GAAP) operating
earnings in Q1 of $0.68/share near the
top of our guidance range of $0.60-
$0.70/share
•
Utilities
Lower bad debt expense
Unfavorable weather
Higher storm costs
•
ExGen
Lower cost to serve load
Strong performance at Constellation
Lower O&M primarily timing within the
year
Expect
Q2
2016
Adjusted
Operating
Earnings
of
$0.50
-
$0.60
per
share
$0.34
8
Q1
2016
Earnings Release
Slides
(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

HoldCo
ExGen
ComEd
PECO
BGE
$2.40 -
$2.70
(1)
$(0.05)
$1.25 -
$1.35
$0.50 -
$0.60
$0.40 -
$0.50
$0.25 -
$0.35
2016 Adjusted Operating Earnings Guidance
Confirming
full-year
guidance
range
of
$2.40
-
$2.70/share
(2,3)
Key Changes
•
Average outstanding share
count of 926M vs. 890M from
Q4 standalone guidance
•
Interest on debt issued for PHI
transaction captured at
HoldCo
•
Includes PHI contribution to
earnings for remainder of year
$(0.10) –
$(0.20)
$2.40 -
$2.70
(2,3)
PHI
BGE
HoldCo
ComEd
ExGen
PECO
$1.20 -
$1.30
$0.50 -
$0.60
$0.40 -
$0.50
$0.10 -
$0.20
$0.25 -
$0.35
2016 Standalone Guidance
2016 Combined Guidance
9
Q1
2016
Earnings Release
Slides
(1)
2016 standalone earnings guidance was based on expected average outstanding shares of 890M and assumed that equity and debt issued for Pepco Holdings acquisition was unwound in
2016.  Earnings guidance for OpCos may not add up to consolidated EPS guidance. Refer to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.
(2)
2016 combined earnings guidance is based on expected average outstanding shares of 926M.  Earnings guidance for OpCos may not add up to consolidated EPS guidance.
(3)
ComEd ROE based on 30 Year average Treasury yield of 2.67% as of 3/31/16.  25 basis point move in 30 Year Treasury Rate equates to +/-$0.01 impact to EPS.

Reaffirming Legacy Exelon Utilities Net Income Outlook
(1)
Numbers rounded to nearest $25M
(2)
Does not include PHI net income and represents adjusted (non-GAAP) operating earnings.  Refer to slide 41 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating earnings.
Exelon Utilities Net Income ($M)
(1,2)
$1,400
$1,300
$1,200
$1,100
$0
2018
$1,400
2017
$1,325
2016
$1,250
$1,250
$1,175
$1,100
Legacy Exelon Utilities projected average earnings growth is still in the 7-9% range per year
from 2015-2018
10
Q1
2016
Earnings Release
Slides

Q4 2015
Q1 2016
Q2 2016
Q3 2016
BGE Electric
and Gas
Distribution
Rates 
ACE Electric
Distribution
Rates
ComEd Electric
Distribution
Formula Rate
Q4 2016
Pepco Electric
Distribution
Rates -
DC
Delmarva
Electric and Gas
Distribution
Rates -
DE
Delmarva
Electric
Distribution
Rates -
MD
Pepco Electric
Distribution
Rates -
MD
MD Rate
Case Filed
November
6
Final Order
Expected
June
NJ Rate
Case Filed
March 22
Q1 2017
IL Formula
Rate Case
Filed April
13
Final Order
Expected
December
MD Rate
Case Filed
April 19
Final Order
Expected
December
DC Rate
Case Filing
Planned
Q2/Q3
DE Rate
Case Filing
Planned
Final Order
Expected
MD Rate
Case Filing
Planned
Final Order
Expected
Exelon Utilities Distribution Rate Case Schedule
11
Q1
2016
Earnings
Release
Slides
Final Order
Expected
Q1/Q2

12
Q1 2016  Earnings Release Slides
Exelon Generation: Gross Margin Update
•
Executed $200M of Power New Business and $100M of Non-Power New Business in Q1
•
Behind ratable hedging position reflects the fundamental upside we see in power prices
•
Generation ~28-31% open in 2017
•
Power position ~5-8% behind ratable, considering cross-commodity hedges
Recent Developments
Gross Margin Category ($M)
(1)
2016
2017
2018
2016
2017
2018
Open Gross Margin
(3)
(including South, West, Canada hedged gross
margin)
$4,450
$5,350
$5,800
$(750)
$(450)
$(350)
Mark-to-Market of Hedges
(3,4)
$2,650
$1,150
$400
$950
$350
$150
Power New Business / To Go
$250
$750
$1,000
$(200)
$(50)
-
Non-Power Margins Executed
$350
$150
$100
$100
-
-
Non-Power New Business / To Go
$100
$300
$400
$(100)
-
-
Total Gross Margin
(2)
$7,800
$7,700
$7,700
-
$(150)
$(200)
March 31, 2016
Change from Dec. 31, 2015
Gross margin categories rounded to nearest $50M
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.  Excludes Pepco Energy Services.  See Slide 26 for a Non-GAAP to GAAP
reconciliation of Total Gross Margin. 
Excludes EDF’s equity ownership share of the CENG Joint Venture
Mark-to-Market of Hedges assumes mid-point of hedge percentages
(1)
(2)
(3)
(4)

13
Q1 2016  Earnings Release Slides
Incremental Combined Company Tax Impacts
(1)
Financial Developments Since Q4 2015
•
ExGen
earnings are lower as increased cash tax
benefits reduce the Domestic Production
Activities Deduction (DPAD) in 2018 but should
normalize in 2019
•
PHI increases cash flow by $700M-$850M for
2017-19 due to bonus depreciation and legacy
NOLs
•
Consolidated tax rate increases by as much as
200 bps through 2018 due to lower DPAD, but is
expected to normalize to ~32% in 2019
(1)
Tax impacts are incremental to the standalone bonus depreciation impacts disclosed on the Q4 2015 earnings call for earnings in 2016: ($0.09), 2017: ($0.11), and 2018: ($0.06); and for cash
in 2016: $625M, 2017: $675M, and 2018: $600M
(2)
ComEd ROE based on 30 Year average Treasury yield of 2.67% as of 3/31/16
ComEd ROE Sensitivity to Interest Rates
(2)
•
ComEd allowed ROEs are calculated at the 30-
Year Treasury + 580 bps with every 25 bps move
in the 30-Year impacting EPS by +/-
$0.01
2017
2018
2019
EPS
$(0.00) - $(0.02)
$(0.06) - $(0.08)
$(0.00) - $(0.01)
Cash Flow
$50M-$100M
$200M-$300M
$400M-$500M
Consolidated
Tax Rate
33%
34%
32%
Cash Tax
Rate
5%
5%
10%
2017
2018
2019
ComEd EPS - 30 Year Treasury Rate
+25 basis points
$0.01
$0.01
$0.01
-25 basis points
$(0.01)
$(0.01)
$(0.01)

14
Q1 2016  Earnings Release Slides
Delivering Value to Shareholders Through a Defined Capital
Allocation Policy
•
Our strong balance sheet underpins our capital allocation policy
•
Capital decisions are 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
•
We
are
committed
to
maintaining
an
attractive
dividend
(1)
,
increasing
the dividend by 2.5% annually through 2018
(1) Quarterly dividends are subject to declaration by the board of directors

15
Q1 2016  Earnings Release Slides
Quarter over Quarter Disclosures

16
Q1 2016  Earnings Release Slides
Exelon Utilities Adjusted Operating EPS Contribution
(1)
Key Drivers –
1Q16
(2)
vs. 1Q15
:
BGE
(-0.01):
•
Increased storm costs: ($0.01)
PECO
(-0.02):
•
Unfavorable weather (RNF): $(0.04)
•
Increased electric distribution rates: $0.02
ComEd
(+0.01):
•
Unfavorable weather
(3)
: $(0.01)
•
Increased distribution and transmission earnings due to
increased capital investment
(3)
: $0.02
PHI
(+0.00):
•
PHI actual results from the period of March 24, 2016 to March
31, 2016 were not a significant driver: $(0.00)
1Q 2016
$0.00
$0.37
$0.12
$0.11
$0.14
$0.11
1Q 2015
$0.39
$0.16
$0.12
PHI
ComEd
BGE
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)
There is a $(0.02) share differential impact spread across the utilities in Q1 2016.
(3)
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.

17
Q1 2016  Earnings Release Slides
ExGen Adjusted Operating EPS Contribution
(1)
$0.34
Q1
$0.35
2016
2015
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)
Q1
2015 Actual
Q1
2016
Actual
Planned Refueling Outage
Days
89
70
Non-refueling Outage Days
32
10
Nuclear Capacity Factor
92.7%
95.8%
Key Drivers –
Q1 2016 vs. Q1 2015
ExGen
(-0.01)
•
Unfavorable RNF primarily due to lower realized energy prices in
the Midwest, New York, and New England regions, partially offset
by nuclear refueling outage timing, fewer non-refueling outage
days, and increased capacity pricing: $(0.02)
•
Higher depreciation costs primarily due to increased nuclear
decommissioning amortization and ongoing capital expenditures:
$(0.02)
•
Other: $0.03

18
Q1 2016  Earnings Release Slides
Exelon Generation Disclosures
March 31, 2016

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
19
Q1 2016  Earnings Release Slides

20
Q1 2016  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
•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 regions 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

21
Q1 2016  Earnings Release Slides
ExGen Disclosures 
(1)
Gross margin categories rounded to nearest $50M    
(2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power
and fuel expense, excluding revenue related to decommissioning, gross receipts tax,
Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable
interest entities. Total Gross Margin is also net of direct cost of sales for certain
Constellation businesses. Excludes Pepco Energy Services. See Slide 26 for a Non-GAAP
to GAAP reconciliation of Total Gross Margin.
(3)
Excludes EDF’s equity ownership share of the CENG Joint Venture
(4)
Mark-to-Market of Hedges assumes mid-point of hedge percentages
(5)
Based on March 31, 2016 market conditions
Gross Margin Category ($M)
(1)
2016
2017
2018
Open Gross Margin
(including South, West & Canada hedged GM)
(3)
$4,450
$5,350
$5,800
Mark-to-Market of Hedges
(3,4)
$2,650
$1,150
$400
Power New Business / To Go
$250
$750
$1,000
Non-Power Margins Executed
$350
$150
$100
Non-Power New Business / To Go
$100
$300
$400
Total Gross Margin
(2)
$7,800
$7,700
$7,700
Reference Prices
(5)
2016
2017
2018
Henry Hub Natural Gas ($/MMbtu)
$2.19
$2.77
$2.87
Midwest: NiHub ATC prices ($/MWh)
$24.00
$27.10
$27.26
Mid-Atlantic: PJM-W ATC prices ($/MWh)
$29.31
$33.59
$32.52
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$4.57
$4.28
$4.39
New York: NY Zone A ($/MWh)
$26.25
$33.23
$32.66
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$6.65
$8.65
$9.28

22
Q1 2016  Earnings Release Slides
ExGen Disclosures
Generation and Hedges
2016
2017
2018
Exp. Gen (GWh)
(1)
200,100
205,400
206,600
Midwest
97,700
96,300
96,700
Mid-Atlantic
(2)
63,300
61,300
60,600
ERCOT
17,200
26,000
30,800
New York
(2)
9,300
9,200
9,100
New England
12,600
12,600
9,400
% of Expected Generation Hedged
(3)
96%-99%
69%-72%
37%-40%
Midwest
92%-95%
65%-68%
31%-34%
Mid-Atlantic
(2)
105%-108%
77%-80%
45%-48%
ERCOT
95%-98%
73%-76%
39%-42%
New York
(2)
91%-94%
64%-67%
52%-55%
New England
79%-82%
53%-56%
24%-27%
Effective Realized Energy Price ($/MWh)
(4)
Midwest
$34.00
$33.00
$31.50
Mid-Atlantic
(2)
$45.50
$45.00
$41.00
ERCOT
(5)
$11.50
$7.50
$4.00
New York
(2)
$61.00
$50.50
$42.50
New England
(5)
$27.50
$18.00
$9.50
(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%, 93.4% and 93.7% in 2016,
2017 and 2018 respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 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.

23
Q1 2016  Earnings Release Slides
ExGen Hedged Gross Margin Sensitivities
Gross Margin Sensitivities (With Existing Hedges)
(1)
2016
2017
2018
Henry Hub Natural Gas ($/Mmbtu)
+ $1/Mmbtu
$20
$270
$570
- $1/Mmbtu
$60
$(300)
$(580)
NiHub ATC Energy Price
+ $5/MWh
$35
$185
$350
- $5/MWh
$(30)
$(180)
$(345)
PJM-W ATC Energy Price
+ $5/MWh
$(15)
$65
$160
- $5/MWh
$20
$(80)
$(165)
NYPP Zone A ATC Energy Price
+ $5/MWh
-  
$15
$20
- $5/MWh
-  
$(15)
$(20)
Nuclear Capacity Factor
+/- 1%
+/- $25
+/- $35
+/- $35
(1)
Based on March 31, 2016 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

24
Q1 2016  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
2016
2017
2018
$9,150
$6,550
$7,950
$7,650
$8,350
$7,100
(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 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 March 31, 2016
(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
Pepco Energy Services. See Slide 26 for a Non-GAAP to GAAP reconciliation of Total Gross Margin. Excludes EDF’s equity ownership share of the CENG Joint Venture.

25
Q1 2016  Earnings Release Slides
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)
96.3
61.3
26.0
9.2
12.6
(C)
Hedge % (assuming mid-point of range)
66.5%
78.5%
74.5%
65.5%
54.5%
(D=B*C)
Hedged Volume (TWh)
64.0
48.1
19.4
6.0
6.9
(E)
Effective Realized Energy Price ($/MWh)
$33.00
$45.00
$7.50
$50.50
$18.00
(F)
Reference Price ($/MWh)
$27.10
$33.59
$4.28
$33.23
$8.65
(G=E-F)
Difference ($/MWh)
$5.90
$11.41
$3.22
$17.27
$9.35
(H=D*G)
Mark-to-market value of hedges  ($ million)
(1)
$380
$550
$60
$105
$65
(I=A+H)
Hedged Gross Margin ($ 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)
$150
$300
$7,700 million
$5.35 billion
$6,500
$750
Illustrative Example of Modeling Exelon Generation                  
2017 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. Excludes
Pepco Energy Services. See Slide 26 for a Non-GAAP to GAAP reconciliation of Total Gross Margin.

Additional ExGen
Modeling Data
Total
Gross Margin Reconciliation (in $M)
2016
2017
2018
Revenue Net of Purchased Power and Fuel Expense
(2)(3)
$8,425
$8,325
$8,325
Other Revenues
(4)
$(325)
$(325)
$(325)
Direct cost of sales incurred to generate revenues for certain
Constellation businesses
(5)
$(300)
$(300)
$(300)
Total Gross Margin (Non-GAAP, as shown on slide 11)
$7,800
$7,700
$7,700
Key ExGen
Modeling Inputs (in $M)
2016
Other Revenues (excluding Gross Receipts Tax)
(4)
$200
O&M
(7)
$(4,475)
Taxes Other Than Income (TOTI)
(8)
$(350)
Depreciation & Amortization
(9)
$(1,075)
Interest Expense
$(375)
Effective Tax Rate
34.0%
(1)
All amounts rounded to the nearest $25M. Excludes Pepco Energy Services.
(2)
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.
(3)
Excludes the mark-to-market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices.
(4)
Other revenues 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.  
(5)
Reflects the cost of sales and depreciation expense of certain Constellation businesses of Generation. Excludes Pepco Energy Services.
(6)
ExGen amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture. 
(7)
ExGen adjusted O&M excludes direct cost of sales for certain Constellation business, P&L neutral decommissioning costs and the impact from O&M related to variable interest entities.
Refer to the Appendix for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M
(8)
TOTI excludes gross receipts tax of $125M
(9)
Depreciation & Amortization excludes the cost of sales impact of ExGen’s non-power businesses of $25M
26
Q1
2016
Earnings Release
Slides
(1)
(1)(6)

27
Q1 2016  Earnings Release Slides
Illinois Nuclear Plant Details
Capacity
1,069 MW
Capacity
1,403 MW
Generation Output
(2)
8,700 GWh
Generation Output
(2)
11,700 GWh
Start of Operations
1987
Start of Operations
1973
License Expiration
2026
License Expiration
2032
Refueling Cycle
12 month
Refueling Cycle (per unit)
24 month
Commited to Run Through
May 31, 2017
Commited to Run Through
May 31, 2018
Employees
~700
Employees
~800
Clinton
Quad Cities
(1)
(1)
Capacity and generation output reflect proportionate ownership share
(2)
2015 actuals

28
Q1 2016  Earnings Release Slides
Additional Disclosures

29
Q1 2016  Earnings Release Slides
Exelon Utilities Overview
Operating Statistics
Commonwealth Edison
Potomac Electric Power
Customers:
Service
Territory:
Peak Load:
2015 Rate
Base:
3,800,000
11,400
sq.
miles
23,753 MW
$10.6 bn
Customers:
Service
Territory:
Peak Load:
2015 Rate Base:
842,000
640 sq. miles
7,023 MW
$3.9 bn
PECO Energy
Atlantic City Electric
Customers:
Service
Territory:
Peak Load:
2015 Rate
Base:
2,100,000
2,100 sq.
miles
8,983 MW
$6.0 bn
Customers:
Service
Territory:
Peak Load:
2015 Rate Base:
547,000
2,700 sq. miles
3,009
MW
$1.8 bn
Baltimore Gas and Electric
Delmarva Power & Light
Customers:
Service
Territory:
Peak Load:
2015 Rate
Base:
1,900,000
2,300 sq. miles
7,236 MW
$5.0 bn
Customers:
Service
Territory:
Peak Load:
2015 Rate Base:
645,000
5,000 sq. miles
4,288 MW
$2.4 bn
Combined Service Territory
Potomac Electric Power Service Territory
Atlantic City Electric Service Territory
Delmarva Power & Light Service Territory
Baltimore Gas and Electric Service Territory
PECO Energy Service Territory
ComEd Service Territory
IL
Chicago
DE
MD
PA
NJ
VA
Philadelphia
Baltimore
Dover
Wilmington
Trenton
Washington, DC

2015 Earned vs. Allowed ROE at PHI Utilities
ACE -
NJ
DPL -
DE -
Gas
9.75%*
DPL -
MD
9.81%*
DPL -
DE
-
Electric
Pepco -
DC
Pepco -
MD
2015 Estimated Earned ROE
2015 Allowed ROE
Significant Opportunity for Earned ROE Improvement at PHI Utilities
*  ROE for purposes of calculating AFUDC and regulatory asset carrying costs.
30
Q1
2016
Earnings Release
Slides
4.79%
7.00%
6.98%
4.77%
7.36%
6.62%
9.75%
9.70%
9.40%
9.62%
0
1
2
3
4
5
6
7
8
9
10

31
Q1 2016  Earnings Release Slides
BGE
Exelon Utilities Load
PECO
Large C&I
Small C&I
Residential
All Customers
ComEd
2016E
2015
2016 load is driven by impacts
of energy efficiency partially
offset by slowly improving
economy
Chicago GMP
1.5%
Chicago Unemployment
6.3%
2016 load growth is driven by
the impacts of energy
efficiency and a weaker
economic outlook , partially
offset by moderate customer
growth
Notes: Data is weather normalized and not adjusted for leap year.  Source of economic outlook data is IHS (March 2016).  Assumes 2016 GDP of 2.3% and U.S. unemployment of 5.0%.
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.
2016 load growth is driven by
slowly improving economic
conditions coupled with solid
residential customer growth,
partially offset by energy
efficiency
Philadelphia GMP
2.1%
Philadelphia
Unemployment
4.5%
2016E
2015
2015
2016E
Baltimore GMP
1.1%
Baltimore Unemployment
5.0%
(0.2%)
(1.4%)
(1.0%)
(1.5%)
(0.9%)
0.3%
(2.0%)
0.0%
0.4%
(0.1%)
0.6%
0.3%
0.6%
0.6%
0.2%
(0.5%)
0.1%
0.7%
-0.1%
1.0%
0.4%
0.7%
0.2%
0.5%

32
Q1 2016  Earnings Release Slides
Pepco
Exelon Utilities Load (cont’d)
Delmarva
C&I
Residential
All Customers
ACE
2016E
2015
2016E
2015
2016E
2015
2016 load is driven by the impacts
of energy efficiency and distributed
energy partially offset by improving
residential and commercial
customer growth.
ACE GMP
0.3%
ACE Unemployment
7.3%
DPL GMP
2.2%
DPL Unemployment
4.8%
Pepco GMP
2.2%
Pepco
Unemployment
5.3%
(2.2%)
(0.4%)
(2.6%)
2.1%
(1.9%)
(2.5%)
(0.3%)
0.0%
(0.9%)
2.2%
0.2%
(1.6%)
(0.7%)
0.2%
(3.3%)
6.7%
0.6%
(2.7%)
2016 load is driven by the impacts
of energy efficiency and distributed
energy partially offset by improved
employment and residential,
commercial & industrial customer
growth.
2016 load is driven by the impacts
of energy efficiency and distributed
energy partially offset by improved
commercial usage and residential
customer growth.
Notes: Data is weather normalized using 20-year historical average and not adjusted for leap year.  Starting with 2Q16, PHI will be moving to 30-year historical average for weather
normalization.  Source of economic outlook data is IHS (March 2016).  Assumes 2016 GDP of 2.3% and U.S. unemployment rate of 5.0%.  Pepco and DPL MD are decoupled which mitigates
the load risk. QTD and YTD actual data can be found in earnings release tables.  ACE includes Atlantic City, Vineland and Ocean City MSAs (Metropolitan Statistical Area). DPL MSA includes
Wilmington Division, Dover MSA and Salisbury MSA.  Pepco MSA includes the city of Washington DC and Silver Spring/Frederick Division.

33
Q1 2016  Earnings Release Slides
PHI Jurisdiction Comparison
Rate Cases
District of Columbia
Maryland
Delaware
New Jersey
Partially Forecasted
Test Year
Yes
(1)
Yes
Yes
Yes
Required to update test
year to actual
No
Yes
No
Yes
Timing for Rate
Implementation
No statute; target to complete
cases within 9 months of filing
Statute - 7 months; rates
automatically go into effect
subject to refund
Statute - 7 months; company
files request to implement
rates, subject to refund
Statute - 9 months; company
files request to implement
rates, subject to refund
(2)
Time Restrictions on
Initiating Subsequent
Rate Filings
No
No
No
No
Staff Party to Case
No
Yes
Yes
Yes
Commissions
Full Time/Part Time
Full-Time
Full-Time
Part-Time
Full-Time
Appointed/Elected
Appointed
Appointed
Appointed
Appointed
Length of Term
4 years
5 years
5 years
6 years
Commissioners
(3)
Name (Term Expiration)
Betty Ann Kane (2018)
Kevin Hughes (2018)
Dallas Winslow (2020)
Richard S. Mroz (2021)
Joanne Doddy Fort (2016)
Harold Williams (2017)
Joann Conaway (2020)
Diane Solomon (2018)
Willie L. Phillips (2018)
Anne Hoskins (2016)
Harold Gray (2020)
Joseph L. Fiordaliso (2019)
Jeannette M. Mills (2019)
Kim Drexler (2020)
Mary-Anna Holden (2017)
Michael  T. Richard (2020)
Manubhai Karia (2020)
Upendra J. Chivukula (2019)
(1)
The District of Columbia PSC allows rates to be developed using a partially forecasted test period.  The Company is required to update the test period to actual within 180 days of the
completion of the rate proceeding
(2)
The statutory deadline for NJBPU decisions has not been successfully enforced by a utility; fully litigated cases can take 12 months or more for decision
(3)
Chairperson denoted in bold

34
Q1 2016  Earnings Release Slides
Electric
Gas
Docket #
9406
Test Year
December 2014-
November  2015
Common Equity Ratio
(1)
53.7%
Requested ROE
10.60%
10.50%
Requested Rate of Return
7.95%
7.90%
Rate Base (adjusted)
$3.0B
$1.2B
Revenue Requirement Increase
(1)
$117.6M
$79.1M
Proposed
Distribution Increase as %
of overall bill
~3%
~9%
Notes
•
11/06/15 BGE
filed application with the MDPSC seeking increases in electric & gas distribution
base rates; request was subsequently revised in Q1 to reflect impact of additional actual data
•
$141M or ~72% of the total $197M distribution rate increase is for recovery of Smart Grid
investment
•
Requested incremental conduit fees of $31M be recovered through a rider
•
210 Day Proceeding
•
June 2016 -
PSC order expected
•
New rates are in effect
shortly after the final order
(1)  Based on the 12 months ended 11/30/2015.
BGE Electric and Gas Distribution Rate Case

35
Q1 2016  Earnings Release Slides
ComEd April 2016 Distribution Formula Rate
Docket #
16-0259
Filing Year
2015
Calendar
Year
Actual
Costs
and
2016
Projected
Net
Plant
Additions
are
used
to
set
the
rates
for
calendar
year
2017.  Rates currently in effect (docket 15-0287) for calendar year 2016 were based on 2014 actual costs and 2015
projected net plant additions
Reconciliation Year
Reconciles
Revenue
Requirement
reflected
in
rates
during
2015
to
2015
Actual
Costs
Incurred.
Revenue
requirement
for 2015 is based on docket 14-0312 (2013 actual costs and 2014 projected net plant additions) approved in December
2014.
Common Equity Ratio
~ 46%
for
both
the
filing
and
reconciliation
year
ROE
8.64% for the filing year (2015 30-yr Treasury Yield of 2.84% + 580 basis point risk premium) and 8.59% for the
reconciliation
year
(2015
30-yr
Treasury
Yield
of
2.79%
+
580
basis
point
risk
premium
–
5
basis
points
performance
metrics penalty).  For 2016 and 2017, 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
$8,830 million–
Filing year (represents projected year-end rate base using 2015 actual plus 2016 projected capital
additions).  2016 and 2017 earnings will reflect 2016 and 2017 year-end rate base respectively.
$7,780 million -
Reconciliation year (represents year-end rate base for 2015)
Revenue Requirement
Increase
$138M increase ($1M decrease due to the 2015 reconciliation and collar adjustment offset by a $139M increase related
to the filing year).  The 2015 reconciliation impact on net income was recorded in 2015 as a regulatory asset.
Timeline
•
04/13/16 Filing Date
•
240 Day Proceeding
The 2016 distribution formula rate filing established the net revenue requirement used to set the rates that will take effect in January 2017 after the
Illinois Commerce Commission's (ICC’s) review. There are two components to the annual distribution formula rate filing:
•
Filing Year: Based on 2015 costs and 2016 projected plant additions. 
•
Annual Reconciliation: For 2015, this amount reconciles the revenue requirement reflected in rates in effect during 2015 to the actual costs for
that year. The annual reconciliation impacts cash flow in 2017 but the earnings impact has been recorded in 2015 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.

36
Q1 2016  Earnings Release Slides
ACE Electric Distribution Rate Case
Docket #
ER16030252
Test Year
2015 Calendar Year
Test Period
Partially Forecasted Test Period (9 months actual & 3 months forecasted)
Requested
Common Equity Ratio
49.5%
Requested Rate of Return
ROE: 10.60%;    ROR:
8.06%
Proposed Rate Base
$1.4B
Requested
Revenue Requirement Increase
$84.4M
Residential Total Bill % Increase
6.3%
Notes
•
3/22/16 ACE filed application with the NJBPU seeking increase in electric
distribution base rates
•
12 month forward looking reliability and other plant additions from January 2016
through December 2016 ($15.2M of revenue) included in revenue requirement
request
•
PowerAhead
Program to fund accelerated investments in grid resiliency,
incremental to the five year capital plan (not included in revenue requirement
request):  Capital $176 million (Distribution Line Hardening $108 million; Storm
Response $35 million; and Other Programs $33 million)
•
9 month statutory deadline for NJBPU decisions has not been successfully enforced
by a utility; fully litigated cases can take 12 months or more for decision
•
NJBPU order expected first half of 2017

37
Q1 2016  Earnings Release Slides
Pepco MD Electric Distribution Rate Case
Docket #
9418
Test Year
2015 Calendar Year
Test Period
Partially Forecasted Test Period (9 months actual & 3 months forecasted)
Requested
Common Equity Ratio
49.6%
Requested Rate of Return
ROE: 10.60%;    ROR:
8.01%
Proposed Rate Base
$1.8B
Requested
Revenue Requirement Increase
$126.8M
Residential Total Bill % Increase
10.4%
Notes
•
4/19/16 Pepco MD
filed application with the MDPSC seeking increase in
electric distribution base rates
•
Size of ask is driven by 2 years of capital investment, recovery of AMI
investments and new depreciation rates.
•
12 month forward looking reliability and other plant additions from January
2016 through December 2016 ($20.7M of revenue); included in revenue
requirement request
•
Extension of the Grid Resiliency Program to fund accelerated investments in
grid resiliency, incremental to the capital plan (not included in revenue
requirement request)
•
Capital $31.6 million (Feeder Work $24.0 million and Reclosing
Devices $7.6 million) in 2017-2018
•
7 Month Proceeding
•
Q42016
-
PSC order expected
•
New rates are in effect
shortly after the final order

38
Q1 2016  Earnings Release Slides
Appendix
Reconciliation of Non-GAAP
Measures

39
Q1 2016  Earnings Release Slides
1Q 2015 YTD GAAP EPS Reconciliation
Three Months Ended March 31, 2015
ExGen
ComEd
PECO
BGE
Other
Exelon
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.35
$0.11
$0.16
$0.12
$(0.03)
$0.71
Mark-to-market impact of economic hedging activities
(0.11)
-
-
-
-
(0.11)
Unrealized gains related to NDT fund investments
0.03
-
-
-
-
0.03
Merger and integration costs
(0.01)
-
-
-
(0.01)
(0.02)
Mark-to-market impact of PHI merger related interest swaps
-
-
-
-
(0.06)
(0.06)
Amortization of commodity contract intangibles
0.03
-
-
-
-
0.03
Midwest Generation bankruptcy recoveries
0.01
-
-
-
-
0.01
CENG non-controlling interest
(0.01)
-
-
-
-
(0.01)
1Q 2015 GAAP Earnings Per Share
$0.51
$0.11
$0.16
$0.12
($0.10)
$0.80
NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

40
Q1 2016  Earnings Release Slides
1Q 2016 YTD GAAP EPS Reconciliation (continued)
Three Months Ended March 31, 2016
ExGen
ComEd
PECO
BGE
PHI
Other
Exelon
2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per
Share
$0.34
$0.12
$0.14
$0.11
$0.00
$(0.02)
$0.68
Mark-to-market impact of economic hedging activities
0.07
-
-
-
-
-
0.07
Unrealized gains related to NDT fund investments
0.03
-
-
-
-
-
0.03
Amortization of commodity contract intangibles
0.01
-
-
-
-
-
0.01
Merger and integration costs
(0.01)
0.01
-
-
(0.04)
(0.05)
(0.08)
Merger commitments
-
-
-
-
(0.30)
(0.12)
(0.42)
Long-lived asset impairment
(0.07)
-
-
-
-
-
(0.07)
Reassessment of state deferred income taxes
(0.01)
-
-
-
-
0.01
-
Cost management program
(0.01)
-
-
-
-
-
(0.02)
CENG non-controlling interest
(0.01)
-
-
-
-
-
(0.01)
1Q 2016 GAAP Earnings (Loss) Per Share
$0.34
$0.13
$0.14
$0.11
$(0.34)
$(0.18)
$0.19
NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

41
Q1 2016  Earnings Release Slides
GAAP to Operating Adjustments
•
Exelon’s Q1 2016 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
–
Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at
the
date
of
acquisition
of
Integrys
in
2014
–
Certain costs incurred associated with PHI acquisition
–
Merger commitments related to settlement of PHI acquisition
–
Impairment of certain upstream assets
–
Non-cash
impact
of
the
remeasurement
of
state
deferred
income
taxes,
primarily
as
a
result
of
PHI
acquisition
–
Costs incurred related to cost management initiatives
–
Generation’s non-controlling interest related to CENG exclusion items
–
Other unusual items

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