EXELON CORP - FORM 8-K - EX-99.2 - EARNINGS CONFERENCE CALL PRESENTATION SLIDES - February 3, 2016

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EX-99.1 - PRESS RELEASE AND EARNINGS RELEASE ATTACHMENTS - EXELON CORPd125923dex991.htm
8-K - FORM 8-K - EXELON CORPd125923d8k.htm
Earnings Conference Call
4
th
Quarter 2015
February 3, 2016
Exhibit 99.2

2
Q4 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 include those factors discussed herein, as
well as the items discussed in (1)  Exelon’s 2014 Annual Report on Form 10-K in (a)
ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations and (c) ITEM 8. Financial Statements and
Supplementary Data: Note 22; (2) Exelon’s Third Quarter 2015 Quarterly Report on
Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial
Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and
Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial
Statements: Note 19; and (3) other factors discussed in filings with the SEC by Exelon.
Readers are cautioned not to place undue reliance on these forward-looking
statements, which apply only as of the date of this presentation. Exelon does not
undertake any obligation to publicly release any revision to its forward-looking
statements to reflect events or circumstances after the date of this presentation.

3
Q4 2015  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
•
Our board has approved a policy to raise our dividend 2.5% each year
for
the
next
three
years,
beginning
with
the
June
2016
dividend
(1)
(1) Quarterly dividends are subject to declaration by the board of directors.

4
Q4 2015  Earnings Release Slides
•
1
st
Quartile SAIFI performance
•
1
st
Quartile CAIDI performance
•
1
st
Quartile Customer Satisfaction –
best ever scores at ComEd and BGE
Strong
Financial
Performance
Leading
Operational
Excellence
Positive
Regulatory
Outcomes
•
1
st
Quartile SAIFI performance
•
1
st
Quartile CAIDI performance
•
1
st
Quartile Customer Satisfaction
•
Improve PHI operational performance
•
Unanimous approval of PECO’s rate
case settlement and Long Term
Infrastructure Improvement Plan
•
4
th
year of constructive outcomes in
ComEd’s
formula rate filings
•
Close PHI transaction
•
BGE rate case decision in June
•
ComEd formula rate filing in April
•
Develop and implement regulatory
strategies for PHI
Exelon Utilities –
Operational Excellence Driving Strong
Financial Performance and Positive Regulatory Outcomes
2015 Results
2016 Goals
•
Exceeded $1B in operating net income
•
Invested $3.7B to make the grid
smarter, more reliable, and provide
better services to customers
•
Quickly integrate PHI to drive synergies
and financial results
•
Invest $3.95B in capital across our
three utilities and additional $1.38B at
PHI ($18B over the next 5 years, $25B
including PHI)
•
Improve system infrastructure
•
Better customer experience

5
Q4 2015  Earnings Release Slides
World Class Operational Performance
2016 Goals
Industry Leading Load Serving Business
•
Full-year Nuclear Capacity Factor: 93.7%
•
Best average refueling outage duration since
2002: 22 days
•
Full-year Power dispatch match: 98.6%
•
Full-year Renewables energy capture: 95.5%
•
Generation to Load matching strategy
meaningfully contributed to 2015 earnings
•
Industry Leading Load Serving Business:
•
Served 195 TWhs
of wholesale and retail
load –
40 TWhs
more than in 2014
•
~ 80% power renewal rate
•
~30% new customer win rate
•
Increased our delivered retail gas by 40%
to 710 BCF
•
>90% gas retention rate
•
Continue to be best in class in operational
performance across the generation fleet
•
Execute on 350MW of contracted renewable
projects (Michigan Wind 3 & Bluestem Wind)
•
Achieve target of serving 210 TWhs
of wholesale
and retail load
•
Achieve proper valuation for our nuclear
generation assets that rewards their carbon free
footprint
210
180
155
195
155
2016
2015
(1)
2014
Target
Actual
Delivering on electric load serving targets and
poised to continue growth
Exelon
Generation
Delivered
Strong
Operational
and
Financial
Performance in 2015
(1) 2015 target includes 15 TWhs from the Integrys  acquisition
(TWhs)

6
Q4 2015  Earnings Release Slides
($0.13)
$1.40
$0.48
$0.43
$0.31
PECO
ExGen
ComEd
BGE
HoldCo
ExGen
ComEd
PECO
BGE
2016 Guidance
$2.40 -
$2.70
(2)
~($0.05)
$1.25 -
$1.35
$0.50 -
$0.60
$0.40 -
$0.50
$0.25 -
$0.35
2015 Actual
$2.49
(1)
HoldCo
2016 Adjusted Operating Earnings Guidance
Expect
Q1
2016
Adjusted
Operating
Earnings
of
$0.60
-
$0.70
per
share
Key Year-Over-Year Drivers
•
BGE: higher O&M for storms
and bad debt, partially offset
by higher distribution rates
•
PECO:  higher distribution
rates, partially offset by
higher O&M for storms and
bad debt
•
ComEd: increased capital
investments in distribution
and transmission
•
ExGen: normalized load
optimization in 2016
(1)
2015 results based on 2015 average outstanding shares of 893M. Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-
GAAP) operating EPS to GAAP EPS.
(2)
2016 earnings guidance based on expected average outstanding shares of 890M and assumes that equity and debt issued for Pepco Holdings acquisition is 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.

7
Q4 2015  Earnings Release Slides
Key Financial Metrics Impacted by Bonus Depreciation
2016
11.8
2018
13.6
2017
12.8
Distribution
Transmission
Standalone Bonus Depreciation Impacts
Updated
Exelon
Utilities
Net
Income
($M)
(3)
Updated
ComEd
Rate
Base
($B)
(4)
$1,400
$1,300
$0
$1,200
$1,100
$1,325
2016
$1,250
2018
$1,400
2017
$1,250
$1,175
$1,100
2016
2017
2018
Earnings per
Share
(1)
($0.09)
($0.11)
($0.06)
Cash Flow
(2)
$625M
$675M
$600M
•
Bonus Depreciation reduces earnings in 2016-2018
primarily due to its impact on ExGen’s ability to take
the Domestic Production Activities Deduction and
impacts to ComEd’s rate base
•
No re-investment of the incremental cash is
contemplated in the earnings impacts listed
Exelon Utilities projected average earnings growth is
still in the 7-9% range per year from 2015-2018
Exelon Utilities Rate Base growing by $5.5B, more
than 25% from 2015 to 2018, despite impact of
bonus depreciation
8.6
9.3
10.0
3.2
3.5
3.6
(1)
2016: ExGen ($0.06), ComEd ($0.03); 2017: ExGen ($0.07), ComEd ($0.04); 2018: ComEd ($0.05), BGE ($0.01), PECO ($0.01), ExGen $0.01
(2)
Numbers rounded to nearest $25M
(3)
Does not include PHI net income and represents adjusted (non-GAAP) operating earnings.  Refer to slide 38 for a list of adjustments from GAAP EPS to adjusted (non-GAAP)
operating earnings.
(4)
Rate base represents end-of-year.  Numbers may not add due to rounding

8
Q4 2015  Earnings Release Slides
Maintaining Investment Grade Credit Ratings is a Top
Financial Priority
Current
Ratings
(2)(3)
ExCorp
ComEd
PECO
BGE
ExGen
Moody’s
Baa2
A2
Aa3
A3
Baa2
S&P
BBB-
A-
A-
A-
BBB
Fitch
BBB+
A-
A
A-
BBB
ExGen
Debt/EBITDA Ratio
(5)
Exelon and ExGen
S&P FFO/Debt %
(1)
•
Key credit metrics expected to remain above
target after including PHI
(4)
Credit Ratings by Operating Company
ExGen
Free Cash Flow 2016-2018 ($M)
(6)
~$3,200
~$5,350
($1,350)
Committed
Non-Contracted
Generation
Growth CapEx
($800)
Cumulative ExGen
FCF 2016-18
Available Free
Cash Flow
Committed
Contracted
Generation
Growth CapEx
3.2x
3.0x
2.3x
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
2018
2017
2016
~$4,150
EEI
Disclosure
~$2,700
EEI
Disclosure
0%
10%
20%
30%
40%
50%
2016
2017
2018
Exelon Target (22%)
Exelon
ExGen
ExGen Target (27%)
(1)
Metrics exclude PHI and financing associated with PHI. Due to ring-fencing, S&P deconsolidates BGE's financial profile from Exelon and analyzes it  solely as an equity investment
(2)
Current senior unsecured ratings as of 2/2/2016 for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd and PECO
(3)
All ratings have “Stable” outlook, except for at Fitch, which has ComEd on “Positive” and Exelon on “Ratings Watch Negative,” and Moody’s, which has ComEd on “Positive” outlook
(4)
Exelon Consolidated and ExGen thresholds based on the S&P Exelon Corp and ExGen Summary Reports published on August 5, 2015.  On a combined basis with PHI, the consolidated threshold is 18%
(5)
Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA. EBITDA, a non-GAAP measure, is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel
amortization expense.
(6)
Free Cash Flow = Adjusted Cash Flow from Operations less Base CapEx and Nuclear Fuel.  Free Cash Flow is midpoint of a range based on December 31, 2015 market prices. Adjusted Cash Flow From Operations (non-
GAAP) primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures.  Includes an extension of bonus depreciation. Does not include impacts of PHI

9
Q4 2015  Earnings Release Slides
Cost Management Initiative Update
•
Cost savings of $350M have been identified and incorporated into current long range
plan, reflecting our high level of confidence in achieving the reductions
•
Additional $50 million of nuclear fuel savings already reflected in the hedge disclosure
•
Savings to be achieved at:
o
Exelon Generation -
$175M
o
Corporate Shared Services -
$175M
•
Approximately $100M of savings coming from Information Technology organization
•
Remaining savings split among our centralized Corporate functions (e.g. Finance,
Legal, Supply, and Human Resources)
•
Savings to be allocated roughly 50% to Exelon Generation and 50% to Exelon
Utilities
•
Run-rate savings impact on EPS remains within range communicated at EEI  ($0.13 –
$0.18)
(1)
•
~35% of run-rate savings will be achieved by end of 2016
Our enterprise-wide O&M CAGR over the 2015 to 2018 period will be negative with a (1.0%)
CAGR at Exelon Generation
(1)
Based on projected 2018 share count of 965M shares, which assumes PHI merger closes

10
Q4 2015  Earnings Release Slides
Adjusted O&M Forecast
(2)
•
2016 forecast of $7.18B
(1)
•
Expect CAGR of ~(0.5)% for 2015-2018
$4,475
$1,275
$775
$750
$4,675
$1,300
$675
$675
ComEd
ComEd
BGE
HoldCo
HoldCo
PECO
ExGen
2016 Guidance
ExGen
BGE
PECO
$7,175
$7,250
-$75
2015 Actual
-$100
Key Year-over-Year Drivers
(2)
•
Inflation:  $150M
•
PECO & BGE Storm Costs: $50M
•
Utility Bad Debt Costs:  $50M
•
Baltimore City Conduit Fee
(3)
:  $25M
•
Pension/OPEB:  ($75M)
•
Fewer Nuclear Outages:  ($75M)
•
Cost Management Initiative:
($125M) 
(1)
Refer to the Appendix for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M.  Further, the Utilities adjusted O&M excludes regulatory O&M costs that are P&L neutral. ExGen adjusted
O&M excludes direct cost of sales for certain Constellation businesses, P&L neutral decommissioning costs and the impact from O&M related to variable interest entities.
(2)
All amounts rounded to the nearest $25M
(3)
The Baltimore City Board of Estimates' decision to more than triple the lease fee on BGE’s approximately 12 million linear feet of electric cable in the City-owned conduit system became
effective in Q4 2015.

11
Q4 2015  Earnings Release Slides
Exelon Generation: Gross Margin Update
1)
Gross margin categories rounded to nearest $50M
2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and
fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon
Nuclear Partners, operating services agreement with Fort Calhoun and variable interest
entities. Total Gross Margin is also net of direct cost of sales for certain Constellation
businesses.  See Slide 29
for a Non-GAAP to GAAP reconciliation of Total Gross Margin.
3)
Excludes EDF’s equity ownership share of the CENG Joint Venture
4)
Mark-to-Market of Hedges assumes mid-point of hedge percentages
•
Ginna
RSSA reflected in gross margin updates
•
Behind ratable hedging position reflects the fundamental upside we see in power prices
•
Generation ~37-40% open in 2017
•
Power position ~5-8% behind ratable, considering cross-commodity hedges
Recent Developments
Gross Margin Category ($M)
(1)
2016
2017
2018
2016
2017
2018
Open Gross Margin
(3)
(including South, West, Canada hedged gross
margin)
$5,200
$5,800
$6,150
$(450)
-
$50
Mark-to-Market of Hedges
(3,4)
$1,700
$800
$250
$500
$50
-
Power New Business / To Go
$450
$800
$1,000
$(50)
-
-
Non-Power Margins Executed
$250
$150
$100
$50
$50
$50
Non-Power New Business / To Go
$200
$300
$400
$(50)
$(50)
$(50)
Total Gross Margin
(2)
$7,800
$7,850
$7,900
-
$50
$50
December 31, 2015
Change from Sept. 30, 2015

12
Q4 2015  Earnings Release Slides
Exelon Generation Disclosures
December 31, 2015

13
Q4 2015  Earnings Release Slides
Portfolio Management Strategy
Protect Balance Sheet
Ensure Earnings Stability
Create Value
Strategic Policy Alignment
•Aligns hedging program with
financial policies and financial
outlook
•Establish minimum hedge targets
to meet financial objectives of the
company (dividend, credit rating)
•Hedge enough commodity risk to
meet future cash requirements
under a stress scenario
Three-Year Ratable Hedging
•Ensure stability in near-term cash
flows and earnings
•Disciplined approach to hedging
•Tenor aligns with customer
preferences and market liquidity
•Multiple channels to market that
allow us to maximize margins
•Large open position in outer years
to benefit from price upside
Bull / Bear Program
•Ability to exercise fundamental
market views to create value within
the ratable framework
•Modified timing of hedges versus
purely ratable
•Cross-commodity hedging (heat
rate positions, options, etc.)
•Delivery locations, regional and
zonal spread relationships
Exercising Market Views
Purely ratable
Actual hedge %
Market views on timing, product
allocation, and regional spreads
reflected in actual hedge %
High End of Profit
Low End of Profit
% Hedged
Open Generation
with LT Contracts
Portfolio Management &
Optimization
Portfolio Management Over Time
Align Hedging & Financials
Establishing Minimum Hedge Targets
Credit Rating
Capital &
Operating
Expenditure
Dividend
Capital
Structure

14
Q4 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
•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

15
Q4 2015  Earnings Release Slides
ExGen Disclosures 
(1)
Gross margin categories rounded to nearest $50M  
(2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power
and fuel expense, excluding revenue related to decommissioning, gross receipts tax,
Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable
interest entities. Total Gross Margin is also net of direct cost of sales for certain
Constellation businesses.  See Slide 29 for a Non-GAAP to GAAP reconciliation of Total
Gross Margin.
(3)
Excludes EDF’s equity ownership share of the CENG Joint Venture
(4)
Mark-to-Market of Hedges assumes mid-point of hedge percentages
(5)
Based on December 31, 2015 market conditions
Gross Margin Category ($M)
(1)
2016
2017
2018
Open Gross Margin
(including South, West & Canada hedged GM)
(3)
$5,200
$5,800
$6,150
Mark-to-Market of Hedges
(3,4)
$1,700
$800
$250
Power New Business / To Go
$450
$800
$1,000
Non-Power Margins Executed
$250
$150
$100
Non-Power New Business / To Go
$200
$300
$400
Reference Prices
(5)
2016
2017
2018
Henry Hub Natural Gas ($/MMbtu)
$2.49
$2.79
$2.91
Midwest: NiHub ATC prices ($/MWh)
$28.46
$29.23
$29.22
Mid-Atlantic: PJM-W ATC prices ($/MWh)
$34.51
$35.22
$34.16
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$4.79
$4.66
$4.49
New York: NY Zone A ($/MWh)
$31.82
$34.52
$33.60
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$9.60
$11.32
$9.71
$7,800
$7,850
$7,900
Total Gross Margin
(2)

16
Q4 2015  Earnings Release Slides
ExGen Disclosures
Generation and Hedges
2016
2017
2018
Exp. Gen (GWh)
(1)
199,900
206,500
207,400
Midwest
97,300
96,400
96,800
Mid-Atlantic
(2)
63,600
61,600
60,700
ERCOT
17,400
26,500
31,500
New York
(2)
9,300
9,200
9,100
New England
12,300
12,800
9,300
% of Expected Generation Hedged
(3)
90%-93%
60%-63%
28%-31%
Midwest
88%-91%
55%-58%
21%-24%
Mid-Atlantic
(2)
91%-94%
64%-67%
35%-38%
ERCOT
98%-101%
67%-70%
32%-35%
New York
(2)
83%-86%
71%-74%
41%-44%
New England
94%-97%
49%-52%
16%-19%
Effective Realized Energy Price ($/MWh)
(4)
Midwest
$34.50
$33.50
$33.00
Mid-Atlantic
(2)
$47.00
$46.00
$42.50
ERCOT
(5)
$11.00
$8.00
$3.50
New York
(2)
$58.50
$44.50
$38.00
New England
(5)
$20.50
$14.50
$7.00
(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 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.

17
Q4 2015  Earnings Release Slides
ExGen Hedged Gross Margin Sensitivities
(1)
Based on December 31, 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)
2016
2017
2018
Henry Hub Natural Gas ($/Mmbtu)
+ $1/Mmbtu
$10
$380
$695
-
$1/Mmbtu
$(5)
$(380)
$(695)
NiHub ATC Energy Price
+ $5/MWh
$55
$225
$380
-
$5/MWh
$(50)
$(220)
$(380)
PJM-W ATC Energy Price
+ $5/MWh
$15
$100
$200
-
$5/MWh
$(10)
$(110)
$(205)
NYPP Zone A ATC Energy Price
+ $5/MWh
$5
$15
$25
-
$5/MWh
$(5)
$(15)
$(25)
Nuclear Capacity Factor
+/-
1%
+/-
$40
+/-
$40
+/-
$40

18
Q4 2015  Earnings Release Slides
ExGen Hedged Gross Margin Upside/Risk
$8,050
$7,500
$8,800
$7,100
(1)
(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.
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
$9,750
$6,550
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 December 31, 2015

19
Q4 2015  Earnings Release Slides
Illustrative Example of Modeling Exelon Generation                  
2017 Gross Margin
(1)
Mark-to-market rounded to the nearest $5 million
(2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear
Row
Item
Midwest
Mid-Atlantic
ERCOT
New York
New England
South, West &
Canada
(A)
Start with fleet-wide open gross margin
(B)
Expected Generation (TWh)
96.4
61.6
26.5
9.2
12.8
(C)
Hedge % (assuming mid-point of range)
56.5%
65.5%
68.5%
72.5%
50.5%
(D=B*C)
Hedged Volume (TWh)
54.5
40.3
18.2
6.7
6.5
(E)
Effective Realized Energy Price ($/MWh)
$33.50
$46.00
$8.00
$44.50
$14.50
(F)
Reference Price ($/MWh)
$29.23
$35.22
$4.66
$34.52
$11.32
(G=E-F)
Difference ($/MWh)
$4.27
$10.78
$3.34
$9.98
$3.18
(H=D*G)
Mark-to-market value of hedges  ($ million)
$235
$435
$60
$65
$20
(I=A+H)
Hedged Gross Margin ($ 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
$150
$300
$7,850 million
$5.8 billion
$6,600
$800
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.
(1)
(2)

20
Q4 2015  Earnings Release Slides
Additional Disclosures

21
Q4 2015  Earnings Release Slides
Exelon Utilities Adjusted Operating EPS Contribution
(1)
Key Drivers –
4Q15
(2)
vs. 4Q14
:
BGE
(+0.02):
•
Increased revenues due to increased distribution rates and
transmission earnings: $0.02
PECO (-0.02):
•
Unfavorable weather (RNF): $(0.03)
•
Decreased uncollectible accounts expense: $0.01
ComEd
(+0.00):
•
Unfavorable weather and volume
(3)
: $(0.02)
•
Increased distribution
(3)
and transmission earnings due to
increased capital investments: $0.02
4Q 2015
$0.26
$0.09
$0.09
$0.08
4Q 2014
$0.26
$0.09
$0.11
$0.06
BGE
ComEd
Numbers may not add due to rounding.
(1)
(2)
(3)
PECO
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.
There is a $(0.01) share differential impact spread across the utilities in Q4 2015.
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.

22
Q4 2015  Earnings Release Slides
ExGen Adjusted Operating EPS Contribution
(1)
$0.15
Q4
$0.27
2015
2014
Numbers may not add due to rounding
(1)
(excludes Salem)
Q4
2014 Actual
Q4
2015
Actual
Planned Refueling Outage
Days
97
103
Non-refueling Outage Days
8
21
Nuclear Capacity Factor
94.8%
93.3%
Key Drivers –
Q4 2015 vs. Q4 2014
ExGen
(-0.12):
•
Increased costs primarily due to timing of nuclear projects: $(0.03)
•
Unfavorable impact associated with nuclear refueling outages:
$(0.05)
•
Higher depreciation costs primarily due to increased nuclear
decommissioning amortization and ongoing capital expenditures:
$(0.02)
•
Favorable settlement of certain state income tax positions: $0.04
•
Other: $(0.04)
•
Share differential: $(0.02)
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.

23
Q4 2015  Earnings Release Slides
2016
(4)(5)
$0.50 -
$0.60
Other
($0.02)
($0.01)
Depreciation &
Amortization
($0.05)
O&M
(3)
$0.01
RNF
(2)
2015
(1)
ComEd Adjusted Operating EPS Bridge 2015 to 2016
Note: Drivers add up to mid-point of 2016 adjusted operating EPS range
(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) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense.
(3) O&M excludes regulatory items that are P&L neutral.
(4) Shares Outstanding (diluted) are 893M in 2015 and 890M in 2016. Refer to slide 38 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.
(5) Guidance assumes an effective tax rate for 2016 of 39.6%.
Interest
$0.07 Distribution
$0.06 Transmission
$0.01 Weather
$0.01 Pension/OPEB
$0.01 Storm Costs
($0.01) Inflation
$0.14
$0.48

24
Q4 2015  Earnings Release Slides
2016
(4)(5)
$0.40 -
$0.50
Other
($0.01)
O&M
(3)
($0.04)
RNF
(2)
PECO Adjusted Operating EPS Bridge 2015 to 2016
Note: Drivers add up to mid-point of 2016 adjusted operating EPS range
(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) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense.
(3) O&M excludes regulatory items that are P&L neutral.
(4) Shares Outstanding (diluted) are 893M in 2015 and 890M in 2016. Refer to slide 38 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.
(5) Guidance assumes an effective tax rate for 2016 of 26.9%.
2015
(1)
$0.08    Electric Distribution Rate Case
($0.01)   Weather
($0.01)   Weather Normal RNF
($0.02)   Weather Related (Storm ($0.01, Bad Debt ($0.01))
($0.01)   Rate Case Related (Veg. Mgmt. & Cap Settlement)
($0.01)   Inflation
$0.07
$0.43

25
Q4 2015  Earnings Release Slides
O&M
(3)
$0.01
RNF
(2)
2015
(1)
2016
(4)(5)
$0.25 -
$0.35
Other
BGE Adjusted Operating EPS Bridge 2015 to 2016
($0.02) Storm Costs
($0.02) Bad Debt
($0.02) Baltimore City Conduit Fee
$0.02 Pricing/Mix
$0.02 Transmission
Note: Drivers add up to mid-point of 2016 adjusted operating EPS range.
(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) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense.
(3) O&M excludes regulatory items that are P&L neutral.
(4) Shares Outstanding (diluted) are 893M in 2015 and 890M in 2016. Refer to slide 38 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.
(5) Guidance assumes an effective tax rate for 2016 of 39.5%.
$0.04
$(0.06)
$0.31

26
Q4 2015  Earnings Release Slides
$1.25 -
$1.35
2016
(5)(6)
2015
(1)
($0.04)
Gross Margin
(2)
O&M
(3)
($0.09)
Other
Depreciation &
Amortization
(4)
($0.08)
ExGen Adjusted Operating EPS Bridge 2015 to 2016
Note: Drivers add up to mid-point of 2016 adjusted operating EPS range.
(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)
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)
O&M excludes items that are P&L neutral (including decommissioning  costs and variable interest entities) and direct cost of sales for certain Constellation businesses.
(4)
Depreciation & Amortization excludes cost of sales for certain Constellation businesses, which are included in gross margin
(5)
Shares Outstanding (diluted) are 893M in 2015 and 890M in 2016.  Refer to slide 38 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.
(6)
Guidance assumes an effective tax rate for 2016 of 34%.
($0.13) Normalized load optimization in 2016
$0.05 Unplanned Generation Outages
$0.02 Capacity Revenues
$0.02 Higher Load Volumes
($0.06) Capital placed in service
($0.03) Decom Asset Retirement
Cost Depreciation
$0.06 Employee Benefit Costs
$0.06 Cost Management Savings
$0.05 Nuclear outages (2 less in 2016)
$0.02 Pension/OPEB
($0.07) Inflation
($0.02) Decom Asset Retirement Obligation
($0.05) Decrease in DPAD and the
absence of favorable state settlements
partially offset by an increase in tax
credits
($0.04) Decom, primarily unregulated
realized gains
($0.01) Interest
$0.02 Other
$0.11
$1.40

27
Q4 2015  Earnings Release Slides
2016 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.
(4)
Figures reflect cash CapEx
and CENG
fleet at 100%
(5)
Other Financing primarily includes
expected changes in short-term debt
and tax sharing from the parent.
(6)
Acquisitions and Divestitures and Equity
Investments previously captured in
Adjusted Cash Flow from Operations
(7)
Dividends are subject to declaration by
the Board of Directors.
(8)
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
Exelon intends to return capital to
shareholders and bondholders, if the
merger is not approved
Operational excellence and financial
discipline drives free cash flow reliability
Generating ~$3.7B of free cash flow in
2016, including $1.3B at ExGen and
$2.9B at the Utilities
Creating value for customers, communities
and shareholders
Investing $5.3B, with $4.0B at the Utilities
and $1.3B at ExGen
($ in millions)
(1)
BGE
ComEd
PECO
Total
Utilities
ExGen
Corp
(8)
Exelon
2016E
Cash
Balance
Beginning Cash Balance
(2)
7,750
Adjusted Cash Flow from Operations
(2,3)
650
1,575
700
2,925
3,725
(425)
6,225
Base CapEx and Nuclear Fuel
(4)
0
0
0
0
(2,475)
(100)
(2,550)
Free Cash Flow
650
1,575
700
2,925
1,250
(525)
3,650
Debt Issuances
750
950
450
2,150
0
0
2,150
Debt Retirements
(300)
(675)
(300)
(1,275)
0
(1,875)
(3,150)
Project Financing
n/a
n/a
n/a
n/a
100
n/a
100
Equity Buyback
0
0
0
0
0
(1,600)
(1,600)
Contribution from Parent
0
475
0
475
0
(475)
0
Other Financing
(5)
(75)
450
25
400
0
1,075
1,475
Financing
375
1,200
175
1,750
100
(2,875)
(1,025)
Total Free Cash Flow and Financing Growth
1,025
2,775
850
4,675
1,375
(3,400)
2,625
Utility Investment
(825)
(2,425)
(675)
(3,950)
0
0
(3,950)
ExGen Growth
(4)
0
0
0
0
(1,325)
0
(1,325)
Acquisitions and Divestitures
(6)
0
0
0
0
0
0
0
Equity Investments
(6)
0
0
0
0
(125)
0
(125)
Dividend
(7)
0
0
0
0
0
(1,150)
(1,150)
Other CapEx
and Dividend
(825)
(2,425)
(675)
(3,950)
(1,450)
(1,150)
(6,550)
Total Cash Flow, excl. Collateral
200
350
175
725
(100)
(4,550)
(3,900)
Ending
Cash
Balance
(2)
3,850

28
Q4 2015  Earnings Release Slides
Pension and OPEB Contributions and Expense
(1)    Pension and OPEB expenses assume a ~26% and ~28% capitalization rate in 2015 and 2016, respectively
(2)
The Balanced Funding Strategy for the Qualified Plans provides pension funding of the greater of $250M or minimum required contributions plus amounts required to avoid benefit
restrictions and at-risk status
(3)
Expected return on assets for pension is 7.00% and for OPEB is 6.70% for 2016
(4)
Pension and OPEB discount rates are 4.29% for the majority of plans at 12/31/15
2015
2016
(in $M)
Pre-Tax
Expense
(1)
Contributions
Pre-Tax
Expense
(1)
Contributions
(2)
Qualified
Pension
(3)(4)
$425
$450
$370
$250
Non-Qualified
Pension
15
15
15
20
OPEB
(3)(4)
30
40
5
35
Total
$470
$505
$390
$305

29
Q4 2015  Earnings Release Slides
Additional ExGen Modeling Data
Total
Gross Margin Reconciliation (in $M)
(1)
2016
2017
2018
$8,475
$8,475
$8,525
Other Revenues
(4)
$(325)
$(325)
$(325)
Direct cost of sales incurred to generate revenues for certain
Constellation businesses
(5)
$(350)
$(300)
$(300)
Total Gross Margin (Non-GAAP, as shown on slide 11)
$7,800
$7,850
$7,900
(1)
All amounts rounded to the nearest $25M
(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.
(6)
ExGen
amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture. 
(7)
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
Key ExGen Modeling Inputs (in $M)
(1)(6)
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%
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
Revenue Net of Purchased Power and Fuel Expense
(2)(3)

30
Q4 2015  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 that result in 2016
usage being lower than 2015
Chicago GMP
2.3%
Chicago Unemployment
5.8%
2016 load growth is greater
than 2015, attributed to
improving economic conditions
and moderate customer
growth, partially offset by
energy efficiency
Baltimore GMP
2.4%
Baltimore Unemployment
5.3%
2016 load growth is driven by
slowly improving economic
conditions coupled with solid
residential customer growth,
partially offset by energy
efficiency
Philadelphia GMP
1.4%
Philadelphia
Unemployment
5.3%
2015
2016E
2015
1.1%
2016E
(0.3%)
(1.4%)
(0.8%)
(1.5%)
0.1%
(0.9%)
(0.4%)
(2.0%)
0.4%
(0.1%)
(0.2%)
0.3%
(0.3%)
0.6%
1.3%
(0.5%)
0.7%
1.5%
1.0%
1.1%
0.7%
2.0%
0.5%
Notes: Data is weather normalized and not adjusted for leap year.  Source of economic outlook data is IHS (December 2015).  Assumes 2015 GDP of 2.5% 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.

31
Q4 2015  Earnings Release Slides
ComEd April 2015 Distribution Formula Rate
Docket #
15-0287
Filing Year
Reconciliation Year
Common Equity Ratio
ROE
Requested Rate of
Return
~ 7% for both the filing and reconciliation years
Rate Base
$8,277 million–
Filing year (represents projected year-end rate base using 2014 actual plus 2015 projected capital
additions).  2015 and 2016  earnings will reflect 2015 and 2016 year-end rate base respectively.
$7,082 million -
Reconciliation year (represents
year-end rate base for 2014)
Revenue Requirement
Decrease
$67M decrease  ($152M decrease due to the 2014 reconciliation offset by a $85M 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
The 2015 distribution formula rate filing established the net revenue requirement used to set the rates that took 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 2014 costs and 2015 projected plant additions. 
•
Annual Reconciliation: For 2014, this amount reconciles the revenue requirement reflected in rates in effect during 2014 to the actual costs for
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
Reconciles Revenue Requirement reflected in rates during 2014 to 2014 Actual Costs Incurred.  Revenue requirement
2013 and reflects the impacts of PA 98-0015 (SB9)
~ 46% for both the filing and reconciliation year
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 
–
for 2014 is based on docket 13-0318 (2012 actual costs and 2013 projected net plant additions) approved in December
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.
that year. The annual reconciliation impacts cash flow in 2016 but the earnings impact has been recorded in 2014 as a regulatory asset.

32
Q4 2015  Earnings Release Slides
PECO Electric Distribution Rate Case & 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
$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
•
12/17/15 –
PaPUC
Final Order
•
Increased rates effective on January 1, 2016
The 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. 
Revenue Requirement Settlement Increase

33
Q4 2015  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)
$120.9M
$79.5M
Proposed
Distribution Increase as %
of overall bill
3.2%
8.8%
Notes
•
11/06/15 BGE
filed application with the MDPSC seeking increases in electric & gas
distribution base rates
•
$140M or ~70% of the total $200M distribution rate increase is for recovery of Smart Grid
investment
•
Requested incremental conduit fees of $31M be recovered through a rider
•
210 Day Proceeding
•
06/03/2016
-
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

34
Q4 2015  Earnings Release Slides
Appendix
Reconciliation of Non-GAAP
Measures

35
Q4 2015  Earnings Release Slides
4Q GAAP EPS Reconciliation
Three Months Ended December 31, 2015
ExGen
ComEd
PECO
BGE
Other
Exelon
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.15
$0.09
$0.09
$0.08
$(0.04)
$0.38
Unrealized gains related to NDT fund investments
0.05
-
-
-
-
0.05
Merger and integration costs
-
-
-
-
(0.01)
(0.01)
Amortization of commodity contract intangibles
(0.01)
-
-
-
-
(0.01)
Long-Lived asset impairments
(0.01)
-
-
-
-
(0.01)
Reassessment of state deferred income taxes
(0.01)
-
-
-
(0.03)
(0.05)
Reduction in state income tax reserve
0.01
-
-
-
-
0.01
PHI merger related redeemable debt exchange
-
-
-
-
(0.01)
(0.01)
CENG non-controlling interest
(0.02)
-
-
-
-
(0.02)
4Q 2015 GAAP Earnings (Loss) Per Share
$0.17
$0.09
$0.09
$0.08
$(0.09)
$0.33
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 December 31, 2014
ExGen
ComEd
PECO
BGE
Other
Exelon
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.27
$0.09
$0.11
$0.06
$(0.04)
$0.48
Mark-to-market impact of economic hedging activities
(0.08)
-
-
-
-
(0.08)
Unrealized gains related to NDT fund investments
0.03
-
-
-
-
0.03
Merger and integration costs
(0.01)
-
-
-
(0.02)
(0.03)
Mark-to-market impact of PHI merger related interest  rate swaps
-
-
-
-
(0.06)
(0.06)
Reassessment of state deferred income taxes
0.04
-
-
-
(0.01)
0.03
Amortization of commodity contract intangibles
(0.03)
-
-
-
-
(0.03)
Plant retirements and divestitures
0.06
-
-
-
-
0.06
Long-Lived asset impairments
(0.39)
-
-
-
-
(0.39)
Bargain-Purchase gain
0.03
-
-
-
-
0.03
Tax settlements
0.01
-
-
-
-
0.01
CENG non-controlling interest
(0.03)
-
-
-
-
(0.03)
4Q 2014 GAAP Earnings (Loss) Per Share
($0.11)
$0.09
$0.11
$0.06
$(0.13)
$0.02

36
Q4 2015  Earnings Release Slides
4Q YTD GAAP EPS Reconciliation
Year Ended December 31,
2014
ExGen
ComEd
PECO
BGE
Other
Exelon
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.34
$0.47
$0.41
$0.23
$(0.06)
$2.39
Mark-to-market impact of economic hedging activities
(0.42)
-
-
-
-
(0.42)
Unrealized gains related to NDT fund investments
0.10
-
-
-
-
0.10
Asset retirement obligation
0.02
-
-
-
-
0.02
Plant retirements and divestitures
0.28
-
-
-
-
0.28
Long-Lived asset impairment
(0.49)
-
-
-
(0.02)
(0.50)
Gain on CENG integration
0.18
-
-
-
-
0.18
Merger and integration costs
(0.10)
-
-
-
(0.04)
(0.14)
Mark-to-market impact of PHI merger related interest swaps
-
-
-
-
(0.07)
(0.07)
Amortization of commodity contract intangibles
(0.07)
-
-
-
-
(0.07)
Tax settlements
0.12
-
-
-
-
0.12
Reassessment of state deferred income taxes
0.04
-
-
-
(0.01)
0.03
Bargain-Purchase gain
0.03
-
-
-
-
0.03
CENG non-controlling interest
(0.07)
-
-
-
-
(0.07)
4Q 2014 GAAP Earnings Per Share
$0.97
$0.47
$0.41
$0.23
($0.20)
$1.88
NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

37
Q4 2015  Earnings Release Slides
4Q YTD GAAP EPS Reconciliation (continued)
NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.
Year Ended December 31, 2015
ExGen
ComEd
PECO
BGE
Other
Exelon
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.40
$0.48
$0.43
$0.31
$(0.13)
$2.49
Mark-to-market impact of economic hedging activities
0.18
-
-
-
-
0.18
Unrealized losses related to NDT fund investments
(0.13)
-
-
-
-
(0.13)
Merger and integration costs
(0.02)
(0.01)
-
-
(0.03)
(0.07)
Mark-to-market impact of PHI merger related interest rate swaps
-
-
-
-
(0.02)
(0.02)
Long-lived asset impairment
(0.01)
-
-
-
(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
PHI merger related redeemable debt exchange
-
-
-
-
(0.01)
(0.01)
Reassessment of state deferred income taxes
(0.01)
-
-
-
(0.03)
(0.05)
Reduction in state income tax reserve
0.01
-
-
-
-
0.01
CENG non-controlling interest
0.04
-
-
-
-
0.04
4Q 2015 GAAP Earnings (Loss) Per Share
$1.54
$0.48
$0.42
$0.31
$(0.20)
$2.54

38
Q4 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 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
–
Certain costs incurred associated with the pending Pepco Holdings, Inc. acquisitions
–
Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at
the
date
of
acquisition
of
Integrys
in
2014
–
Generation’s non-controlling interest related to CENG exclusion items
–
Other unusual items

39
Q4 2015  Earnings Release Slides
Adjusted O&M Reconciliations to GAAP
2015
Adjusted
O&M
Reconciliation
(in
$M)
(3)
ExGen
ComEd
PECO
BGE
Other
Exelon
GAAP O&M
$5,300
$1,575
$800
$675
$(25)
$8,325
PHI Acquisition Costs
(25)
-
-
-
(25)
(50)
Long-Lived Asset Impairment
-
-
-
-
(25)
(25)
Regulatory
O&M
(1)
-
(275)
(125)
-
-
(400)
Decommissioning
(1)
50
-
-
-
-
50
Direct cost of sales incurred to generate revenues for
certain
Constellation
businesses
(2)
(250)
-
-
-
-
(250)
O&M for managed plants that are partially owned
(425)
-
-
-
-
(425)
Other
25
-
-
-
-
25
Adjusted O&M (Non-GAAP, as shown on slide 10)
$4,675
$1,300
$675
$675
$(75)
$7,250
(1)
Reflects P&L neutral O&M.
(2)
Reflects the direct cost of sales of certain Constellation businesses of Generation, which are included in Total Gross Margin.
(3)
All amounts rounded to the nearest $25M.

40
Q4 2015  Earnings Release Slides
Adjusted O&M Reconciliations to GAAP
2016
Adjusted
O&M
Reconciliation
(in
$M)
(3)
ExGen
ComEd
PECO
BGE
Other
Exelon
GAAP O&M
$5,175
$1,600
$875
$750
$(100)
$8,300
Regulatory
O&M
(1)
-
(300)
(100)
-
-
(400)
Decommissioning
(1)
50
-
-
-
-
50
Direct cost of sales incurred to generate revenues for certain
Constellation
businesses
(2)
(300)
-
-
-
-
(300)
O&M for managed plants that are partially owned
(400)
-
-
-
-
(400)
Other
(50)
(25)
-
-
-
(75)
Adjusted O&M (Non-GAAP, as shown on slide 10)
$4,475
$1,275
$775
$750
$(100)
$7,175
(1)
Reflects P&L neutral O&M.
(2)
Reflects the direct cost of sales of certain Constellation businesses of Generation, which are included in Total Gross Margin.
(3)
All amounts rounded to the nearest $25M.

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