EX-99.1 2 d434938dex991.htm PRESENTATION SLIDES AND HANDOUTS Presentation slides and handouts
Edison Electric Institute
Financial Conference
November 12 –
13, 2012
Exhibit 99.1

2012 EEI Conference
1
Cautionary Statements Regarding
Forward-Looking Information
This presentation contains certain forward-looking statements within the meaning of the Private Securities
Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual
results to differ materially from the forward-looking statements made by Exelon Corporation, Commonwealth
Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation
Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) 
Exelon’s 2011 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 18; (2) Constellation Energy Group’s 2011 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 12; (3) the
Registrant’s Third Quarter 2012 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
16; and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to
place undue reliance on these forward-looking statements, which apply only as of the date of this
presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-
looking statements to reflect events or circumstances after the date of this presentation. 

2
Financial Discipline & Flexibility
Financial
Action
Summary
Operational
Efficiencies
Cost
Management
•
Identified
additional
cost
savings
of
$50
million
per
year
beginning
in
2014,
in
addition
to
$500
million
merger
run
rate
synergies
(1)
Financial Tools
Financial
Flexibility
•
Optimized nuclear fuel inventory expenditures for cash savings
of
$400
million
from
2013-2016
(2)
(incorporated
in
2012
Analyst
Day CapEx schedule)
•
Investments in upstream gas business and utility scale solar
will be funded off-credit where possible
•
Evaluating project financing options for Exelon Wind portfolio
Defer Growth
Projects
•
Deferred ~$1.0B of nuclear uprate spend to align with
expected market recovery
•
LaSalle EPU 4-year deferral (additional two years since 2012 Analyst
Day announcement)
•
Limerick EPU 4-year deferral
Maintaining investment grade credit rating and dividend are our top priorities
(1)
Run rate target for O&M synergies from 2014 onwards.
2012 EEI Conference
(2) Includes reduction in nuclear fuel capital expenditures related to the 4 year deferral of LaSalle
and Limerick EPU projects.
Eliminated
undesignated
renewable
spend
of
~$1.3
billion
in
2013-2015
Note: EPU = Extended  Power Uprate.

3
Merger Checklist Update
Item
Target
Status
Highlights
O&M
Synergies
$500 million run rate
beginning
in
2014
(1)
•
On track to meet $170 million 2012 target and
$550
(2)
million run rate synergy target for 2014
•
Unregulated business comprises ~75% of target
Liquidity
Reduction
$4.2 billion year-end
2012
•
•
Gross Margin
Opportunities
$100
million
run
rate
(4)
•
On track to meet $100 million run rate synergies
starting in 2014
Asset Sales
Process
Execute sales agreement
by August 2012
•
Executed
sales
agreement
on
August
9 
for
~$400
million, plus tax benefits of $225 million; expect to
close transaction in 4Q 2012
BGE
File
rate
case
in
2
half
of 2012
•
Filed
rate
case
on
July
27
,
2012
and
expect
order
from MD PSC by February 2013
•
Filing reflects a $176M increase in revenue
requirements for both electric and gas
Commercial
Load Growth
~20% growth in volumes
from 2011 -
2014
•
Lower volume growth as a consequence of
significant competition but disciplined pricing
(3)
As of 9/30/2012.
(4)
(1)
Run rate target for O&M synergies from 2014 onwards.
(2)
We are successfully executing on the merger
2012 EEI Conference
nd
Includes additional $50M run rate cost savings disclosed in 3Q12 earnings materials.
Gross Margin opportunities on a run rate basis from 2014 onwards from
combining the two commercial portfolios.
Amended and extended existing $7 billion in credit 
facilities across all OpCos until 2017
th
th
On
track
to
eliminate
legacy
CEG
credit
facilities
of
$4.2 billion,
with
$2.7
billion
reduced
year
to
date
(3)

4
Exelon Generation: Load Serving Update
Retail Landscape
•
Expected load growth of 1% across the U.S.
•
Switched market expected to grow by
approximately 11% in C&I from 2011 to 2015
•
Switched market expected to grow by
approximately 22% in residential from 2011 to
2015
Strategy
•
Serve new customers as existing markets grow
and new markets open
-
Retail expected to grow at ~11% CAGR for 2011-2015
-
Wholesale expected to remain static starting in 2013
•
Improve market share in existing markets
•
Cross sell suite of products to existing
customers  to create higher retention
•
Leverage operational efficiency and national
footprint
Execution
•
Recently, the market has been impacted by
increased competition and aggressive pricing
•
Our disciplined approach to pricing has led to a
reduction in expected volumes and margins
•
Various channels to market are available to
optimize our generation
2012E
30-40%
60-70%
165
175
2013E
25-35%
185
2015E
2014E
20-30%
170
55-65%
35-45%
2011A
170
90
Wholesale Load
Total Contracted
Retail Load
Retail & Wholesale Load (TWh)
(1)
65-75%
70-80%
(2)
2012 EEI Conference
0
50
100
150
200
+9%
(1)
Numbers and percentages are rounded to the nearest 5.
(2)
Index
load
expected
to
be
20%
to
30%
of
total
forecasted
retail
load.
80

Exelon Generation:  Regulatory Priorities 
5
Exelon is heavily engaged in advocating positions that enhance the integrity of 
competitive markets and shareholder value
2012 EEI Conference
•
PJM
–
Restructured Minimum Offer Price Rules (MOPR)
-
Proposed
modifications
will
enhance
clarity
and
appropriately
apply minimum offer rule to subsidized projects
-
Modifications positioned to be implemented in advance of May
2013 PJM capacity auction
•
ERCOT
–
Market
Redesign
-
Forward capacity market remains a long-term option to assure
resource adequacy
-
In October, the PUCT voted to increase price caps (as an “interim”
step) from $4,500/MWh to:
•
$5,000/MWh (beginning June 1, 2013)
•
$7,000/MWh (beginning June 1, 2014)
•
$9,000/MWh (beginning June 1, 2015)

2012 EEI Conference
6
Executing Plan for Stronger Future
•Strong financial performance in 2012
•Successfully executing on the merger and meeting commitments
•Growing utility rate base in a prudent manner
•Expecting $3 -
$6/MWh upside in forward power prices as a result of plant
retirements, higher operating costs for compliance and a disconnect
between heat rates and gas prices
•Extracting value out of load serving business in a tough, competitive pricing
environment
•Anticipating positive enhancements in the regulatory arena, particularly with
the PJM MOPR
•Prioritizing capital allocation in order to maintain investment grade ratings
and provide time for a power market recovery to support the dividend

Financial Update

8
2012 Earnings Guidance
2012 Prior Guidance
(prior to 3Q earnings call)
$2.55 -
$2.85
(1)
$1.75 -
$1.95
$0.30 -
$0.40
$0.40 -
$0.50
$0.05 -
$0.15
HoldCo
ExGen
ComEd
PECO
BGE
(1)
2012 Revised Guidance
(disclosed at 3Q earnings call)
$2.75 -
$2.95
(1)
$1.85 -
$1.95
$0.45 -
$0.50
$0.40 -
$0.50
$0.05 -
$0.10
HoldCo
ExGen
ComEd
PECO
BGE
2012 EEI Conference 
2012 guidance includes Constellation Energy and BGE earnings for March 12 – December 31, 2012. Based on expected 2012 average outstanding shares of 819M. 
Earnings guidance for OpCos may not add up to consolidated EPS guidance.
Key Drivers of Change
in Full-Year Guidance
•
Impact of ICC Rehearing
Order on ComEd’s earnings
•
Higher than expected RNF
at ExGen in 3Q 2012
•
Cost impact of Hurricane
Sandy

Cost Synergies Update
O&M
Savings
($M)
Run Rate O&M Synergies Breakdown
Run rate O&M
synergies of
~$550M
•
Key
Drivers
of
run
rate
O&M
synergies
include
-
Labor savings from corporate and
commercial consolidations
-
Reduced collateral requirements
-
IT systems consolidation
-
Supply chain savings
-
Other non-labor corporate synergies
On track to achieving merger synergies
(1) O&M synergies include cost savings of ~$40M from lower liquidity requirements.  
Unregulated
77%
BGE
7%
PECO
7%
ComEd
10%
9
2012 EEI Conference 
$305
$170
2015+
2014
$550
2013
2012
$50
$500
•
On
track
to
meet
$170M
O&M
synergies
target
for
2012
•
Completed
activities
to
enable
$275M
of
the
$550M
run-rate
synergies
to
date
(1)

Capital Expenditure Expectations
300
225
100
100
100
50
75
100
2015
2,450
950
975
325
2014
2,475
1,025
1,075
175
2013
2,750
975
925
575
2012
(1)
3,800
975
1,150
625
675
Base Capex
Nuclear Fuel
MD Commitments
Wind
Solar
Upstream Gas
Nuclear Uprates
2015
2,650
1,550
550
225
325
2014
2,525
1,375
550
225
375
2013
2,550
1,350
675
200
325
2012
(1)
2,200
1,400
400
200
200
Electric Distribution
Electric Transmission
Gas Delivery
Smart Grid/Smart Meter
(in $M)
(in $M)
(1) 2012 CapEx includes CEG and BGE from merger close date.
10
2012 EEI Conference 
Exelon Utilities
Exelon Generation

2012 Projected Sources and Uses of Cash
11
($ in Millions)
2012 EEI Conference 
(1)
Exelon beginning cash balance as of  12/31/11. Excludes counterparty collateral activity.
(2)
Includes $675 million of Constellation net collateral paid to counterparties prior to merger completion.
(3)
Cash Flow from Operations primarily includes net cash flows provided by operating activities, estimated proceeds from Maryland clean coal fleet divestitures and net cash flows used in
investing activities other than capital expenditures. 
(4)
Dividends are subject to declaration by the Board of Directors.
(5)
Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo. PECO’s A/R Agreement was extended in accordance with its terms through August 30, 2013.
(6)
“Other”
includes proceeds from options and expected changes in short-term debt.
(7)
Includes cash flow activity from Holding Company, eliminations, and other corporate entities.  Represents Constellation cash flows from merger close through December 31, 2012.
Beginning
Cash
Balance
(1)
$550
Cash
acquired
from
Constellation
(2)
150
n/a
n/a
1,375
1,650
Cash
Flow
from
Operations
(3)
250
1,175
900
3,475
5,825
CapEx (excluding other items below):
(425)
(1,225)
(350)
(975)
(3,050)
Nuclear Fuel
n/a
n/a
n/a
(1,150)
(1,150)
Dividend
(4)
(1,725)
Nuclear Uprates
n/a
n/a
n/a
(300)
(300)
Wind
n/a
n/a
n/a
(625)
(625)
Solar
n/a
n/a
n/a
(675)
(675)
Upstream
n/a
n/a
n/a
(75)
(75)
Utility Smart Grid/Smart Meter
(75)
(50)
(75)
n/a
(200)
Net Financing (excluding Dividend):
Debt
Issuances
(5)
250
350
350
775
1,725
Debt Retirements
(175)
(450)
(375)
(125)
(1,125)
Project Finance/Federal Financing Bank
Loan
n/a
n/a
n/a
375
375
Other
(6)
--
25
(25)
--
(100)
Ending Cash Balance
(1)
$1,100
(7)

Credit Metrics Support Investment-Grade Ratings
Moody’s Credit
Ratings
(1)(2)
S&P Credit
Ratings
(1)(2)
Fitch Credit   
Ratings
(1)(2)
FFO / Debt
Target
Range
Exelon Corp
Baa2
BBB-
BBB+
ComEd
A3
A-
BBB+
15-18%
PECO
A1
A-
A
15-18%
BGE
Baa1
BBB+
BBB+
15-18%
Generation
Baa1
BBB
BBB+
25-27%
(3)
(1)
Current senior unsecured ratings for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd and PECO as of
November 8, 2012.
(2)
On November 8, 2012 Moody’s affirmed the ratings of Exelon and Generation with a negative outlook, concluding their review for a
possible
downgrade.
ComEd,
PECO
and
BGE
ratings
have
a
stable
outlook
at
Moody’s.
All
ratings
at
S&P
and
Fitch
have
a
stable
outlook.
(3)
FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt obligations of Exelon Corp. Range represents
FFO/Debt to maintain current ratings at current business risk.
•
Committed to maintaining investment-grade ratings
•
2012-2015 credit metrics for Exelon Generation/HoldCo at or above target range
S&P target of 25-27% for Exelon Generation/HoldCo based on current market
conditions
12
2012 EEI Conference
Metrics sufficient to maintain investment-grade rating in 5-year financial plan

Credit Facility Update
•Achieving targeted facility reductions and associated synergies
$4.2B reduction in legacy CEG facilities (excluding BGE) on track by 12/31/12
$40M in annual cost savings beginning in 2013 ($35 million in 2012)
•
Amended and extended existing $7 billion in credit facilities for Exelon Corp, ExGen, PECO and
BGE
Anticipate ~$20M in savings over life of credit facilities
(1)
Includes Exelon Generation $5.3B revolver, legacy CEG $2.5B revolver, legacy CEG bilateral agreements of $1.7B, Exelon Corp $0.5B revolver and Exelon Generation $0.3B bilateral
agreement
$1.5
$6.1
$7.6
12/31/12
Termination of
legacy CEG revolver
9/30/12
Liquidity Reduced to Date
$2.7
Day 1 Merger Close
$10.3
(1)
Liquidity sizing supports commercial trading platform and provides ongoing
access to substantial liquidity
13
2012 EEI Conference 
Credit Facility (excluding utilities)

Pension and OPEB for Combined Company
Plan Design and Funding Strategy:
•
Plan funding strategies are summarized as follows:
For pension, contribute the minimum amounts required under ERISA, including amounts necessary to
avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006. For
Exelon’s
largest
pension
plan,
Exelon
expects
to
contribute
the
greater
of
$250M
or
the
minimum
amounts required under ERISA beginning annually in 2013.
OPEB plans are not subject to regulatory minimum contribution requirements. The contribution
strategy for Exelon’s OPEB plans is determined based on benefit claims paid and regulatory
implications (amounts deemed prudent to meet regulator expectations and best assure continued
recovery), while Constellation’s legacy plans are unfunded.
•
In July 2012, legislation was passed that provides pension funding relief for certain plans in the near term;
the impact of this legislation is included in the forecast and sensitivities.
•
During
the
third
quarter
of
2012,
Exelon
announced
certain
plan
design
changes
for
its
post-retirement
benefit plans. The changes are effective beginning in 2014 and their impact has been incorporated in the
forecast below.
Current Forecast:
•
The table below provides the combined company’s forecasted 2013 and 2014 pension and OPEB expense
and contributions.
(1)
Pension
and
OPEB
expenses
assume
an
~
24%
capitalization
rate.
(2)
Contributions shown in the table above are based on the current contribution policy for Exelon and Constellation plans.
(3)
Expected
return
on
assets
for
pension
is
7.50%
(2013)
and
7.0%
(2014).
Expected
return
on
assets
for
2013
-
2014
for
OPEB
is
6.68%.
Amounts
above
assume
Exelon
achieves
its
expected return on assets for pension and OPEB in 2012 of 7.50% and 6.68%, respectively.
(4)
Projected
12/31/12
pension
discount
rate
is
3.87%
(Exelon)
and
3.67%
(Constellation).
Projected
12/31/12
OPEB
discount
rate
is
3.96%
(Exelon)
and
3.69%
(Constellation).
14
2013
2014
(in $M)
Pre-Tax
Expense
(1)
Contributions
(2)
Pre-Tax
Expense
(1)
Contributions
(2)
Pension
(3)(4)
$430
$265
$455
$280
OPEB
(3)(4)
$240
$305
$225
$285
Total
$670
$570
$680
$565
2012 EEI Conference 

2013 Pension and OPEB Sensitivities
•
Tables below provide sensitivities for the combined company’s 2013 pension and OPEB expense and
contributions
(1)
under various discount rate and S&P 500 asset return scenarios
15
2013 Pension Sensitivity
(2) 
(in $M)
S&P Returns in Q4 2012
(3)
10%
0%
-10%
Discount Rate at
12/31/12
Pre-Tax
Expense
(1)
Contributions
(2)
Pre-Tax
Expense
(1)
Contributions
(2)
Pre-Tax
Expense
(1)
Contributions
(2)
Baseline Discount Rate
(4)
$400
$265
$420
$265
$440
$265
+50 bps
$365
$265
$385
$265
$405
$265
-
50bps
$445
$265
$465
$265
$485
$265
2013 OPEB Sensitivity
(2) 
(in $M)
S&P Returns in Q4 2012
(3)
10%
0%
-10%
Discount Rate at
12/31/12
Pre-Tax
Expense
(1)
Contributions
(2)
Pre-Tax
Expense
(1)
Contributions
(2)
Pre-Tax
Expense
(1)
Contributions
(2)
Baseline Discount Rate
(4)
$220
$275
$235
$295
$250
$315
+50 bps
$185
$235
$200
$255
$215
$275
-
50bps
$255
$320
$270
$340
$285
$360
2012 EEI Conference 
(1) Contributions shown in the table above are based on the current contribution policy for Exelon and Constellation plans and include the impact of pension funding relief.
(2) Pension and OPEB expenses assume an ~ 24% capitalization rate in 2013.
(3) Final 2012 asset return for pension and OPEB will depend in part on overall equity market returns for  Q4 2012 as proxied by the S&P 500.  The amounts above reflect
YTD S&P returns through September 30, 2012.
(4) The baseline discount rates reflect a projected 12/31/12 pension discount rate of 3.87% and 3.67% for Exelon and Constellation, respectively, and OPEB discount rate
of 3.96% and 3.69% for Exelon and Constellation, respectively.

2012 EEI Conference 
16
Additional 2012 ExGen and CENG Modeling
P&L Item
2012
Stub
(1)
Estimate
2012
Full-Year
(2)
Estimate
ExGen
Model
Inputs
(3)
O&M
(4)
$4,000M
$4,250M
Taxes Other Than Income (TOTI)
$300M
$300M
Depreciation
&
Amortization
(5)
$700M
$750M
Interest Expense
$300M
$350M
CENG Model Inputs
Gross Margin
Included in ExGen Disclosures
O&M
(6)
$350M
$450M
Depreciation
&
Amortization
(7)
$100M
$100M
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Stub period represents estimates for March 12 – December 31, 2012 and is reflected as part of ExGen’s 2012 earnings guidance.
Full-year estimates provided for modeling purposes.
ExGen amounts  for O&M, TOTI and Depreciation & Amortization exclude the impacts of CENG. CENG impact is reflected in “Equity earnings of 
unconsolidated affiliates” in the Income Statement.
ExGen O&M excludes decommissioning  costs and the impact from O&M related to entities consolidated solely as a result of the application of FIN 46R.
ExGen Depreciation & Amortization excludes the impact of decommissioning.
CENG O&M includes TOTI of $20M for stub estimate and $25M for full-year estimate.
CENG Depreciation & Amortization includes accretion expense.

Merger CapEx Synergies & Costs To Achieve
$100
2012
$55
2013
$70
$385
Capital
O&M
$70
$55
$35
2015+
2014
2013
2012
Run rate CapEx
synergies of
~$70M
2012 EEI Conference 
17
•
On track to achieve CapEx synergies in
2012 and beyond
•
Run rate CapEx synergies mainly driven
by:
Information Technology (IT) systems
consolidation
Supply Chain capital synergies
•
Costs to achieve excluded from
operating earnings
•
Key areas of costs to achieve:
IT systems consolidation
Transaction costs (banker, legal
costs, etc.)
Employee-related costs
CapEx Synergies ($M)
Costs to Achieve ($M)

Debt Maturity Schedule
600
2020
1,600
1,100
500
2019
2018
1,340
500
840
2017
1,166
700
425
41
2016
1,118
75
665
379
2015
1,685
550
260
800
75
2014
1,574
637
250
617
70
2013
1,019
300
252
467
2012
407
375
32
ExGen
(2)
PECO
ComEd
Exelon Corp
BGE
~64% of 2012 –
2016 debt maturities consist of regulated utility debt
(in $M)
Debt Maturity Profile
(1)
(2012-2020)
18
2012 EEI Conference 
(1)
As of 9/30/12
(2)
Includes $550M in 2015 and 2020 of inter-company loan agreements between Exelon and Exelon Generation that mirror the terms and amounts of the third party
obligations of Exelon.

GAAP to Operating Adjustments
19
2012 EEI Conference 
•
Exelon’s 2012 adjusted (non-GAAP) operating earnings outlook excludes the earnings effects of the
following:
Mark-to-market adjustments from economic hedging activities
Unrealized
gains
and
losses
from
nuclear
decommissioning
trust
fund
investments
to
the
extent
not
offset by contractual accounting as described in the notes to the consolidated financial statements
Financial impacts associated with the planned retirement of fossil generating units and the expected
sale in the fourth quarter of 2012 of three generating stations as required by the merger
Changes in decommissioning obligation estimates
Certain costs incurred related to the Constellation merger and integration initiatives
Costs incurred as part of Maryland commitments in connection with the merger
Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at
the merger date
Costs incurred as part of a March 2012 settlement with the Federal Energy Regulatory Commission
(FERC) related to Constellation’s prior period hedging and risk management transactions
Changes
in
state
deferred
tax
rates
resulting
from
a
reassessment
of
anticipated
apportionment
of
Exelon’s deferred taxes as a result of the merger
Non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in
2013
Certain costs incurred associated with other acquisitions
Significant impairments of assets, including goodwill
Other unusual items
Significant changes to GAAP
•
Operating
earnings
guidance
assumes
normal
weather
for
remainder
of
the
year

21
Commercial Business Overview
Scale, Scope and Flexibility Across the Energy Value Chain
Development and
exploration of natural gas
and liquids properties
12 assets in
seven
states
~295 BCFe of proved
Reserves
(1)
Leading merchant power
generation portfolio in the
U.S.
~35 GW of owned
generation capacity
(2)
Clean portfolio, well
positioned for evolving
regulatory requirements
Industry-leading wholesale
and retail sales and
marketing platform
~170 TWh of load and     
~420 BCF of gas delivered
(3)
~ 1 million residential and
100,000 business and
public sector customers
One of the largest and most
experienced Energy
Management providers
~1,800 MW of Load
Response under contract
(4)
Over 4,000
energy savings
projects implemented
across the U.S.
Benefiting from scale, scope and flexibility across the value chain
(1) Estimated
proved
reserves
as
of
12/31/2011.
Includes
Natural
Gas
(NG),
NG
Liquids
(NGL)
and
Oil.
NGL
and
Oil
are
converted
to
BCFe
at
a
ratio
of
6:1.
(2) Total owned generation capacity as of 9/30/2012, net of physical market mitigation (Brandon Shores, C.P. Crane and H.A. Wagner ~2,648 MW).
(3) Expected for 2012 as of 9/30/2012. Electric load and gas includes fixed price and indexed products. No stub period adjustment for legacy Constellation contribution.
(4) Load Response estimate as of 9/30/2012.
2012 EEI Conference
Upstream
Exploration
& Production
Power
Generation
Electric, Gas
Retail &
Wholesale
Beyond The
Meter

22
Commercial Business Transformation
PJM, wholesale marketing focus     
National, customer-facing business
Industry-leading retail platform and portfolio management expertise, combined
with one of the lowest cost and best managed generation fleets
Expand into
new markets
Cross sell new
products and
services
Benefit from
matching
generation and
load
Capital and
collateral
efficiency
Optimize
generation
assets/value
added forward
hedges
Leverage
relationships
with large
wholesale
customers
Monetize risk
management
expertise
~$8 billion in gross margin per year
Low-cost, geographically and technologically diverse generation fleet
Unparalleled upside to tightening energy and capacity markets 
2012 EEI Conference
Leading Merchant
Generation Fleet
Electric Load Serving
Business
Portfolio and Risk
Management

23
Generation and Load Match
We have already seen benefits across the portfolio this
summer:
•
Took advantage of large moves in summer heat 
rates  in ERCOT
—
Sold excess peaking generation at pre-
summer higher forward contract prices
—
Bought back below the cost of our units when
actual market heat rates dropped through
delivery
•
Sold load following products against our PJM
portfolio through our retail and wholesale load
channels
26
ERCOT
New England
14
30
New York
43
MidAtlantic
116
MidWest
118
Peaking
Intermediate
Baseload
Renewables
The combination establishes an industry-leading platform with regional
diversification of the generation fleet and customer-facing load business
Generation Capacity, Expected Generation and Expected Load 
2013 in TWh
(1,2)
Expected Load
Expected Generation
Generation capacity
2012 EEI Conference
15
11
6
12
17
14
17
18
48
75
25
97
South/West/
Canada
(1)
Owned and contracted generation capacity converted from MW to MWh assuming 100% capacity factor for all technology types, except for renewable capacity which is shown at estimated capacity factor.
(2)
Expected generation and load shown in the chart above will not tie out with load volume and ExGen disclosures. Load shown above does not include indexed products and generation reflects a net owned  
and contracted position. Estimates as of 9/30/2012.
Generation & Load Match: Competitive Advantage
Now able to sell closer to our generation
locations reducing risk associated with
locational pricing
—
Generation dispatched due to high summer
delivered heat rates and helped serve higher
loads from the hot weather
—

Minimum Offer Price Rules (MOPR) Update
24
PJM is proposing modifications to the MOPR to ensure uneconomic generation does not
distort market
•
Restructured MOPR
MOPR to apply to all new gas-fired and IGCC units in PJM, with limited exceptions
MOPR exemption to be available only to self-supply entities and competitive market
entrants
MOPR
floor
to
apply
for
three
years,
set
at
100%
of
the
net
cost
of
new
entry
•
Implementation/Timing
PJM currently reviewing restructured MOPR with all stakeholders
PJM expected to file for FERC approval by November 30, 2012
Exelon, other generators, and other stakeholders to support PJM’s filing
FERC approval expected in early February, 2013
PJM RPM
Auction
2015/16 –
May 2012
Stakeholder
Discussions -
Summer 2012
FERC Filing –
November  30, 2012
PJM RPM
Auction
2016/17 –
Spring 2013
FERC Ruling –
February 1, 2013
Note: IGCC = Integrated Gasification Combined Cycle.  FERC = Federal Energy Regulatory Commission.  RPM= Reliability Pricing Model.
2012 EEI Conference

Capacity Markets
25
2011/
2012
2012/
2013
2013/
2014
2014/
2015
2015/
2016
PJM
(3,8)
RTO 
Capacity
27,400
12,800
11,500
11,500
11,500
Price
$110
$16
$28
$126
$136
EMAAC
Capacity
(4)
9,100
9,100
9,100
9,100
Price
$140
$245
$137
$168
MAAC 
Capacity
2,600
2,700
2,700
2,700
Price
$133
$226
$137
$168
SWMAAC
Capacity
(5)
1,800
1,800
1,800
1,800
Price
$133
$226
$137
$168
Average Exelon
$110
$78
$142
$132
$153
New England
(6)
NEMA  
Capacity
2,100
2,100
2,100
2,100
2,100
Price
$104
(7)
$85
(7)
$85
(7)
$107
$114
SEMA
Capacity
35
35
35
35
35
Price
$104
(7)
$85
(7)
$85
(7)
$95
(7)
$104
(7)
Rest of Pool   Capacity
700
700
700
700
700
Price
$104
(7)
$85
(7)
$85
(7)
$95
(7)
$104
(7)
NYISO
(8)
Rest of Pool   Capacity
1,100
1,100
1,100
1,100
1,100
MISO
(9)
AMIL 
Capacity
1,100
1,100
1,100
1,100
1,100
2012 EEI Conference
PJM RPM Capacity Revenues
$-
$200
$400
$600
$800
$1,000
$1,200
$1,400
$-
$20
$40
$60
$80
$100
$120
$140
$160
2012
2013
2014
2015
$97
$105
$138
$141
Exelon
fleet
weighted
average
price
($/MWd)
(2)
Revenue ($MM)
(1)
(1)
Revenues reflect capacity cleared in base and incremental auctions and are for calendar years.
Revenue rounded to nearest $50M.
(2)
Weighted average $/MW-Day would apply if all owned generation cleared.
(3)
Reflects owned and contracted generation Installed Capacity (ICAP) adjusted for mid-year PPA roll
offs.
(4)
ICAP is net of Eddystone 1&2, Cromby 1&2 and Schuykill 1 (total ~ 1,100 MW).
(5)
ICAP is net of units to be divested (Brandon Shores, Wagner & Crane ~2,648 MW; Constellation
offered these units in PY11/12 - PY 15/16 auctions) and Riverside 6 CT (~115MW).
(6)
Reflects Qualified Summer Capacity including owned and contracted units.
(7)
Price is pro-rated for auctions that clear at the floor price and there is more capacity procured
than suggested by the reliability requirement.
(8)
Reflects 50.01% ownership in CENG.
(9)
Does not include wind under PPA.
RTO = Regional Transmission Organization, MAAC = Mid-Atlantic Area Council, EMAAC = Eastern
Mid-Atlantic Area Council, SWMAAC = South West Mid-Atlantic Area Council, NEMA = North East
Massachusetts; SEMA = North East Massachusetts, AMIL = Ameren Illinois.

26
Retail and Wholesale Gas
Retail Gas
(1)
(2011 –
2015 Bcf)
+18%
+14%
480
465
420
Contribution from ONEOK Energy
Marketing Company acquisition
(1)
Estimate as of 9/30/2012.
Portfolio Size:
•
420 Bcf expected to be served in 2012
•
Month by month renewals, with high renewal rates
Market Potential:
•
All states are competitive markets with an estimated
total market size of 15,000 Bcf, of which 7,000 Bcf is
currently switched
Growth Strategy and Objectives:
•
Looking to grow Northeast gas markets as well as
recently acquired ONEOK territories
Portfolio Size:
•
5 Bcf wholesale storage
•
300,000 MMBtu’s per day of term transport
•
Over 1 Bcf/day of plant supply
Growth Strategy and Objectives:
•
Expand wholesale presence to complement power
assets
•
Increase market knowledge of regional and basis
transport information to assist power forecasting
495
2012 EEI Conference
385
0
50
100
150
200
250
300
350
400
450
500
550
2011A
2012E
2013E
2014E
2015E
Retail Gas
Wholesale Gas

27
(1)
Oil/NGL conversion to gas is 6:1.
(2)
Constellation does not operate any of its properties.
Note: E&P =  Exploration and Production.
Upstream E&P Assets
Estimated Net Proved
Reserves
(as of 12/31/11)
Average Net Daily
Production
(Q2 2012)
295 Bcfe
60.3 MMcfe
•
Our Upstream Gas business achieves strong returns
(>12% IRR)
•
$150m (~50% utilized) Reserve Based Lending (RBL)
facility in place
—
Receives off-balance sheet treatment from S&P
•
Provides
valuable
market
intelligence
in
complex
natural gas markets
Forecasted Production
2012
2013
2014
2015
Net Daily Prod
(MMcfe / day)
55 -
70
55 -
70
60 -
75
60 -
75
2012 EEI Conference
Mississippi lime (OK)
Hunton dewatering (OK)
Woodford shale (OK)
Eagle Ford shale (TX)
Fayetteville shale (AR)
Haynesville shale (LA)
Floyd shale (AL)
Ohio shale (OH)
Woodbine shale (TX)
Trenton Black River (MI)
Current Portfolio Of Investments
Investment Thesis

28
Exelon Generation Disclosures
September 30, 2012
(As disclosed in Third Quarter 2012 Earnings Materials)
2012 EEI Conference

29
Portfolio Management Strategy
Protect Balance Sheet
Ensure Earnings Stability
Create Value
Exercising Market Views
Purely ratable
Actual hedge %
Market views on timing, product
allocation and regional spreads
reflected in actual hedge %
High End of Profit
Low End of Profit
% Hedged
Open Generation
with LT Contracts
Portfolio Management &
Optimization
Portfolio Management Over Time
Align Hedging & Financials
Establishing Minimum Hedge Targets
2012 EEI Conference
Credit Rating
Capital &
Operating
Expenditure
Dividend
Capital
Structure
Strategic Policy Alignment
•Aligns hedging program with financial
policies and financial outlook
•Establish minimum hedge targets to
meet financial objectives of the
company (dividend, investment-grade
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

30
Components of Gross Margin Categories
Margins move from new business to MtM of hedges over
the course of the year as sales are executed
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
2012 EEI Conference
•Generation Gross
Margin at current
market prices,
including capacity &
ancillary revenues,
nuclear fuel
amortization and
fossils fuels expense
•Exploration and
Production
•PPA Costs &
Revenues
•Provided at a
consolidated level
for all regions
(includes hedged
gross margin for
South, West &
Canada
(1)
)
•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 EREP,
reference price,
hedge %, expected
generation
•Retail, Wholesale
planned electric
sales
•Portfolio
Management new
business
•Mid marketing new
business
•Retail, Wholesale 
executed gas sales
•Load Response
•Energy Efficiency
•BGE Home
•Distributed Solar
•Retail, Wholesale
planned gas sales
•Load Response
•Energy Efficiency
•BGE Home
•Distributed Solar
•Portfolio
Management /
origination fuels new
business
•Proprietary
trading
(3)
Open Gross
Margin
MtM of
Hedges
(2)
“Power”
New
Business
“Non Power”
Executed
“Non Power”
New Business
(1)  Hedged gross margins for South, West & Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region.
(2)  MtM of hedges provided directly for the five larger regions. MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh.
(3)  Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non power” executed category.

31
ExGen Disclosures 
2012 EEI Conference
Gross Margin Category ($M)
(1,2)
2012
(3)
2013
2014
2015
Open Gross Margin
(including South, West & Canada hedged GM)
(4,5)
$4,500
$5,750
$6,050
$6,200
Mark to Market of Hedges
(5,6)
$3,200
$1,350
$500
$250
Power New Business / To Go
$50
$500
$750
$950
Non-Power Margins Executed
$300
$150
$100
$50
Non-Power New Business / To Go
$100
$450
$500
$550
Total
Gross
Margin
$8,150
$8,200
$7,900
$8,000
Reference Prices
(7)
2012
2013
2014
2015
Henry Hub Natural Gas ($/MMbtu)
$2.77
$3.84
$4.18
$4.37
Midwest: NiHub ATC prices ($/MWh)
$28.95
$30.59
$31.34
$32.32
Mid-Atlantic: PJM-W ATC prices ($/MWh)
$33.93
$38.24
$39.44
$40.77
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$3.67
$8.37
$8.30
$7.15
New York: NY Zone A ($/MWh)
$30.85
$35.19
$35.98
$36.55
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$6.72
$4.42
$3.79
$4.07
(4)
Excludes Maryland assets to be divested.
(5)
Includes CENG Joint Venture.
(6)
Mark to Market of Hedges assumes mid-point of hedge percentages.
(7)
Based on September 30, 2012 market conditions.
(1)
Gross margin does not include revenue related to decommissioning, Exelon Nuclear Partners
and entities consolidated solely as a result of the application of FIN 46R.
(2)
Gross margin rounded to nearest $50M.
(3)
Stub period calculated by excluding Jan 2012 through mid-March 2012 for Constellation
only.

32
ExGen Disclosures
Generation and Hedges
2012
(1)
2013
2014
2015
Exp. Gen (GWh)
(4)
219,500
218,700
211,400
209,800
Midwest
100,700
97,400
97,500
99,000
Mid-Atlantic
(2,3)
71,800
75,000
72,200
71,800
ERCOT
19,900
18,500
16,900
15,800
New York
(3)
13,000
13,800
10,900
9,300
New England
14,100
14,000
13,900
13,900
% of Expected Generation Hedged
(5)
99-102%
88-91%
56-59%
21-24%
Midwest
99-102%
89-92%
56-59%
20-23%
Mid-Atlantic
(2,3)
99-102%
88-91%
57-60%
24-27%
ERCOT
96-99%
78-81%
53-56%
28-31%
New York
(3)
98-101%
92-95%
61-64%
15-18%
New England
97-100%
89-92%
51-54%
11-14%
Effective Realized Energy Price ($/MWh)
(6)
Midwest
$42.00
$38.00
$35.00
$34.50
Mid-Atlantic
(2,3)
$56.00
$48.00
$47.50
$50.50
ERCOT
7
$9.00
$7.50
$5.00
$5.00
New York
(3)
$44.00
$36.00
$35.00
$52.00
New England
(7)
$8.00
$7.00
$4.00
$5.00
2012 EEI Conference
(1) Stub period calculated by excluding Jan 2012 thru mid-March 2012 for Constellation only. (2) Excludes Maryland assets to be divested (3) Includes CENG Joint Venture. (4) Expected
generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity.  Expected generation is 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 10
refueling outages in 2012 and 2013 and 11 refueling outages in 2014 and 2015 at Exelon-operated nuclear plants and Salem but excludes CENG.  Expected generation assumes capacity
factors of 92.8%, 93.5%, 93.8%, and 93.3% in 2012, 2013, 2014 and 2015 at Exelon-operated nuclear plants excluding Salem and CENG. These estimates of expected generation in 2012,
2013, 2014 and 2015 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.  (5) 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. Uses
expected value on options. (6) 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. (7) Spark spreads shown for ERCOT and New England.

33
ExGen Hedged Gross Margin Sensitivities
Gross Margin Sensitivities (With Existing Hedges) 
(1, 4)
2012
2013
2014
2015
Henry Hub Natural Gas ($/MMbtu)
(2)
$(5)
$55
$400
$780
$25
$(15)
$(325)
$(700)
NiHub ATC Energy Price
$(5)
$40
$230
$390
$5
$(35)
$(230)
$(385)
PJM-W ATC Energy Price
(2)
$(5)
$50
$165
$295
$5
$(40)
$(160)
$(285)
NYPP Zone A ATC Energy Price
$5
$15
$35
$45
$(5)
$(15)
$(35)
$(45)
Nuclear Capacity Factor
(3)
+/-
1%
+/-
$10
+/-
$40
+/-
$45
+/-
$45
2012 EEI Conference
(1) Based on September 30, 2012 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. (2) Excludes Maryland assets to be divested. (3) Includes CENG Joint Venture (4) Sensitivities based on commodity exposure 
which includes open generation and all committed transactions.
+ $1/MMbtu
-
$1/MMbtu
+ $5/MWh
-
$5/MWh
+ $5/MWh
-
$5/MWh
+ $5/MWh
-
$5/MWh

34
Exelon Generation Hedged Gross Margin Upside/Risk
$8,200
$8,100
$8,500
$7,850
$8,950
$7,150
2012 EEI Conference
6,000
6,500
7,000
7,500
8,000
8,500
9,000
9,500
10,000
10,500
11,000
2012
2013
2014
2015
$11,050
$6,350
(1) Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold
into the spot market.  Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential
modeling changes. These ranges of approximate gross margin in 2013, 2014 and 2015 do not represent earnings guidance or a forecast of future results as Exelon has not completed its
planning or optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of
September 30, 2012 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. (3) Excludes Maryland assets to be divested

35
Illustrative Example of Modeling Exelon Generation             
2013 Gross Margin
Row
Item
Midwest
Mid-
Atlantic
ERCOT
New
England
New York
South,
West &
Canada
(A)
Start with fleet-wide open gross margin 
$5.75 billion
(B)
Expected Generation (TWh)
97.4
75.0
18.5
14.0
13.8
(C)
Hedge % (assuming mid-point of range)
90.5%
89.5%
79.5%
90.5%
93.5%
(D=B*C)
Hedged Volume (TWh)
88.2
67.1
14.7
12.7
12.9
(E)
Effective Realized Energy Price ($/MWh)
$38.00
$48.00
$7.50
$7.00
$36.00
(F)
Reference Price ($/MWh)
$30.59
$38.24
$8.37
$4.42
$35.19
(G=E-F)
Difference ($/MWh)
$7.41
$9.76
($0.87)
$2.58
$0.81
(H=D*G)
Mark-to-market
value
of
hedges
($
million)
(1)
$655 million
$655 million
($15) million
$35 million
$10 million
(I=A+H)
Hedged Gross Margin ($ million)
$7,100 million
(J)
Power New Business / To Go ($ million)
$500 million
(K)
Non-Power Margins Executed ($ million)
$150 million
(L)
Non-
Power New Business / To Go ($ million)
$450 million
(N=I+J+K+L)
Total Gross Margin
$8,200 million
(1) Mark-to-market rounded to the nearest $5 million. 
2012 EEI Conference

36
Constellation Energy Nuclear Group (CENG) Background
As a result of Exelon’s equity interest in CENG, CENG gross margins and earnings are reflected in ExGen disclosures
and
other
financial
statements.
The
following
is
information
related
to
PPA
contracts
between
CENG
and
3rd
parties and the PPA between CENG and its equity parents.
Calvert 1&2
NMP 1
NMP 2
(1)
Ginna
(2)
Ownership Interest
Total Plant Capacity
1,705 MW
620 MW
1,138 MW
581 MW
Ownership Split
100% CENG
100% CENG
82% CENG / 18% LIPA
100% CENG
ExGen Ownership (50.01% of CENG)
852.5 MW
310 MW
466.5 MW
290.5 MW
PPA structure (% output)
CENG Legacy PPA with Utilities
-
-
See footnote 1
90%
< June 2014
0%
> June 2014
CENG PPA with Parents
100%
100%
100%
10%
< June 2014
100%
> June 2014
CENG PPA with Parents
5 year
contract
extendable
at
end
of
each
year
for
additional
year
-
Market
based
pricing
and
monthly,
rolling
3
year
hedge
profile
(100%,
60%,
30%)
2012
2013
2014
2015
(%  of uncommitted output)
EDF Trading
15
15
15
N.A.
ExGen
85
85
85
N.A.
2012 EEI Conference
(1) Nine Mile Point 2 (NMP) has a revenue sharing agreement (via a call option type contract) on 80% of the output.
(2) Ginna Legacy PPA at $44/MWh; CENG PPA with parents (ExGen, EDF) at close to market prices and designed to maintain a monthly ratable profile for CENG.

37
Constellation Energy Nuclear Group (CENG) Background
2012 EEI Conference
ExGen Disclosures
Forward Estimates
•ExGen forward disclosures reflect the gross position that
accrues to ExGen from ownership interest in CENG and
PPA with CENG as of a certain date
•Open Gross Margin: Reflects proportionate share of
CENG revenues and fuel costs, market value of PPA less
PPA costs paid by ExGen to CENG
•MtM
of Hedges: Reflects MtM
of any hedges placed by
ExGen for managing position arising from ownership
interests or PPAs with CENG
•Expected Generation: Reflects proportionate ownership
in CENG and generation associated with PPA between
CENG and ExGen.
•Hedge Percentage: Reflects hedges placed by ExGen to
hedge exposure arising from CENG position (owned or
contracted)
•Effective Realized Energy Price: Reflects MtM
and
hedges from CENG position (owned or contracted)
Financial Statements
(10-Q, 10-K, Earnings Release tables)
Actuals
•ExGen actuals
reflect equity method accounting
treatment for ownership interest  in CENG and regular
treatment for PPA between ExGen and CENG.
•RnF:  Includes net PPA gross margin (revenues less
costs) between ExGen and CENG. CENG earnings or
gross margin are not included, and are instead shown
under “CENG equity earnings”
on the income statement.
•Total Supply: Includes only the generation corresponding
to the PPA between ExGen and CENG.
•Average Margins ($/MWh): Includes only margins
corresponding to PPA between ExGen and CENG as well
as any hedges placed by ExGen

Exelon Utilities

ComEd Distribution Rate Case Overview
2011
Formula
Rate
Filing
(Docket
#
11-0721
filed
11/8/11;
2010
test
year
costs,
2011
plant
additions,
rates
eff.
June
2012
–
Dec
2012):
•
Based on 2010 calendar year costs and 2011 net plant additions
•
Supported $59M distribution revenue requirement reduction
•
10.05% ROE (2010 Treasury yield of 4.25% + 580 basis point risk premium)
ICC Final Order (issued 5/30/12):
•
$168M reduction to revenue requirement; incremental reduction includes:
~$50M related to costs ICC determined should be recovered through alternative rate recovery tariffs or reflected in reconciliation proceeding;
primarily delays timing of cash flows
~$35M reflects disallowance of return on pension asset
~$10M reflects incentive compensation related adjustments
~$15M reflects various adjustments for cash working capital, operating reserves and other technical items
ICC Re-hearing Order (issued 10/3/12) on pension asset, interest rate on reconciliation and average rate base
•
Granted $35M of prior disallowance related to pension, reflecting an updated total reduction to revenue requirement of $133M
Upheld the average rate base decision
Order also revised the decision on interest on reconciliation balances, granting a rate equal to the short term debt rate
•
ComEd filed a notice of appeal with the First Appellate Court on 10/4/12 and a motion to expedite on 10/10/12.  The motion to expedite was
denied, therefore, initial briefs are due on 12/13/12.
2012 Formula Rate Filing (Docket # 12-0321 filed 4/30/12, 2011 test year costs, 2012 projected plant additions, rates eff. Jan 2013 –
December 2013)
•
2012 plan year based on 2011 actual costs and 2012 net plant additions
9.71% ROE (2011 Treasury yield of  3.91% + 580 basis point risk premium)
•
Reconciled 2011 revenue requirements in effect to 2011 actual costs incurred
9.81%
ROE
(3.91%
plus
590
basis
point
risk
premium)
(1)
•
When factoring in 5/30/12 Order and 10/3/12 Re-hearing Order for #11-0721, ComEd proposes a $74M increase to distribution revenue
requirement
•
Received staff and intervener direct testimony on 7/17/12 and rebuttal testimony on 9/11/12
•
ICC order by 12/26/12; rates effective January 2013
Summary of Filings
(1)  590 basis point premium applies only to 2011 revenue reconciliation. All subsequent revenue reconciliations will assume a 580 basis point premium.
39
2012 EEI Conference

40
BGE Rate Case (Updated to reflect 10/22/12 filing)
Rate
Case
Request
(1)
Electric
Gas
Docket #
9299
Test Year
October 2011 –
September 2012
Common Equity Ratio
48.4%
Requested Returns
ROE: 10.5%; ROR: 7.96%
Rate Base
$2.7B
$1B
Revenue Requirement Increase
$131M
$45M
Proposed Distribution Price
Increase as % of overall bill
4%
6%
Timeline
•10/22/12: Update 8 months actual/4 month estimated test period data with actuals for last 4 months
(June-Sept. 2012)
•11/9/12: BGE and staff/intervenors file rebuttal testimony
•11/20/12:
Staff/Intervenors
and
BGE
file
surrebuttal
testimony
•12/3/12 –
12/18/12: Hearings
•1/11/13: Initial Briefs
•1/23/13: Reply Briefs
•2/23/13: Decision
•New rates are in effect shortly after the decision
2012 EEI Conference
Initial filing on 7/27/12 used 8 months of actuals and 4 months of projections for October 2011 – September 2012 time period and requested an ROR of 8.02%, electric 
revenue increase of $151M and gas revenue increase of $53M.  Rate base, equity ratio and ROE have not changed materially since the 7/27/12 filing.
(1)

41
ComEd Load
2012 EEI Conference
2012E
-0.3%
-0.2%
-0.6%
-0.3%
1.7%
2011
0.6%
-0.8%
-1.3%
-0.5%
1.4%
GMP
Large C&I
Small C&I
Residential
All Customers
Driver or
Indicator
2013 Outlook
Gross Metro
Product (GMP)
1.5% growth in GMP, which reflects a slow
growth economy
Employment
1.3% increase in total employment is expected
for 2013.
Manufacturing
Manufacturing employment is expected to grow
2.0% in 2013, which is consistent with the
growth in 2011 and 2012.
Households
Household formations is expected to increase
0.4% in 2013.  This is slightly better than the
0.3% growth expected for 2012.
Energy
Efficiency
Continued expansion of EE programs with ~ 1%
reduction in usage in 2013.
Notes: 2012 data is not adjusted for leap year.  Source of 2013 economic outlook data is Global Insight (July 2012).
Slow growth economy and energy efficiency initiatives will continue to impact
load growth
Weather-Normalized Load YoY Growth
Economic Forecast of Drivers that Influence Load

42
PECO Load
2012E
-2.4%
-3.5%
-2.0%
-2.4%
1.9%
2011
-3.3%
-0.7%
1.7%
-0.9%
0.5%
GMP
Large C&I
Small C&I
Residential
All Customers
Driver or
Indicator
2013 Outlook
Gross Metro
Product (GMP)
GMP projected to grow at 1.8% for
2013, vs. pre-recession average of
2.5%
Employment
Resident Employment outlook is
1.3% in 2013 vs. 1.0% in 2012
Manufacturing
Manufacturing employment is
expected to grow at 1.0%.
Philadelphia has had negative growth
from 2000 to 2011.
Households
Household growth is expected to be
0.3%, the same as the last three
years.
Energy
Efficiency
Energy Efficiency impact forecasted
to be  ~1% reduction in usage in
2013.
Improvements at oil refineries will be partially offset by on-going energy efficiency
initiatives
2012 EEI Conference
Notes: 2012 data is not adjusted for leap year.  Source of 2013 economic outlook data is Global Insight (July 2012).
Weather-Normalized Load YoY Growth
Economic Forecast of Drivers that Influence Load

43
BGE Load
2012E
-0.6%
-3.1%
-1.2%
-2.2%
1.7%
2011
2.0%
0.8%
-4.3%
-1.1%
1.0%
GMP
Large C&I
Small C&I
Residential
All Customers
Driver or
Indicator
2013 Outlook
Gross Metro
Product (GMP)
GMP is projected to grow at 1.5% for
2013.
Employment
1.0% growth projected. BGE’s
decoupled non-rate case revenue
growth is primarily driven by customer
growth.  The main driver for customer
growth is employment.
Manufacturing
Manufacturing employment is expected
to be fairly flat to 2012 levels in 2013
Personal Income
Projected to grow at 1.7%
Energy Efficiency
Continued expansion of EE programs
will offset any growth seen due to
improvements in economic conditions.
2013 is expected to be another transition year for the Baltimore
economy with
continued slow growth projected combined with the shutdown of RG
Steel
2012 EEI Conference
Notes: 2012 data is not adjusted for leap year.  Source of 2013 economic outlook data is Global Insight (July 2012).
Weather-Normalized Load YoY Growth
Economic Forecast of Drivers that Influence Load 

44
Exelon Utilities: Rate Base and ROE Targets
2012E
Long-Term Target
Equity Ratio
~49%
~53%
(4)
Earned ROE
4 -
5%
(5)
2012E
Long-Term Target
Equity Ratio
~45%
~53%
(2)
Earned ROE
8 -9%
Continued investment in Utilities will provide stable earnings growth
Based on 30-yr.
US Treasury
(3)
($ in billions)
$1.1
$0.7
$1.1
2012E
$5.1
$3.3
$0.7
$5.6
$3.6
2015E
$1.2
$0.8
$1.2
2013E
$5.2
$3.4
2014E
$5.5
$3.6
$0.7
Electric Distribution
Electric Transmission
Gas Delivery
$2.1
$7.2
$2.7
2014E
$8.6
$6.7
$2.5
2013E
$9.2
$6.4
$9.9
$6.1
2015E
$8.2
$2.2
2012E
Transmission
Distribution
$4.6
$2.8
$0.6
$4.1
$0.7
$1.0
$1.0
2013E
$2.7
2014E
$0.6
$0.9
$2.6
$4.3
2012E
$4.8
2015E
$1.0
$2.9
$0.8
Electric Distribution
Gas Delivery
Electric Transmission
=10%
(1)
ComEd distribution rate base represents an average and transmission rate base represents
end of year; PECO rate base represents end-of-year; and BGE rate base represents a trailing
13-month average.  Numbers may not add due to rounding.
(2)
Equity component for distribution rates will be the actual capital structure adjusted for
goodwill.
(3)
Earned ROE will reflect the weighted average of 11.5% allowed transmission ROE and
distribution ROE resulting from 30-year Treasury plus 580 basis points for each calendar year.
2012 EEI Conference
(4)
Per MDPSC merger commitment, BGE is precluded from paying dividends through 2014.
Per MDPSC orders, BGE cannot pay out a dividend to its parent company if said dividend
would cause BGE’s equity ratio to fall below 48%.
(5)
ROE
represents
full
year
of
2012
earnings
and
therefore
includes
activity
prior
to
the
merger close in March 2012.
(1)
2012E
Long-Term Target
Equity Ratio
~55%
~53%
Earned ROE
11.5 –
12.5%
=10%

45
Capital Expenditures
($ in millions)
2014E
$475
2015E
$50
$125
$50
$250
$575
$275
$150
2012E
$425
$50
$100
2013E
$525
$250
$125
$50
$100
$175
$100
$75
$75
Gas Delivery
Electric Transmission
Electric Distribution
Smart Meter/Smart Grid
(1)
2015E
$1,575
$1,000
$250
$325
2014E
$1,325
$850
$125
$350
2013E
$1,400
$825
$100
$475
2012E
$1,275
$925
$50
$300
2015E
$600
$300
$25
$175
$100
2014E
$625
$250
$275
$100
2013E
$100
$125
$150
$625
$150
$100
2012E
(2)
$575
$325
$75
$50
$125
(1)
Smart Meter/Smart Grid CapEx net of proceeds from U.S. Department of Energy (DOE) grant. For BGE, includes CapEx from Smart Energy Savers program of ~$10M per year.
(2)
Represents 2012 full year CapEx; estimated 2012 CapEx from merger close date totals $500M.
2012 EEI Conference

46
Smart Meter / Smart Grid Update
Investments will provide customer operational and reliability benefits
(1)
The $200M DOE grant was the maximum allowable under the Smart Grid Investment Grant Program.
2012 EEI Conference
•Installation of nearly 4M smart electric meters delayed to Q1 2015
pending order on rehearing
•Smart Grid program to include distribution automation device
installations and substation modernization upgrades
•ComEd Innovation Corridor will provide a “Test Bed” for smart grid
technologies to be demonstrated within a utility scale environment   
•Investment recovered through distribution formula rate
ComEd will invest ~$1.3B over
the next 10 years
•Installation of more than 1.8M smart electric meters began Q1 2012
•Plans to file request with PAPUC to accelerate deployment completion
by 2014
•Awarded $200M under the DOE program
(1)
, lowering net cost to
customers to ~$450M
•Investment recovered through surcharge mechanism with 10% ROE
PECO will invest up to $650M
through 2014
•Installation of 2M smart electric and gas meters began in April 2012
•A customer web portal and dynamic pricing (Peak Time Rebates) as
the default tariff
•Awarded $200M under the DOE program
(1)
, lowering net cost to
customers to ~$300M
•Cost recovery on project pending until cost-effectiveness showing at
the end of deployment
BGE will invest up to $500M 
through 2015

47
PECO –
Default Service Plan Filing (DSP II)
(1)
FR = Full Requirements; (2) FPFR = Fixed-Price Full Requirements
Retention as of:  October 9, 2012
Proposed Procurement Mix
Class
DSP I (1/1/11 –
5/31/13)
DSP II (6/1/13 –
5/31/15)
Large C&I
Current load retained:
3%
•
100% spot-priced FR
(1)
products
•
2011 opt-in FPFR
(2)
product
•
100% spot-priced FR products
Medium
Commercial
Current load retained:
17%
•
85% 1-year FPFR products, 15% spot-priced FR products
•
100% 6-month FPFR products
Small
Commercial
Current load retained:
42%
•
70% 1-year FPFR products, 20% 2-year FPFR products,
10% spot-priced FR products
•
100% 1-year FPFR products
Residential
Current load retained:
70%
•
45% 2-year FPFR products; 30% 1-year FPFR products;
targeted 20% block products of 1-yr, 2-yr, 5-yr and
seasonal terms; targeted 5% spot market purchases
•
As block products expire, block and spot is replaced by FPFR
products with terms ending 5/31/15 (end of DSP II period)
•
Remainder of portfolio is a mix of 2-yr and 1-yr FPFR
products, with delivery periods overlapping on a semi-annual
basis
•
On 1/13/12, PECO filed a new Default Service Plan with the PAPUC, which outlines how PECO will purchase electricity for
customers not purchasing from a competitive generation supplier from 6/1/13 through 5/31/15
•
PA PUC entered an Opinion and Order on October 12, 2012
PA PUC order:
•
Directs PECO to develop a plan by 1/1/14 to allow Customer Assistance Program (CAP) customers to select an Electric Generation
Supplier (EGS)
•
Provides for some changes to PECO’s Retail Market Enhancements (Opt-In and Customer Referral programs)
•
Directs PECO, EGSs, and interested parties to submit a plan within 60 days to address how participating EGSs will pay for Retail
Market Enhancements
2012 EEI Conference

48
BGE –
Standard Offer Service
•
BGE provides Standard Offer Service (SOS) as fixed seasonal rates for those electric customers who are not shopping.  The
costs
of
providing
this
service
are
recovered
from
customers
via
an
Administrative
Charge
included
in
the
SOS
rate.
The
Administrative Charge and the Energy & Transmission components of the SOS Rate are subject to periodic true-ups.  BGE
procures the majority of energy for this product via Full Requirements load auctions as ordered by the MDPSC.  See table
below:
(1)
FPFR = Fixed-Price Full Requirements
Retention as of: September  30, 2012
Procurement Mix
Class
6/1/12 –
5/31/13
6/1/13 –
5/31/14
Large C&I
(Hourly)
Current load retained:
7%
•
100% of supply procured directly from the PJM spot
market
•
100% of supply procured directly from the PJM spot
market
Medium
Commercial
(Type II)
Current load retained:
38%
•
100% 3-month FPFR
(1)
products
•
Auction
Apr
’12
for
Jun
’12
–
Aug
’12
•
Auction
Jun
’12
for
Sep
’12
–
Nov
’12
•
Auction
Oct
’12
for
Dec
’12
–
Feb
’13
•
Auction
Jan
’13
for
Mar
’13
–
May
’13
•
100% 3-month FPFR products
•
Auction
Apr
’13
for
Jun
’13
–
Aug
’13
•
Auction
Jun
’13
for
Sep
’13
–
Nov
’13
•
Auction
Oct
’13
for
Dec
’13
–
Feb
’14
•
Auction
Jan
’14
for
Mar
’14
–
May
’14
Small
Commercial
(Type I)
Current load retained:
63%
•
25% 2-year FPFR products
•
Auction
Apr
’10
for
Oct
’10
–
Sep
’12
•
Auction
Oct
’10
for
Jun
’11
–
May
’13
•
Auction
Apr
’11
for
Oct
’11
–
Sep
’13
•
Auction
Oct
’11
for
Jun
’12
–
May
’14
•
Auction
Apr
’12
for
Oct
’12
–
Sep
’14
•
25% 2-year FPFR products
•
Auction
Apr
’11
for
Oct
’11
–
Sep
’13
•
Auction
Oct
’11
for
Jun
’12
–
May
’14
•
Auction
Apr
’12
for
Oct
’12
–
Sep
’14
•
Auction
Oct
’12
for
Jun
’13
–
May
’15
•
Auction
Apr
’13
for
Oct
’13
–
Sep
’15
Residential
Current load retained:
74%
•
25% 2-year FPFR products
•
Auction
Apr
’10
for
Oct
’10
–
Sep
’12
•
Auction
Oct
’10
for
Jun
’11
–
May
’13
•
Auction
Apr
’11
for
Oct
’11
–
Sep
’13
•
Auction
Oct
’11
for
Jun
’12
–
May
’14
•
Auction
Apr
’12
for
Oct
’12
–
Sep
’14
•
25% 2-year FPFR products
•
Auction
Apr
’11
for
Oct
’11
–
Sep
’13
•
Auction
Oct
’11
for
Jun
’12
–
May
’14
•
Auction
Apr
’12
for
Oct
’12
–
Sep
’14
•
Auction
Oct
’12
for
Jun
’13
–
May
’15
•
Auction
Apr
’13
for
Oct
’13
–
Sep
’15
2012 EEI Conference

49
Regulatory Schedule
4Q12
1Q13
2Q13
3Q13
2013 formula rate
case filing (by
5/1/13)
ComEd Distribution
Formula Rate 
Illinois Power
Agency
Procurement
ComEd
Transmission Rate
Update
2013 formula rate
case filing (by 5/1);
rates effective June
2013 thru May 2014
2013 formula rate case
filing final order (by
12/27/13); rates
effective 1/2/14 –
1/1/15
4Q13
BGE Distribution Rates
PECO Supply
Procurement
BGE Transmission Rate
Update
2013 formula rate case
filing (by 5/15/13);
rates effective June
2013 thru May 2014
MDPSC Order expected
February 23, 2013
DSP II Procurement
(December)
BGE Supply
Procurement
Regular procurement
event (January)
Regular procurement
event (April and June)
Act 129 Part II Energy
Efficiency Plan Filing
(11/2012)
PECO Distribution
Filing
12-0321 final order
(by 12/26); rates
effective 1/2/13 –
1/1/14
DSP II Procurement
(February)
DSP II Procurement
(October)
Regular
procurement event
(October)
Regular
procurement event
(October)
No procurement events scheduled for 2013
2012 EEI Conference

Generation

Exelon Generation Fleet
A clean and diverse portfolio that is well positioned for environmental upside from
EPA regulations
(1)
Total owned generation capacity as of 9/30/2012 for legacy Exelon and legacy Constellation combined, net of physical market mitigation assumed to be 2,648 MW.  Nuclear capacity reflects
EXC ownership of CENG and Salem. Coal capacity shown does not include Eddystone 2 (309 MW) retired on 6/1/2012.
51
National Scope
•
Power generation assets in 20 states and
Canada
•
Low-cost generation capacity provides
unparalleled leverage to rising commodity
prices
Large and Diverse
•
35
GW
of
diverse
generation
(1)
–
19 GW of Nuclear
–
10 GW of Gas
–
2 GW of Hydro
–
2 GW of Oil
–
1 GW of Coal
–
1 GW of Wind/Solar/Other
Clean
•
One of nation’s cleanest fleets as
measured by CO2, SO2 and NOx intensity
•
Less than 5% of combined generation
capacity will require capital expenditures
to comply with Air Toxic rules
2012 EEI Conference

Executing on Renewable Development Projects
Existing renewable projects will expand the renewable portfolio by more than 600
MW by 2013
52
•
Six projects completed or to be completed by
the end of 2012
—
Adding 404 MW
—
Diverse geographic representation:
Idaho
Kansas
Michigan
New Mexico
Texas
•
All projects done under long-term PPAs with
anticipated payback in approximately 10 years
2012 EEI Conference
AVSR 1
Wildcat
Wind
Wind
Solar
•
Antelope Valley Solar Ranch Project One
Large scale solar project that will be 230
MW once fully operational
On track to add 80 MW by year-end 2012
150 MW online by Fall 2013
Initial investment fully recovered by 2015
25-year PPA for entire output with Pacific
Gas & Electric
Cashflow and EPS accretive in 2013
Los
Angeles

53
Nuclear Uprates
(1)
Includes deletion of TMI MUR from the uprate program and deferral of Limerick and LaSalle
EPU’s.
(2)
In 2013 dollars. Overnight costs do not include financing costs or cost escalation.
(3)
Adjusted for actual MW’s achieved.
(4)
Total project returns
Uprate projects enhance Exelon’s
geographically diverse nuclear fleet –
approximately 18 MW to come on line
in 2012 and an additional 230 MW
through 2015
Nuclear
Uprate
Program
Summary
(1)
Estimated
IRR
(4)
Overnight
Cost
(2)
Approval
Process
Project
Duration
Megawatt
Recovery &
Component
Upgrades
11 -
13%
$890 M
Not
required
3-4 Years
MUR
(Measurement
Uncertainty
Recapture)
12 -
16%
$300 M
Straight
forward
approval
process
2-3 Years
EPU (Extended
Power Uprate)
8 -
13%
$2,240 M
Straight
forward
approval
process
3-6 Years
Station
Base Case
MW
(3)
Max Potential
MW
(3)
MW Online to
Date
Year of Full
Operation
by Unit
(1)
MW Recovery & Component Upgrades:
Quad Cities
99
99
99
2011 / 2010
Dresden
3
3
2013 / 2012
Peach Bottom
29
30
15
2012 / 2011
Dresden
106
110
62
2011 / 2013
Limerick
6
6
3
2012 / 2013
Peach Bottom
2
2
2014 / 2015
MUR:
LaSalle
39
39
39
2010 / 2011
Limerick
30
30
30
2011 / 2011
Braidwood
34
42
2013 / 2013
Byron
34
42
2013 / 2013
Quad Cities
20
21
2014 / 2014
Dresden
26
28
2014 / 2015
TMI
0
0
Deleted
EPU:
Clinton
2
2
2
2010
Peach Bottom
130
137
2015 / 2016
LaSalle
297
313
2020 / 2019
Limerick
270
284
2021 / 2021
Total
1,127
1,188
250
2012 EEI Conference

Peach Bottom Uprate Program
•
MW Recovery
–
Low Pressure Turbine Retrofit installation complete
for both Unit 2 and Unit 3
–
Replacement of Reactor Recirculation Pump Motor
Generator sets with energy efficient Adjustable
Speed Drives in 2014 and 2015
•
EPU
–
Funding approved for installation work
54
Unit 2
Unit 3
Uprate Project
MW
Increase
(1)
Online
Date
MW
Increase
(1)
Online
Date
Status
MW Recovery -
Low Pressure
Turbine Retrofit
14
4Q 2012
15
4Q 2011
Complete
MW Recovery -
Adjustable Speed
Drives
1
4Q 2014
1
4Q 2015
Initial studies in progress
EPU
65
1Q 2015
65
1Q 2016
Installation phase in progress
(1)  Capital investment and MW uprate numbers represent Exelon’s 50% ownership stake in Peach Bottom Station. $’s used in chart are nominal (excludes capitalized interest).
Peach Bottom Uprate Projects are underway –
15 additional MWs came online in
2011 and the remaining will come online between late 2012 and 2016
$0
$50
$100
$150
2009
2010
2011
2012
2013
2014
2015
2016
2017
Capital Investment $M
(1)
MW Recovery
EPU
2012 EEI Conference

Exelon Nuclear Fleet Overview (including CENG and Salem)
Plant Location
Type/
Containment
Water Body
License Extension Status / License
Expiration
Ownership
Spent Fuel Storage/
Date to lose full core
discharge capacity
Braidwood, IL
(Units 1 and 2)
PWR
Concrete/Steel Lined
Kankakee River
Expect to file application in 2013 /  2026,
2027
100%
Dry Cask
Byron, IL
(Units 1 and 2)
PWR
Concrete/Steel Lined
Rock River
Expect to file application in 2013 /  2024,
2026
100%
Dry Cask
Clinton, IL
(Unit 1)
BWR
Concrete/Steel Lined / Mark III
Clinton Lake
2026
100%
Dry Cask
(2017)
Dresden, IL
(Units 2 and 3)
BWR
Steel Vessel / Mark I
Kankakee River
Renewed / 2029, 2031
100%
Dry Cask
LaSalle, IL
(Units 1 and 2)
BWR
Concrete/Steel Lined / Mark II
Illinois River
2022, 2023
100%
Dry Cask
Quad Cities, IL
(Units 1 and 2)
BWR
Steel Vessel / Mark I
Mississippi River
Renewed / 2032
75% Exelon, 25% Mid-
American Holdings
Dry Cask
Calvert Cliffs, MD
(Units 1and 2)
PWR
Concrete/Steel Lined
Chesapeake Bay
Renewed / 2034, 2036
100% CENG
Dry Cask
R.E. Ginna, NY
(Unit 1)
PWR
Concrete/Steel Lined
Lake Ontario
Renewed / 2029
100% CENG
Dry Cask
Limerick, PA
(Units 1 and 2)
BWR
Concrete/Steel Lined / Mark II
Schuylkill River
Filed application in June 2011 (decision
expected in 2015) / 2024, 2029
100%
Dry Cask
Nine Mile Point, NY
(Units 1 and 2)
BWR
Concrete/Steel Vessel / Mark I /
Concrete/Steel Vessel/ Mark II
Lake Ontario
Renewed / 2029, 2046
100% CENG    /
82% CENG   , 18% Long
Island Power Authority
Dry Cask
Oyster Creek, NJ
(Unit 1)
BWR
Steel Vessel / Mark I
Barnegat Bay
Renewed / 2029
100%
Dry Cask
Peach Bottom, PA
(Units 2 and 3)
BWR
Steel Vessel / Mark I
Susquehanna
River
Renewed / 2033, 2034
50% Exelon, 50% PSEG
Dry Cask
TMI, PA
(Unit 1)
PWR
Concrete/Steel Lined
Susquehanna
River
Renewed / 2034
100%
2023
Salem, NJ
(Units 1 and 2)
PWR
Concrete/Steel Lined
Delaware River
Renewed / 2036, 2040
42.6% Exelon, 57.4%
PSEG
Dry Cask
(1)
Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review.
(2)
The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge
capacity in their on-site storage pools.
(3)
On December 8, 2010, Exelon announced that it will permanently cease generation operations at Oyster Creek by December 31, 2019.
Oyster Creek’s current NRC license expires in 2029.
(4)
Exelon Generation has a 50.01% ownership interest in CENG (Constellation Energy Nuclear Group, LLC). Electricite de France SA (EDF) has a 49.99% ownership interest in CENG.
55
2012 EEI Conference
(1)
(2)
(3)
(4)
(4)
(4)
(4)

Effectively Managing Nuclear Fuel Costs
(1)
Projected Exelon (100%) Uranium Demand
Components of Nuclear Fuel in 2012
2012 –
2015: 100% hedged in volume
2016:
~85% hedged in volume
2017:
~55% hedged in volume
11
10
9
8
7
6
5
4
3
2
1
0
2017E
2016E
2015E
2014E
2013E
2012
Projected Exelon Average Uranium Cost vs. Market
2017E
2016E
2015E
2014E
2013E
2012
Exelon Average Reload Price
Projected Market Price
(1)
All charts exclude Salem and CENG.
(2)
At ownership, excluding Salem and CENG. Excludes costs reimbursed under the settlement agreement with the DOE.
56
Projected
Total
Nuclear
Fuel
Spend
(2)
2017E
1,174
2016E
1,152
2015E
1,096
2014E
1,051
2013E
992
2012
926
Nuclear Fuel Capex
Nuclear Fuel Expense (Amortization + Spent Fuel)
2012 EEI Conference
14%
Fabrication
14%
Nuclear Waste
36%
Uranium
3%
Conversion
2%
Tax/Interest
31%
Enrichment
0
20
40
60
80
100
0
200
400
600
800
1,000
1,200
1,400

Impact of Refueling Outages
Refueling Outage Duration
31%
36%
14%
14%
Nuclear
Output
(1)
Note: Net nuclear generation data at ownership excluding Salem and CENG. 
57
1,208
1,169
1,104
Nuclear Refueling Cycle
•
All Exelon owned units on a 24 month cycle
except for Braidwood U1/U2, Byron U1/U2 and
Salem U1/U2, which are on 18 month cycles
•
Average Outage Duration (2010-11): ~27 days
Note: Exelon data excludes Salem & CENG. Exelon’s 2009 average includes 23 days of TMI outage that
extended into 2010 for a steam generator replacement.
Actual
Target
# of Outages
2012 Refueling Outage Impact
•
10 planned refueling outages, including 1 at
Salem
•
Exelon completed 4 refueling outages in the
Spring with an average duration of 30 days
•
5 Exelon planned Fall refueling outages (Byron
1, Peach Bottom 2, Braidwood 2, Oyster Creek,
and Dresden 3)
•
1 Salem planned Fall refueling outage
2013 Refueling Outage Impact
•
10 planned refueling outages, including 1 at
Salem
•
4 Exelon planned Spring refueling outages and
5 planned Fall refueling outages
•
1 Salem planned Spring refueling outage
Industry (w/o Exelon)
Exelon
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2012 EEI Conference
125
126
127
128
129
130
131
132
133
134
135
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
7
7.5
8
8.5
9
9.5
10
10.5
0
10
20
30
40
50