EX-99.1 2 d363056dex991.htm PRESENTATION SLIDES Presentation Slides
Performance that Drives Progress
Analyst Meeting
June 7, 2012
Exhibit 99.1


Welcome
JaCee Burnes
Vice President, Investor Relations


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 First Quarter 2012 Quarterly
Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information,
ITEM 1. Financial Statements: Note 15; 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
2012 Analyst Meeting – Performance that Drives Progress


Agenda
3
Time (ET)
Presentation Topic
Presenter
Total Time
9:00 –
9:10
Welcome & Introductions
JaCee Burnes
10 minutes
9:10 –
9:30
Exelon Overview
Chris Crane
20 minutes
9:30 –
9:45
Financial Update
Jack Thayer
15 minutes
9:45 –
10:15
Constellation
Ken Cornew
30 minutes
10:15 –
10:25
Competitive Markets
Bill Von Hoene
10 minutes
10:25 –
10:55
Q&A
Panel Q&A
(1)
30 minutes
10:55 –
11:15
BREAK
20 minutes
11:15 –
11:30
Exelon Utilities
Denis O’Brien
15 minutes
11:30 –
11:40
Power Generation
Chip Pardee
10 minutes
11:40 –
11:55
Q&A
Panel Q&A
(2)
15 minutes
11:55 –
12:00
Closing
Chris Crane
5 minutes
12:00 –
1:30
RECEPTION/LUNCH
90 minutes
2012 Analyst Meeting – Performance that Drives Progress
(1)
First panel for Q&A to include Chris Crane, Bill Von Hoene, Ken Cornew, Jack Thayer, Joe Glace.
(2)
Second panel for Q&A to include Denis O’Brien, Chip Pardee, Anne Pramaggiore, Craig Adams, Ken DeFontes, Jack Thayer.


Exelon Overview
Chris Crane
President & Chief Executive Officer


5
Exelon Overview
Power Generation
Constellation
ComEd, PECO & BGE
Competitive Business
Regulated Business
Exelon is the largest competitive integrated energy company in the U.S. 
Largest merchant fleet in the
nation (~35 GW of capacity),
with unparalleled upside
One of the largest and best
managed nuclear fleets in the
world (~19 GW)
Significant gas generation
capacity (~10 GW)
Renewable portfolio (~1 GW),
mostly contracted
Leading competitive energy
provider in the U.S.
Customer-facing business, with
~1.1 M competitive customers
and large wholesale business
Top-notch portfolio and risk
management capabilities
Extensive suite of products
including Load Response,
RECs, Distributed Solar
One of the largest electric and
gas distribution companies in
the nation ~6.6 M customers
Diversified across three utility
jurisdictions –
Illinois, Maryland
and Pennsylvania
Significant investments in
Smart Grid technologies
Transmission infrastructure
improvement at utilities
Exelon Generation
Exelon Utilities
ComEd, PECO & BGE
Exelon Utilities
2012 Analyst Meeting – Performance that Drives Progress


6
National Scope
National presence gives us a unique platform to perform and grow
Power Generation
Constellation
Operations in seven RTOs, with
strong positions across PJM,
ERCOT & New England
Serves more than 2/3
rds
of the 
Fortune 100 companies in the
U.S.
Large urban presence with
operations in three states –
IL,
PA and MD
2012 Analyst Meeting –
Performance that Drives Progress
Coast-to-coast presence with operations in 47 states and Canada
Exelon Utilities
2012 Analyst Meeting – Performance that Drives Progress


7
Diversified Platform and Revenue Growth
Exelon’s portfolio is well diversified and positioned for long-term growth
~50%
~50%
Regulated Business
Competitive Businesses
Upside from tightening power
markets from significant amount of
coal retirements
Strong pipeline of organic generation
growth opportunities, including
nuclear uprates, wind & solar
Leverage Constellation brand,
network and relationships to grow
customer-facing business across the
country
Low-risk investment through
contracted renewables fleet and load
matched with generation
Investment grade credit ratings to
support operations and growth
Stable income and cash flow from
utility operations
Significant investment in
infrastructure upgrades, including
next generation technology
enhancements (Smart Grid)
Diversification across three utility
jurisdictions
Leverage utility structure to drive
best practices
Investments to improve reliability
and operations 
Competitive Business
Diversification of revenue, earnings and cash flows
(1) Based on 2012 thru 2014 average operating EBITDA estimate as of 4/30/2012 and adjusting for ComEd rate order.
Regulated Business
2012 Analyst Meeting – Performance that Drives Progress
Balanced EBITDA Contribution
(1)


8
Multiple Merger Benefits
Matches Exelon’s clean
generation fleet with
Constellation’s customer-
facing leading retail and
wholesale platform
Creates economies of scale
through expansion across
the value chain
Regional and
technological
diversification
Maintain clean
generation profile
More competitive 
product offerings and
enhanced margins
Scalable commercial
platform
Earnings and cash flow
accretive
Stronger balance sheet 
than standalone
financials
Significant cost
synergies and gross
margin expansion
Maintains a regulated
earnings profile
Enables operational
enhancements from
sharing best practices
This merger creates incremental strategic and financial value
2012 Analyst Meeting – Performance that Drives Progress
Strategic
Fit
Financial
Benefits
Competitive
Operations
Utility
Benefits


Exelon’s Transformation
The merger enhances scale, scope and flexibility across the value chain  
Exelon Pre Merger
Exelon Post Merger
Financials
$55.1 billion
Assets
(1)
$74.5 billion
$18.9 billion
Revenues
(1)
$32.7 billion
$26.4 billion
Market Capitalization
(2)
$33.9 billion
Power Generation
(3)
~26 GW
Total Capacity
(4)
~35 GW
175 TWh
Expected Generation
(5)
220 TWh
~4 GW
Natural Gas Capacity
(5)
~10 GW
Constellation
(3)
~40 TWh / 50 BCF
Competitive Load & Gas
(6)
~170 TWh / 465 BCF
3,500
Customer Count
More than 1 million
Minimal Load Response
Load Response Portfolio
~2,000 MW
No projects
Energy Efficiency Projects
Over 4,000 projects across U.S.
Exelon Utilities
(3)
5.4 million
Customers
6.6 million
$13 billion
2011 Combined Rate Base
$17 billion
(1)
Represents 2011 actuals.
(2)
As of 3/12/2012. 
(3)
2012 estimate as of 4/30/2012.
(4) Represents owned capacity, net of mitigation (~2,648 MW).
(5) Represents owned or contracted capacity, net of mitigation.
(6) Represents fixed price or indexed load, including retail and wholesale.
9
2012 Analyst Meeting – Performance that Drives Progress


Lower energy costs
reflected in prices paid by
customers
Expanded set of products
and services backed by a
large, diverse portfolio of
generation assets,
including several low
carbon options
Lower collateral costs
with reduction in size of
liquidity facilities and
collateral postings
Savings on transaction
costs with less need for
Over-the-Counter hedging
Competitive pricing that
enables volume and/or
margin growth
Improved risk profile, with
asset-backed hedging of
load position
Natural hedge between
what we own and what we
sell
10
Generation and Load Match
Benefits of a well-matched generation and load footprint are realized across
the board
Strategic, financial and customer value from combining generation and
load portfolios
Strategic
Benefits
Financial
Benefits
Customer
Benefits
2012 Analyst Meeting – Performance that Drives Progress


Committed to Making the Merger Successful
Tasks Accomplished
Closed the merger in less than a year
Effective integration planning and execution for
seamless day 1 operations
Appointed leadership and management teams
Ongoing Focus
Employ Exelon’s management model to enhance
profitability by realizing efficiencies and reducing
costs
Enterprise-wide synergy realization (O&M, CapEx)
Efficient and optimal use of capital to pursue
highest value projects and opportunities
Grow and diversify our business in a deliberate and
sustainable manner
Focus on both process and innovation to protect
and grow the business
We are well on our way to realizing the value from this merger
Merger Checklist  / Scorecard
Item
Target
Cost Synergies
$500 million run rate
(1)
Liquidity Reduction
$4.2 billion year-end 2012
Gross Margin
Opportunities
$100 million run rate
(2)
Asset Sales
Process
Complete by  August 2012
Commercial Load
Volume Growth
~6% CAGR on volumes
(3)
BGE
File rate case in 2
half of 2012
Confident in ability to achieve or exceed
targets in a timely and efficient manner 
Clearly defined plans to make this merger successful
(1) Run rate target for O&M synergies from 2014 onwards.
(2) Gross Margin opportunities on a run rate basis from 2014 onwards from combining the two commercial
portfolios.
(3) Represents Compounded Annual Growth Rate (CAGR) until 2014 using 2011
as the base year.
11
2012 Analyst Meeting – Performance that Drives Progress
nd


12
Financial Discipline
Committed to maintain investment grade
credit rating
Rigorous and comprehensive capital
allocation process among competing uses
and growth projects
Align commodity hedging program to
financial policies, including dividend
and investment grade credit rating
Hedge enough commodity risk to meet
future cash requirements
Achieve or exceed synergy targets (O&M,
CapEx)
Eliminate inefficiencies and contain
costs
Continue to execute a well-aligned financial policy framework and maintain dividend
Enterprise Risk Management
Cost Containment
Strategic Policy Alignment
Investment Grade Rating
Holistic view on company-wide risk,
recognition of natural hedges and offsets
as part of decision making process
Small, well-managed proprietary trading
function
2012 Analyst Meeting – Performance that Drives Progress


13
Exelon: Vision, Strategy, Values and Goals
VALUES
We are dedicated to safety
We  actively pursue excellence 
We innovate to better serve our customers
We act with integrity and are accountable
to each other, our communities, and the
environment
We succeed as a diverse and inclusive
team
GOALS
Keep the lights on and the gas flowing
Run generation fleet at world class levels
Foster a work environment that is safe,
productive, learning-focused and engaging
Capitalize on clean energy as a competitive
advantage
Build sustained value through disciplined
financial management
Be a top-tier competitor in our key markets
Advance competitive markets
VISION –
Performance that Drives Progress
STRATEGIC DIRECTION –
Sustainable Growth
2012 Analyst Meeting – Performance that Drives Progress


14
Strategic Direction: Sustainable Growth
Key focus areas as we diversify and grow our business
Sustainable Growth –
Focused on creating value for our shareholders by leveraging
our strength in operations and financial management to grow our business
2012 Analyst Meeting –
Performance that Drives Progress
Operational
Excellence
Financial
Discipline
Drive
Competition
& Choice
Advance
Clean
Energy
2012 Analyst Meeting – Performance that Drives Progress
Operational Excellence
We capitalize on reliability and
efficiency in our operations as a
competitive advantage
Financial Discipline
We are committed to investment
grade ratings and maintaining
the dividend
Drive Competition & Choice
We champion competitive energy
markets
Advance Clean Energy
We believe clean energy
creates value


Financial Update
Jack Thayer, EVP & Chief Financial Officer


2012 Earnings Guidance
Expect to deliver full-year 2012 adjusted
(non-GAAP) operating EPS within
guidance range of $2.55 -
$2.85/share
(1)
Guidance includes CEG earnings from
merger close date
ExGen guidance reflects gross margins 
for combined company portfolio
Lower PJM capacity revenues as
expected
ComEd earnings reflect impact from
recent ICC formula rate order
Merger cost synergies of $0.12/share
Purchase accounting adjustments largely
excluded from operating earnings
$0.30 -
$0.40
$0.05 -
$0.15
$0.40 -
$0.50
FY 2012
$2.55 -
$2.85
(1)
HoldCo
ExGen
ComEd
PECO
BGE
16
$1.75 -
$1.95
2012 Analyst Meeting – Performance that Drives Progress
(1) 2012 guidance includes Constellation Energy and BGE earnings for March 12 – December 31. Based on expected 2012 average outstanding shares of 819M. Earnings guidance
for OpCos may not add up to consolidated EPS guidance.
Confident of achieving earnings within range of $2.55 - $2.85/share


Achievable Merger Synergies
Run Rate O&M Synergies Breakdown
Gross Margin Opportunities ($M)
Run rate gross margin opportunities of
$100M
(2)
starting in 2014
Matching load and generation
Retail growth opportunities
Portfolio optimization
$500
$305
$170
2015+
2014
2013
2012
Merger O&M synergies
Higher run rate
O&M synergies of
~$500M
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
Fully committed to achieving merger synergies
(1) O&M synergies include cost savings of ~$40M from lower liquidity requirements.
(2) Gross margin opportunities included in Total Gross Margin shown on slide 45.
Unregulated
75%
BGE
7%
PECO
7%
ComEd
11%
17
O&M
Savings
($M)
(1)
2012 Analyst Meeting – Performance that Drives Progress


Operating O&M Forecast Lower than Inflation
2012 O&M forecast of $6.45B
(1)
Includes merger synergies of $170M for ~9.5 months
Excludes costs to achieve which are considered non-operating
Maintain O&M CAGR of ~1%
(2)
for 2012-2014
2012E (Combined
Company)
$6,775
(2) (3)
-50
4,100
1,200
675
525
2011 Actuals (Standalone
EXC + Standalone CEG)
3,000
1,100
725
650
1,250
(in $M)
ExGen
ComEd
ComEd
PECO
PECO
BGE
Corp
ExGen O&M includes
costs of maintaining a
larger retail platform
Higher O&M at ComEd
mainly driven by EIMA
related costs of ~$70M
PECO costs lower due
to higher than normal
storm costs in 2011
(1)
O&M included in 2012 EPS guidance includes CEG and BGE costs from merger close date.
(2)
O&M Compound Annual Growth Rate (CAGR) calculated after normalizing 2012 O&M to include CEG and BGE costs for 12 months.
(3)
O&M for utilities excludes regulatory O&M that are P&L neutral. ExGen O&M excludes decommissioning costs.
EIMA = Energy Infrastructure Modernization Act
~1% CAGR for 2012-2014
ExGen
BGE
Constellation
2012 EPS
guidance includes
$6.45B
(1)
of O&M
costs
Stub O&M
18
$6,725
(3)
2012 Analyst Meeting – Performance that Drives Progress


Capital Expenditure Expectations
400
375
475
50
100
2014
3,325
1,100
1,050
50
425
175
2013
3,200
1,025
925
25
75
675
2012
(1)
3,925
975
1,175
650
625
100
Base Capex
Nuclear Fuel
MD Commitments
Wind
Solar
Upstream Gas
Nuclear Uprates
2014
2,950
1,700
550
225
475
2013
2,875
1,650
625
200
400
2012
(1)
2,300
1,475
400
175
250
Electric Distribution
Electric Transmission
Gas Delivery
Smart Grid/Smart Meter
Growth
CapEx
Diversified balance of utility capex recoverable through rates and generation growth
capex that are largely contracted
(in $M)
(in $M)
(1) 2012 CapEx includes CEG and BGE from merger close date.
19
2012 Analyst Meeting – Performance that Drives Progress
Exelon Utilities
Exelon Generation


2012 Projected Sources and Uses of Cash
(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 $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo. PECO’s A/R Agreement was extended in accordance with its terms through August 31, 2012.
(6)
“Other”
includes proceeds from options and expected changes in short-term debt.
(7)
Includes cash flow activity from Holding Company, eliminations, and other corporate entities.  Represents Constellation cash flows from merger close through December 31, 2012.
20
(7)
($ in Millions)
Beginning Cash Balance
(1)
$550
Cash acquired from Constellation
(2)
150
n/a
n/a
1,375
1,650
Cash Flow from Operations
(3)
300
1,425
825
3,600
5,925
CapEx (excluding other items below):
(475)
(1,225)
(350)
(975)
(3,100)
Nuclear Fuel
n/a
n/a
n/a
(1,175)
(1,175)
Dividend
(4)
(1,725)
Nuclear Uprates
n/a
n/a
n/a
(400)
(400)
Wind
n/a
n/a
n/a
(650)
(650)
Solar
n/a
n/a
n/a
(625)
(625)
Upstream
n/a
n/a
n/a
(100)
(100)
Utility Smart Grid/Smart Meter
(75)
(100)
(75)
n/a
(250)
Net Financing (excluding Dividend):
Planned Debt Issuances
(5)
300
--
250
775
1,325
Planned Debt Retirements
(175)
(450)
(375)
(75)
(1,075)
Project Finance/Federal Financing
Bank Loan
n/a
n/a
n/a
350
350
Other
(6)
--
225
--
--
175
Ending Cash Balance
(1)
$875
2012 Analyst Meeting – Performance that Drives Progress


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
April 16, 2012.
(2)
Moody’s downgraded Exelon and Generation and upgraded BGE upon completion of the merger with Constellation Energy. Moody’s
currently
has
Exelon
and
Generation
on
Negative
Outlook.
S&P
and
Fitch
affirmed
ratings
of
Exelon
and
subsidiaries
upon
completion of the merger.
(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
2012-2016 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
21
2012 Analyst Meeting – Performance that Drives Progress
Metrics sufficient to maintain investment-grade rating in 5-year financial plan


Levers Provide Additional Flexibility
Lever
Summary
Operational
Efficiencies
Cost
Management
Identify additional cost management opportunities within
the combined company
Financial Tools
Project
Financing
Use project financing for renewable opportunities as
deemed fit
Defer Growth
Projects
Maintain flexibility on timing of generation growth projects
LaSalle EPU 2-year deferral provides additional cash
flow
headroom
and
maintains
ability
to
add
303
-
336
MWs by 2017/18
22
EPU = Extended Power Uprate
2012 Analyst Meeting – Performance that Drives Progress
Exelon has levers available to maintain balance sheet strength, sustain the
dividend and maintain investment-grade ratings


23
Appendix
2012 Analyst Meeting – Performance that Drives Progress


$ / Share
ComEd Operating EPS Bridge
24
$0.61
$0.03
Depreciation &
Amortization
$(0.04)
O&M
$(0.08)
RNF
$(0.03)
Share Count
Change
$(0.12)
2011
2012
$0.30 -
$0.40
Other
$(0.02)
Interest
Note: Drivers add up to mid-point of 2012 EPS range.
AMP = Advanced Metering Program
RNF = Revenue Net Fuel
(1) O&M for utilities excludes regulatory O&M that are P&L neutral.
($0.05)  EIMA O&M
($0.02)  Pension/OPEB
($0.01) Tax Rate Change
$0.03 Decrease in Long-Term Debt
$0.02   DST Revenue
$0.03   Transmission Revenue
($0.03)  Weather
($0.01)  Rider AMP
($0.02)  Other RNF
($0.03)  Depreciation Expense
($0.01)  Amortization
2012 Analyst Meeting – Performance that Drives Progress


PECO Operating EPS Bridge
$0.58
2012
$0.40 -
$0.50
O&M
$0.03
RNF
$(0.05)
Share Count Change
$(0.11)
2011
25
Note: Drivers add up to mid-point of 2012 EPS range
RNF = Revenue Net Fuel
(1) O&M for utilities excludes regulatory O&M that are P&L neutral.
($0.04)  Weather
($0.02)  Load
$0.03    Primarily Storm Costs
2012 Analyst Meeting – Performance that Drives Progress


BGE Operating EPS Bridge
$0.70
2012
$0.05
-
$0.15
Other
$0.01
Interest
$(0.01)
Depreciation
&
Amortization
$(0.02)
O&M
$0.00
RNF
$(0.01)
Stub
$(0.05)
Share Count
Change
$(0.52)
2011
26
Note: Drivers add up to mid-point of 2012 EPS range.
RNF = Revenue Net Fuel
(1) O&M for utilities excludes regulatory O&M that are P&L neutral.
$0.04   Storm
($0.02) PSC Mandated Reliability Spend
($0.01) Reg Asset Capitalization
($0.01) Other
($0.01) Weather
($0.01) Issuance of long-term debt
2012 Analyst Meeting – Performance that Drives Progress


Credit Facility Update
Constellation liquidity facilities (excluding BGE) of $4.2B to be eliminated by end of year
2012
Reduced Constellation $2.5B revolver by $1.0B at merger close and plan to eliminate balance
revolver by end of 2012
End state liquidity capacity of $6.1B starting in 2013
Expected Liquidity Facility
(excl. utilities) on 12/31/12
$6.1
Expected Liquidity Reduction
$4.2
Liquidity Facilities (excl.
utilities) as of 1/1/2012
$10.3
$6.1
Exelon
$4.2
Constellation
Expect to realize $40M in annual cost savings beginning in 2013
(in $B)
27
2012 Analyst Meeting – Performance that Drives Progress


Merger CapEx Synergies & Costs To Achieve
$80
2012
$60
2013
$40
2014
$8
$325
Capital
O&M
Costs to Achieve ($M)
CapEx Synergies ($M)
$70
$55
$35
2015+
2014
2013
2012
Run rate CapEx
synergies of
~$75M
28
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
2012 Analyst Meeting – Performance that Drives Progress


Merger Purchase Accounting P&L Impacts
Preliminary
Exelon
Generation
Pre-Tax
GAAP
P&L
Impacts
(1)
($M)
2012
Item
Q1
Q2
Q3
Q4
Total
2013
2014
Description
Earnings
Treatment
Unamortized energy
contracts, net
(Revenue net Fuel)
~($125)
~($450)
(~$275)
~($300)
~($1,150)
~($475)
~($100)
Non-cash amortization of
intangible assets, net, for
acquired power supply and
fuel contracts recognized at
fair value at the merger
date.
Excluded from
operating
earnings in
2012-14
Depreciation &
Amortization
~($1)
~($6)
~($6)
~($6)
~($20)
~($30)
~($30)
Net incremental
depreciation and
amortization based on fair
value of generation station
and upstream assets, trade
name, and retail
relationships.  Excludes
plant divestitures.
Included in
operating
earnings
Amortization of
adjustment to
recognize the
unregulated long-term
debt at fair value
(Interest Expense)
~$3
~$8
~$8
~$8
~$28
~$25
~$15
Non-cash amortization of
fair value adjustment for
long-term debt.
Included in
operating
earnings except
for $17M and
$12M hybrid
amortization in
2012-13,
respectively
(2)
29
2012 Analyst Meeting – Performance that Drives Progress
(1)
Amounts shown in table above are based on the preliminary valuation underlying the disclosures in the first quarter Form 10-Q.  These amounts are subject to
revision and any changes could be material.  Numbers represent increase / (decrease) to GAAP earnings. This list of purchase accounting adjustments is not all
inclusive.  Other minor adjustments have minimal impact on earnings.
(2)
Exclusion from operating earnings for amortization related to hybrid instrument expected to be retired in 2013.


Pension and OPEB for Combined Company
Plan Design and Funding Strategy:
Exelon is evaluating benefit plan design changes for the combined company, but does not anticipate
merging the Exelon and Constellation plans until 2013 at the earliest
Exelon and Constellation plans will maintain their stand-alone funding strategies in 2012; the funding
strategy for the combined company will be reevaluated once the future state plan design is established
Both companies’
pension funding strategy is to 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
Unlike qualified pension plans, OPEB plans are not subject to regulatory minimum contribution
requirements and are, therefore, voluntary. 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
plans
are
unfunded
Current Forecast:
The table below provides the combined company’s 2012 and forecasted 2013 pension and OPEB expense
and
contributions
assuming
2012
asset
returns
of
7.50%
and
6.68%
(after-tax)
for
pension
and
OPEB,
respectively, a projected 12/31/12 pension discount rate of 4.70% and 4.52% for Exelon and
Constellation, respectively, and a projected 12/31/12 OPEB discount rate of 4.78% and 4.53% for Exelon
and Constellation, respectively
(1) Pension and OPEB expenses assume a 27.0% and 27.6% capitalization rate for 2012 and 2013, respectively.
(2) Contributions shown in the table above are based on the current contribution policy for Exelon and Constellation plans.
30
2012
2013
(in $M)
Pre-Tax Expense
(1)
Contributions
(2)
Pre-Tax Expense
(1)
Contributions
(2)
Pension
$350
$160
$350
$150
OPEB
$240
$320
$235
$305
Total
$590
$480
$585
$455
2012 Analyst Meeting – Performance that Drives Progress


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
31
2013 Pension Sensitivity
(2) 
(in $M)
S&P Returns in Q2 –
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)
$340
$145
$360
$155
$375
$160
+50 bps
$310
$150
$325
$155
$345
$160
-
50bps
$375
$90
$390
$150
$410
$160
2013 OPEB Sensitivity
(2) 
(in $M)
S&P Returns in Q2 –
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
$285
$230
$300
$245
$320
+50 bps
$200
$260
$210
$275
$225
$290
-
50bps
$240
$315
$255
$335
$270
$355
(1) Contributions shown in the table above are based on the current contribution policy for Exelon and Constellation plans.
(2) Pension and OPEB expenses assume a 27.6% capitalization rate.
(3) Final 2012 asset return for pension and OPEB will depend in part on overall equity market returns from Q2 – Q4 2012 as proxied by the S&P 500.  The
amounts above reflect  YTD S&P returns through March 31, 2012. 
(4) The baseline discount rates reflect a projected 12/31/12 pension discount rate of 4.70% and 4.52% for Exelon and Constellation, respectively, and OPEB
discount rate of 4.78% and 4.53% for Exelon and Constellation, respectively. 
2012 Analyst Meeting – Performance that Drives Progress


Debt Maturity Profile (2012-2020)
Debt Maturity Schedule
600
173
75
2014
1,585
648
250
617
70
2013
1,019
300
252
467
2012
819
46
2015
1,685
260
800
35
665
379
2020
1,600
1,100
500
550
2019
2018
600
500
840
2017
1,168
1,340
425
41
2016
1,079
702
PECO
ComEd
Exelon Corp
BGE
ExGen
(in $M)
32
2012 Analyst Meeting – Performance that Drives Progress
~66% of 2012 – 2016 debt maturities consist of regulated utility debt


2012 Key Assumptions
Utility Statistics
2012 Estimate
Electric Delivery Growth (%)
(3)
ComEd
(0.3)%
PECO
(3.3)%
BGE
0.7%
Effective Tax Rate -
Operating (%)
ComEd
39.6%
PECO
33.6%
BGE
37.8%
Exelon
37.4%
33
(1)
Excludes Salem and CENG.
(2)
Reflects forward market prices as of April 30, 2012.
(3)
Weather-normalized load growth.
(4)
O&M rounded to the nearest $25M.
Generation Statistics
2012 Estimate
(2)
Nuclear Capacity Factor (%)
(1)
93.5%
Total Expected Generation(GWh)
219,900
Henry Hub Natural Gas ($/MMbtu)
$2.47
Midwest: NiHub ATC Price
$26.71
Mid-Atlantic: PJM-W ATC Price
$32.70
ERCOT-N ATC Spark Spread
$11.10
New York: NY Zone A ATC Price
$26.99
New England: Mass Hub Spark Spread
$5.98
Effective
Tax
Rate
(%)
-
Operating
37.1%
2012 O&M
(4)
Reconciliation (in $M)
ExGen
ComEd
PECO
BGE
Other
Exelon
GAAP O&M
$4,725
$1,350
$700
$575
$175
$7,525
Decommissioning accretion
$(75)
-
-
-
-
$(75)
Retirement of Fossil  Plants
$(25)
-
-
-
-
$(25)
FERC Settlement
$(200)
-
-
-
-
$(200)
Regulatory O&M
-
$(150)
$(25)
-
-
$(175)
Merger/Integration costs
$(325)
-
-
$(50)
$(225)
$(600)
Operating O&M (as shown on slide 18)
$4,100
$1,200
$675
$525
$(50)
$6,450
2012 Analyst Meeting – Performance that Drives Progress


GAAP to Operating Adjustments
Three Months Ended March 31, 2012
ExGen
(1)
ComEd
PECO
BGE
(1)
Other
(1)
Exelon
(1)
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.58
$0.13
$0.14
$0.02
$(0.02)
$0.85
Mark-to-market adjustments from economic hedging activities
0.05
-
-
-
0.01
0.06
Unrealized gains related to nuclear decommissioning trust funds
0.05
-
-
-
-
0.05
Retirements of fossil generation units
(0.01)
-
-
-
-
(0.01)
Constellation merger and integration costs
(0.06)
(0.00)
(0.01)
(0.00)
(0.09)
(0.16)
Maryland commitments
(0.03)
-
-
(0.12)
(0.17)
(0.32)
Amortization of commodity contract intangibles
(0.11)
-
-
-
-
(0.11)
FERC settlement
(0.25)
-
-
-
-
(0.25)
Plant divestitures
(0.00)
-
-
-
-
(0.00)
Reassessment of state deferred income taxes
0.02
-
-
-
0.15
0.17
Other acquisition costs
(0.00)
-
-
-
-
(0.00)
1Q 2012 GAAP Earnings (Loss) Per Share
$0.24
$0.13
$0.14
$(0.09)
$(0.12)
$0.28
34
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
-
Certain costs 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
-
Revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger
-
Non-cash benefit associated with a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s
deferred taxes as a result of the merger
-
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
2012 Analyst Meeting – Performance that Drives Progress
(1)   For the three months ended March 31, 2012, includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.
Note:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.


Constellation
Ken Cornew
EVP and Chief Commercial Officer of Exelon
and President and CEO of Constellation


36
Commercial Business Overview
Scale, Scope and Flexibility Across the Energy Value Chain
Development and
exploration of natural gas
and liquids properties
11 assets in
seven states
~295 BCFe of proved
Reserves
(1)
Largest 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     
~465 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
~2,000 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 4/30/2012, net of physical market mitigation (Brandon Shores, C.P. Crane and H.A. Wagner ~2,648 MW).
(3)  Expected for 2012 as of 4/30/2012. Electric load and gas includes fixed price and indexed products. No stub period adjustment for legacy Constellation contribution.
(4)  Load Response estimate as of 4/30/2012.
2012 Analyst Meeting – Performance that Drives Progress


37
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
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 
Largest Merchant
Generation Fleet
Portfolio and Risk
Management
Electric Load Serving
Business
Expand into
new markets
Cross sell new
products and
services
Benefit from
matching
generation and
load
Capital and
collateral
efficiency
2012 Analyst Meeting – Performance that Drives Progress


38
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
Credit Rating
Capital
Structure
Capital &
Operating
Expenditure
Dividend
2012 Analyst Meeting – Performance that Drives Progress
Strategic Policy Alignment
Three-Year Ratable Hedging
Bull / Bear Program
•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
•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
•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


39
Portfolio Management Approach
Block Energy
Basis
Load Shape
Renewable
Ancillaries
Capacity
Transmission
Pricing and Portfolio Management Approach
Full
Requirements
Components
(1)
Hedged primarily with
owned or contracted
generation –
baseload,
intermediate &
peaking assets
Hedged primarily via
market based
products –
blocks,
fixed load shapes,
options, RECs
Transmission
& Capacity
Block Energy,
Basis,
Load Shape,
Renewables &
Ancillaries
Constellation's model will be an integrated approach to load management, selling
the products that closely tie to its asset portfolio
Constellation
approach
Load Following Pricing Build Up
(Illustrative)
Integrated Portfolio
Pure Play Retail
Mostly Fixed
2012 Analyst Meeting – Performance that Drives Progress
(1) Full requirements pricing build up is for illustrative purpose and not reflective of any one particular product or zone. Margins are not reflected in the build up.


Renewables
Baseload
Intermediate
Peaking
Generation capacity
40
Generation and Load Match
Our generation portfolio is low cost,
flexible and diverse
Generation and load positions are well
balanced across multiple regions
Adequate intermediate and peaking
capacity within the portfolio for managing
peaking load
Continue to buy or sell length from
market to manage portfolio needs
15
14
4
16
21
17
20
18
56
74
27
101
22
New York
18
New England
30
ERCOT
44
MidAtlantic
113
MidWest
129
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 
2012 in TWh
(1,2)
Expected Load
Expected Generation
Generation & Load Match: Competitive Advantage
South, West
& Canada
2012 Analyst Meeting – Performance that Drives Progress
(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 4/30/2012.


24%
41
Electric Load Serving Business: Growth Target
0
20
40
60
80
100
120
140
160
180
200
220
170
+20%
2014E
35-45%
200
65-75%
25-35%
2013E
180
65-75%
25-35%
2012E
55-65%
2011A
170
90
80
Retail Load
(2)
Wholesale Load
Total Contracted
Commercial Load
(1)
2011 –
2014 TWh
Load Split by Customer Class 
(2011 TWh)
Well positioned for growth in volumes and
margins on the back of a sustainable platform
and new opportunities
A diverse set of customers enhances margin
opportunities from a sales and portfolio
management standpoint
Mass Markets
<1,000 MWhs per year
Small C&I
1,001-5,000 MWhs per year
Medium C&I
5,001-25,000 MWhs per year
Large C&I
>25,000 MWhs per year
46%
Wholesale
Large C&I
15%
Medium C&I
8%
Small C&I
7%
Mass Markets
C&I = Commercial & Industrial
Load Size
Customer Type
2012 Analyst Meeting – Performance that Drives Progress
(1)
Numbers and percentages are rounded to the nearest 5
(2)
Index load expected to be 20% to 30% of total forecasted retail load


18%
42
Electric Load Serving Business: Strategy
Constellation is well positioned in a U.S. market where capacity
available for
competitive supply has room to grow
Total U.S. Power Market in 2012
Estimated
Load
~
3,700
TWh
(1)
(1) Source: EIA, KEMA and internal estimates. 
Through retail and wholesale channels, Constellation
currently serves 170 TWhs, or approximately 5%, of total
U.S. power demand
Expected Total Competitive Market Growth
Underlying load growth
More than 1% annual load growth across the U.S.
Switched market expected to grow by approximately 11% in
C&I from 2011 to 2014
Existing markets: PA and OH
New markets: MI and AZ
Switched market expected to grow by approximately 15% in
residential from 2011 to 2014
Strategy to Grow
As existing markets grow and new markets open, serve new
customers
Improve market share in existing markets
Cross sell suite of products to existing customers
Create more value with customers
Utilize data and technology to expand product offerings
Achieve higher renewal rates
Distinguish our brand
Leverage operational efficiency
Eligible Non-Switched
16%
Eligible Switched
19%
Muni/Co-Op Market
Other
Ineligible
47%
2012 Analyst Meeting – Performance that Drives Progress


43
ExGen Disclosure Overview
Continue
to
provide
transparency
in
our
ExGen
disclosures
with
a
modified
and
expanded
framework that incorporates new business lines and regions
Continue to provide open gross margins, expected generation, hedge %, reference prices and effective realized
energy prices (EREP)
Also provide Mark-to Market (MtM) value of all hedges on a consolidated basis
Consider retail and wholesale load to be an alternate channel to
market our generation. As such, executed sales are
regarded as a hedge and thus flow into MtM, EREP and hedge percentage
Provide volume targets and track sales execution versus targets on an annual basis
Introduction of new gross margin categories
In addition to Open Gross Margin and MtM of hedges, gross margins will be provided for the following categories -
Power New Business: Gross margins from future hedging activity via retail, wholesale or structured
transaction/mid-marketing activities. Once power sales are executed, these flow into MtM via EREP
Non Power New Business: Gross margins from planned sales from business activities not related to hedging
power
production,
such
as
Load
Response,
Energy
Efficiency,
Retail
and
Wholesale
Gas,
Proprietary
Trading
(1)
etc.
Once
sales
are
executed,
gross
margins
will
flow
to
“Non
Power
Executed”
category.
Non Power Executed: Contracted gross margin associated with business activities not directly linked to production
or sale of power
Introduction of new regions
To reflect our expanded national presence, New England, New York, and South, West & Canada regions have been
added to Midwest, Mid-Atlantic and ERCOT
Hedged gross margins for South, West & Canada will be included within the consolidated “Open Gross Margin”
estimate
The other five regions will have corresponding expected generation, hedge %, reference prices and EREP
2012 Analyst Meeting – Performance that Drives Progress
(1) Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non power” executed category.
Maintain ability to value generation fleet on an open and hedged basis
No separate gross margins for commercial load, but will disclose volume targets and sales execution


44
Components of Gross Margin Categories
Open Gross
Margin
•Generation Gross
Margin at current
market prices,
including
capacity &
ancillary
revenues 
•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
Hedges
(2)
•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
“Power”
New
Business
•Retail, Wholesale
planned electric
sales
•Portfolio
Management
new business
•Mid marketing
new business
“Non Power”
Executed
•Retail, Wholesale 
executed gas
sales
•Load Response
•Energy Efficiency
•BGE Home
•Distributed Solar
“Non Power”
New Business
•Retail, Wholesale
planned gas
sales
•Load Response
•Energy Efficiency
•BGE Home
•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
Margins move from “Non power new business”
to
“Non power executed”
over the course of the year
Gross margin linked to power production and sales
Gross margin from
other business activities
(1) Hedged gross margins for South, West & Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region.
(2) MtM of hedges provided directly for the five larger regions. MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh.
(3) Proprietary trading gross margins will remain within “Non Power” New Business category andnot move to “Non power” executed category.
2012 Analyst Meeting – Performance that Drives Progress


45
ExGen Disclosures
Gross Margin Category ($ MM)
2012
(1)
2013
2014
Open Gross Margin
(2,3)
(including South, West, Canada hedged gross margin)
$4,300
$5,800
$6,250
Mark-to-Market of Hedges
$3,150
$1,400
$500
Power New Business / To Go
$200
$550
$850
Non-Power Margins Executed
$200
$100
$50
Non-Power New Business / To Go
$200
$500
$550
Total Gross Margin
$8,050
$8,350
$8,200
Generation and Hedges
2012
(1)
2013
2014
Exp. Gen (GWh)
219,900
218,400
210,200
Midwest
101,800
97,900
97,800
Mid-Atlantic
(2,3)
71,300
74,100
72,000
ERCOT
19,900
18,800
16,100
New York
(3)
13,400
13,400
10,500
New England
13,500
14,200
13,800
% of Expected Generation Hedged
97-100%
73-76%
41-44%
Midwest
94-97%
77-80%
44-47%
Mid-Atlantic
(2,3)
105-108%
74-77%
45-48%
ERCOT
(4)
89-92%
56-59%
34-37%
New York
(3)
91-94%
69-72%
20-23%
New England
(4)
94-97%
66-69%
27-30%
Effective Realized Energy Price ($/MWh)
Midwest
$41.00
$39.50
$37.00
Mid-Atlantic
(2,3)
$53.00
$49.00
$49.00
ERCOT
(4)
$8.50
$6.00
$3.00
New York
(3)
$45.00
$37.00
$37.50
New England
(4)
$8.00
$8.50
$3.50
(1) Stub period was calculated by excluding Jan 2012 thru mid-March 2012 for Constellation only.
(2) Excludes Maryland assets to be divested.
(3) Includes  Constellation Energy Nuclear Group (CENG) Joint Venture.
Reference Prices  (ATC -$/MWh)
(5)
2012
2013
2014
Henry Hub Natural Gas ($/MMbtu)
$2.47
$3.45
$3.87
Midwest: NiHub
$26.71
$30.28
$32.45
Mid-Atlantic: PJM-W
$32.70
$37.93
$40.37
ERCOT-N ATC Spark Spread
$11.10
$9.19
$8.50
New York: NY Zone A
$26.99
$31.40
$33.46
New England: Mass Hub Spark Spread
$5.98
$4.66
$3.50
2012 Analyst Meeting –
Performance that Drives Progress
(4) Spark spreads shown for Texas and New England.
(5) Based on April 30, 2012 market conditions.


46
Closing Remarks
RPM PY 2015/2016 Auction Results
Results were in line with internal expectations of pricing improvement vs. last year’s auction
Moderate growth in cleared Demand Response (DR) signals continued DR bidding discipline
Best Positioned Merchant Generation Portfolio
Continue to believe the upside associated with net retirements and higher operational costs in
the range of $3-5/MWh in PJM, with a large portion not currently reflected in energy prices  
Effective Risk Management
Well established criteria and effective oversight to manage and monitor risk
Small proprietary trading function and contribution to gross margin
Nation’s Number One Energy Marketer
Best positioned to capture additional load as new markets open and existing markets mature
Matching generation to load, and an extensive suite of products and services, provides us with
a competitive advantage
We are well positioned to expand our business across many fronts
and deliver on
overall commercial business growth
2012 Analyst Meeting – Performance that Drives Progress


47
Appendix
2012 Analyst Meeting – Performance that Drives Progress


48
Generation Capacity Market Positions
2011/2012
2012/2013
2013/2014
2014/2015
2015/2016
PJM
(1)
RTO 
Capacity
27,400
12,800
11,500
11,500
11,500
Price
$110
$16
$28
$126
$136
EMAAC
Capacity
(2)
9,200
9,200
9,200
9,200
Price
$140
$245
$137
$168
MAAC 
Capacity
2,600
2,700
2,700
2,700
Price
$133
$226
$137
$168
SWMAAC
Capacity
(3)
1,900
1,900
1,900
1,900
Price
$133
$226
$137
$168
New England
(4)
NEMA  
Capacity
2,100
2,100
2,100
2,100
2,100
Price
$104
(5)
$85
(5)
$85
(5)
$107
$114
SEMA
Capacity
35
35
35
35
35
Price
$104
(5)
$85
(5)
$85
(5)
$95
(5)
$104
(5)
Rest of Pool  
Capacity
700
700
700
700
700
Price
$104
(5)
$85
(5)
$85
(5)
$95
(5)
$104
(5)
NYISO
(6)
Rest of Pool  
Capacity
1,100
1,100
1,100
1,100
1,100
MISO
(7)
AMIL 
Capacity
1,100
1,100
1,100
1,100
1,100
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.
2012 Analyst Meeting – Performance that Drives Progress
(1) Reflects owned and contracted generation  installed capacity (ICAP) adjusted for mid – year PPA roll offs.
(2) ICAP is net of Eddystone 1&2, Cromby 1&2 (total ~ 933 MW), which are not included PY 11/12 onwards reflecting  decision in December 2009 to permanently retire  these units.
(3) ICAP for all years beginning PY 11/12 excludes capacity for units to be divested (Brandon Shores, Wagner & Crane ~2,648 MW). Constellation offered these units in PY11/12 - PY 15/16 auctions.
(4) Reflects Qualified Summer Capacity including owned and contracted units.
(5) Price is pro-rated for auctions that clear at the floor price and there is more capacity procured than suggested by the reliability requirement.
(6) Reflects 50.01% ownership in CENG;  (7) Does not include wind under PPA. 


49
Capacity Market Background
PJM Reliability Pricing Model (RPM)
Base
Residual
Auction
is
held
3
years
in
advance
for
1-year
term
97.5% of Reliability Requirement is targeted to be procured
Demand curve based approach to procurement
Three Incremental Auctions are held prior to delivery
2.5% of Reliability Requirement is targeted to be procured
ISO-NE Forward Capacity Market (FCM)
Forward
Capacity
Auction
is
held
3
years
in
advance
for
1-year
term
100% of Installed Capacity Requirement is procured
Descending clock auction with administrative floor price
Three Reconfiguration Auctions are held prior to delivery and Monthly Spot Auctions are held
during the delivery year
NYISO Capacity Auctions
Annual procurement for prompt planning year
Split into summer and winter seasonal auctions
Demand curve based approach to procurement
Monthly and spot auctions are held during the delivery year
2012 Analyst Meeting – Performance that Drives Progress


50
Electric Load Serving Business: Background
#1
retail
C&I
power
provider
with
17%
share
of
the
switched
commercial
and
industrial
market
(1)
Top 10 provider of residential power
Active in all U.S. power markets and products and serving over 2/3rds of Fortune 100 companies
(1)  Exelon and Constellation combined retail businesses.  Source: KEMA, “The Retailer Yearbook”, December 2011.
National Presence
Constellation is the leading power supplier in the U.S. with coast to coast
presence and a large suite of product offerings
Multiple Avenues & Scalable Platform
Back Office
Systems
Experienced
Sales Force
Innovative
Marketing
Strong Brand
Recognition
Scalable Platform
Multiple
Products
Multiple
Channels
Multiple
Customers
Multiple
Markets
2012 Analyst Meeting – Performance that Drives Progress


51
Load Response
Estimated Total                       
Available Market = 100 GW
(1)
30%
30%
C&I Switched
C&I Available
Residential Available
40%
National Presence
Portfolio Size
Approximately 2 GW of load response under contract
Market Potential
Roughly 100 GW total market potential of which 30 GW is located in active ISO Demand Response markets
Growth Strategy and Objectives
Share capture in maturing formal ISO demand response capacity programs
Focus on growth opportunities in economics and reserve programs
2012 Analyst Meeting – Performance that Drives Progress
(1) Source: FERC/McKinsey. Customer class as % of total market. Not including municipals, cooperatives and utility driven DR programs.


52
Energy Efficiency
National Presence
Estimated Total                       
Available Market = 20 GW
(1)
6%
Residential
94%
Non Residential
(1)
Source: EPRI/McKinsey. Customer class as % of total market.
Portfolio Size
Over 4,000 energy savings projects have been implemented to date
Market Potential
$5 billion to $6 billion in annualized revenue
Approx.
40%
located
in
non-competitive
markets
allowing
growth
beyond
key
traditional
power
markets
Growth Strategy and Objectives
Focus
on
government,
education,
healthcare
and
multi-family
housing
sectors
Combined product offering primarily focuses on commercial and industrial customers
2012 Analyst Meeting – Performance that Drives Progress
States with Current Constellation EE
Presence
Regulatory Environment Benefiting EE Projects
Lack of Regulation Benefiting EE Projects


53
Distributed Solar
Portfolio Size
Of
the
company’s
345
MW
of
solar
installations
owned
or
under
construction
(all
expected
to
be
operational
by 2013), approximately 59 MW are non-utility scale installations for our commercial, industrial and public
sector customers
Market
Potential
(2)
Unsubsidized economic potential for distributed residential and commercial solar PV in the U.S. likely to reach
10 to 12 GW by the end of 2012
Growth Strategy and Objectives
Focus
on
states
with
established
incentives
markets
in
place
MD,
NJ,
MA
and
CA
and
where
there
is
potential
for
new
incentive
markets
CT
and
NY
Pursue
opportunities
in
non-Solar
REC
markets
CO,
AZ
and
NM
where
there
is
increased
interest
in
solar
(1)
Excludes Antelope Valley Solar Ranch One (230 MW), Sacramento Municipal Utility District (30 MW), City Solar Project (10 MW) and Maryland Generating Clean Horizons (16 MW).
(2)
Source:
McKinsey,
“Solar
Power:
Darkest
Before
Dawn”
published
April
2012.
2012 Analyst Meeting – Performance that Drives Progress


54
Retail and Wholesale Gas
Retail Gas
(1)
(2011 –
2014 Bcf)
Retail Gas
Portfolio Size
465 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
Wholesale Gas
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
385
0
50
100
150
200
250
300
350
400
450
500
550
2014E
530
2013E
505
2012E
465
2011A
Retail Gas
Contribution from ONEOK Energy
Marketing Company acquisition
(1)
Estimate as of 4/30/2012.
2012 Analyst Meeting – Performance that Drives Progress
+14%
+21%


55
ExGen Disclosures
April 30, 2012
2012 Analyst Meeting – Performance that Drives Progress


56
ExGen Disclosures 
Gross Margin Category ($ MM)
2012
(2)
2013
2014
Open Gross Margin
(including South, West & Canada hedged GM)
(3,4)
$4,300
$5,800
$6,250
Mark to Market of Hedges
(5)
$3,150
$1,450
$550
Power New Business / To Go
$200
$550
$850
Non-Power Margins Executed
$200
$100
$50
Non-Power New Business / To Go
$200
$500
$550
Total Gross Margin
$8,050
$8,350
$8,200
(1) Gross margin rounded to nearest $50M.
(2) Stub period calculated by excluding Jan 2012 thru mid-March 2012 for Constellation only.
(3) Excludes Maryland assets to be divested.
Reference Prices
(6)
2012
2013
2014
Henry Hub Natural Gas ($/MMbtu)
$2.47
$3.45
$3.87
Midwest: NiHub ATC prices ($/MWh)
$26.71
$30.28
$32.45
Mid-Atlantic: PJM-W ATC prices ($/MWh)
$32.70
$37.93
$40.37
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$11.10
$9.19
$8.50
New York: NY Zone A ($/MWh)
$26.99
$31.40
$33.46
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$5.98
$4.66
$3.50
(4) Includes CENG Joint Venture.
(5) Mark to Market of Hedges assumes mid-point of hedge percentages.
(6) Based on April 30, 2012 market conditions.
2012 Analyst Meeting – Performance that Drives Progress
(1)


57
ExGen Disclosures
Generation and Hedges
2012
(1)
2013
2014
Exp. Gen (GWh)
(4)
219,900
218,400
210,200
Midwest
101,800
97,900
97,800
Mid-Atlantic
(2,3)
71,300
74,100
72,000
ERCOT
19,900
18,800
16,100
New York
(3)
13,400
13,400
10,500
New England
13,500
14,200
13,800
% of Expected Generation Hedged
(5)
97-100%
73-76%
41-44%
Midwest
94-97%
77-80%
44-47%
Mid-Atlantic
(2,3)
105-108%
74-77%
45-48%
ERCOT
89-92%
56-59%
34-37%
New York
(3)
91-94%
69-72%
20-23%
New England
94-97%
66-69%
27-30%
Effective Realized Energy Price ($/MWh)
(6)
Midwest
$41.00
$39.50
$37.00
Mid-Atlantic
(2,3)
$53.00
$49.00
$49.00
ERCOT
7
$8.50
$6.00
$3.00
New York
(3)
$45.00
$37.00
$37.50
New England
(7)
$8.00
$8.50
$3.50
(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 at Exelon-operated nuclear plants and Salem but excludes CENG.  Expected
generation assumes capacity factors of 93.5%, 93.3% and 93.8% in 2012, 2013 and 2014 at Exelon-operated nuclear plants excluding Salem and CENG. These estimates of
expected generation in 2012, 2013 and 2014 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.
2012 Analyst Meeting – Performance that Drives Progress


58
ExGen Hedged Gross Margin Sensitivities
Gross Margin Sensitivities (With Existing Hedges) 
(1, 4)
2012
2013
2014
Henry Hub Natural Gas ($/MMbtu)
(2)
+ $1/Mmbtu
$(70)
$155
$570
-
$1/Mmbtu
$85
$(130)
$(505)
NiHub ATC Energy Price
+ $5/MWh
$20
$105
$295
-
$5/MWh
$(10)
$(105)
$(290)
PJM-W ATC Energy Price
(2)
+ $5/MWh
$(20)
$90
$205
-
$5/MWh
$25
$(90)
$(200)
NYPP Zone A ATC Energy Price
+ $5/MWh
$10
$25
$45
-
$5/MWh
$(10)
$(25)
$(45)
Nuclear Capacity Factor
(3)
+/-
1%
+/-
$25
+/-
$40
+/-
$40
(1) Based on April 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.
2012 Analyst Meeting – Performance that Drives Progress


59
Exelon Generation Hedged Gross Margin Upside/Risk
6,000
6,500
7,000
7,500
8,000
8,500
9,000
9,500
10,000
2014
2013
2012
$8,200
$7,800
$8,900
$8,000
$9,500
$7,200
2012 Analyst Meeting – Performance that Drives Progress
(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 and 2014 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 April 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.


60
Upstream E&P Assets
(1)
Oil/NGL conversion to gas is 6:1.
(2)
Constellation does not operate any of its properties.
Estimated Net
Proved Reserves
(as of 12/31/11)
Average Net Daily
Production
(Q1 2012)
Forecasted Production
2012
2013
2014
295 Bcfe
67 MMcfe
Net Daily Prod
(MMcfe / day)
55 -
70
55 -
70
60 -
75
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)
Trenton Black River (MI)
Current Portfolio of Investments
2012 Analyst Meeting – Performance that Drives Progress


ExGen Disclosures Guide
61
2012 Analyst Meeting – Performance that Drives Progress


ExGen Disclosure Overview
Continue
to
provide
transparency
in
our
ExGen
disclosures
with
a
modified
and
expanded
framework that incorporates new business lines and regions
Continue to provide open gross margins, expected generation, hedge %, reference prices and effective realized
energy prices (EREP)
Also provide Mark-to Market (MtM) value of all hedges on a consolidated basis
Consider
retail
and
wholesale
load
to
be
an
alternate
channel
to
market
our
generation.
As
such,
executed
sales
are regarded as a hedge and thus flow into MtM, EREP and hedge percentage
Provide volume targets and track sales execution versus targets on an annual basis
Introduction of new gross margin categories
In addition to Open Gross Margin and MtM of hedges, gross margins will be provided for the following categories -
Power New Business:
Gross margins from future hedging activity via retail, wholesale or structured
transaction/mid-marketing activities. Once power sales are executed, these flow into MtM via EREP
Non Power New Business: Gross margins from planned sales from business activities not related to hedging
power
production,
such
as
Load
Response,
Energy
Efficiency,
Retail
and
Wholesale
Gas,
Proprietary
Trading
(1)
etc.
Once
sales
are
executed,
gross
margins
will
flow
to
“Non
Power
Executed”
category.
Non Power Executed: Contracted gross margin associated with business activities not directly linked to production
or sale of power
Introduction of new regions
To reflect our expanded national presence, New England, New York, and South, West & Canada regions have been
added to Midwest, Mid-Atlantic and ERCOT
Hedged gross margins for South, West & Canada will be included within the consolidated “Open Gross Margin”
estimate
The other five regions will have corresponding expected generation, hedge %, reference prices and EREP
Maintain ability to value generation fleet on an open and hedged basis
No separate gross margins for commercial load, but will disclose volume targets and sales execution
(1) Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non power” executed category.
62
2012 Analyst Meeting – Performance that Drives Progress


63
ExGen Disclosure Overview
Gross Margin Categories ($ MM)
For all regions, three years forward
General Description
Open Gross Margin
Value of generation at current market prices, excluding the impact of any near-
term hedges
Mark to Market of Hedges
Mark-to-market value of transactions associated with hedging open generation
position (power or fuel hedges, including executed retail/wholesale electric load)
Power New Business / To Go
New category of gross margins for future hedging activity via retail, wholesale or
structured transaction / mid marketing activities.
Non-Power Margins Executed
New category for contracted gross margin associated with business activities not
directly linked to production or sale of power
Non-Power New Business / To Go
New category for gross margins from planned sales from business activities not
related to hedging power production
Total Gross Margin
Sum total of each of the five gross margin categories
Generation & Hedges
General Description
Expected Generation (GWh)
Anticipated output from owned or contracted generating capacity
% of Expected Generation Hedged
Physical or financial hedges against power output
Effective Realized Energy Price
Close proxy for the hedged power price or spark, and when used in conjunction
with the reference price and hedged MWh  yields the MtM of hedges.
Retail & Wholesale Volumes
General Description
Electric load target & contracted volumes
Estimate of load sales target and sales executed from all load
channels
Retail gas target
Estimate of gas sales target
2012 Analyst Meeting – Performance that Drives Progress


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
Open Gross
Margin
•Generation Gross
Margin at current
market prices,
including
capacity &
ancillary
revenues 
•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
Hedges
(2)
•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
“Power”
New
Business
•Retail, Wholesale
planned electric
sales
•Portfolio
Management
new business
•Mid marketing
new business
“Non Power”
Executed
•Retail, Wholesale 
executed gas
sales
•Load Response
•Energy Efficiency
•BGE Home
•Distributed Solar
“Non Power”
New Business
•Retail, Wholesale
planned gas
sales
•Load Response
•Energy Efficiency
•BGE Home
•Distributed Solar
•Portfolio
Management /
origination fuels
new business
•Proprietary
trading
(3)
(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 andnot move to “Non power” executed category.
64
2012 Analyst Meeting – Performance that Drives Progress


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 
$5.8 billion
(B)
Expected Generation (TWh)
97.9
74.1
18.8
13.4
14.2
(C)
Hedge % (assuming mid-point of range)
78.5%
75.5%
57.5%
70.5%
67.5%
(D=B*C)
Hedged Volume (TWh)
76.9
55.9
10.8
9.4
9.6
(E)
Effective Realized Energy Price ($/MWh)
$39.50
$49.00
$6.00
$37.00
$8.50
(F)
Reference Price ($/MWh)
$30.28
$37.93
$9.19
$31.40
$4.66
(G=E-F)
Difference ($/MWh)
$9.22
$11.07
($3.19)
$5.60
$3.84
(H=D*G)
Mark-to-market
value
of
hedges
($
million)
(1)
$715 million
$625 million
($35) million
$55 million
$40 million
(I=A+H)
Hedged Gross Margin ($ million)
$7,200 million
(J)
Power New Business / To Go ($ million)
$550 million
(K)
Non-Power Margins Executed ($ million)
$100 million
(L)
Non-
Power New Business / To Go ($ million)
$500 million
(N=I+J+K+L)
Total Gross Margin
$8,350 million
(1) Mark-to-market rounded to the nearest $5 million. 
65
2012 Analyst Meeting – Performance that Drives Progress


66
Constellation Energy Nuclear Group (CENG) Background
As
a
result
of
Exelon’s
equity
interest
in
CENG,
PPA
contracts
between
CENG
and
3
parties
and
the
PPA
between
CENG and ExGen,  some background on CENG and how CENG gross margins and earnings are reflected in ExGen
disclosures and other financial statements.
Calvert 1&2
NMP 1
NMP 2
(1)
Ginna
(2)
Ownership Interest
Total Plant Capacity
1, 750 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)
875 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.
(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.
2012 Analyst Meeting – Performance that Drives Progress
rd


67
Constellation Energy Nuclear Group (CENG) Background
•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)
•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
ExGen Disclosures
Forward Estimates
Financial Statements
(10-Q, 10-K, Earnings Release tables)
Actuals
2012 Analyst Meeting – Performance that Drives Progress


Competitive Markets
Bill Von Hoene
Senior EVP & Chief Strategy Officer


Drive Competition and Choice
We believe in the value competitive energy markets bring to our customers via
choice, innovation and savings
Retail Markets
Wholesale Markets
Perfect Core Markets
Support continued growth of competitive retail choice
for energy and services in restructured states
Defend Open Markets
Oppose and defeat efforts to limit competitive retail
choice for energy and services
Support Transparent Pricing Mechanisms
Promote the establishment of market rules that
provide transparent price signals for energy and
capacity and allow a level playing field for all
providers to compete
Defend Well Functioning Wholesale Markets
Oppose government mandates to subsidize
unneeded, uneconomic generation. Challenge
illegalities of legislative or regulatory construct and
strengthen mitigation measures via FERC (e.g. MOPR)
We champion competitive energy markets to empower our customers and
enhance value for our shareholders
Expand into Restricted or Closed Markets
Enable competitive retail choice for energy & services
in states that limit or are closed to competition
69
2012 Analyst Meeting – Performance that Drives Progress


Perfecting Existing Retail Energy Markets
Opportunity to offer savings for residential class
continues to support switching
56% of eligible Illinois load is served by
competitive suppliers
Over 200 communities approved ballot
measures to allow municipal aggregation
Increased consumer protection encourages
residential consumers to pursue retail supply
Core retail markets are adopting continuous improvements to enhance shopping
and expand customer experience
PAPUC moving steadily toward a fully
competitive end state
60% of eligible Pennsylvania load is served
by competitive suppliers
Retail markets assessment targeting
improvements to retail market
Reforms of default service likely to
stimulate retail shopping
Exelon looking to build partnership with Maryland
energy stakeholders
56% of eligible Maryland load is served by
competitive suppliers
Web portal for residential electricity price
comparison
Steadfast commitment to retail competition
Market volatility creates opportunities for
risk management and enhanced products
and services
High penetration of smart meter
installation and state-wide, standardized
customer data interface creates
opportunities for increased products and
services
Note: PAPUC = Pennsylvania Public Utility Commission; AMI = Advanced Metering Infrastructure.
Illinois
Pennsylvania
Maryland
Texas
70
2012 Analyst Meeting – Performance that Drives Progress


Defense of Competitive Markets
71
Our regulatory advocacy efforts are designed to improve the functioning of
competitive markets where they exist and protect against attempts to undermine
price signals
We actively seek opportunities to preserve the integrity of competitive markets    
We participate in, or if necessary initiate, proceedings at FERC and at state commissions to
protect
the
efficient
functioning
of
wholesale
and
retail
markets
and
thwart
attempts
to
undermine price signals
A current example is our efforts to defend forward capacity markets in PJM from the
exercise of buyer market power by states and load interests
A
key
component
of
energy
market
regulation
is
the
principle
of
comparability;
all
resources,
whether
existing,
new,
renewable,
fossil
or
nuclear,
should
have
a
level
playing
field
and
the
ability to compete on a best price basis.  Supply and demand resources should be expected to
meet the same performance criteria if they receive the same compensation
Transmission
is
a
critical
element
of
wholesale
market
liquidity,
so
we
seek
to
develop
or
facilitate the development of transmission upgrades that reduce congestion around our assets
We
utilize
public
messaging
and
are
active
in
coalitions
such
as
COMPETE
to
inform
consumers of the value of competition
2012 Analyst Meeting – Performance that Drives Progress


Opportunities to Expand Competitive Retail Energy Markets
Considering opening the market to retail choice
Customer/supplier advocacy efforts to
encourage policymakers and commission to
take action to re-open retail shopping
Recent rate case settlement includes pilot
shopping program
There is a growing interest to open or expand competition in markets with
restricted or non-existent retail choice
Increase existing Direct Access Cap
Existing program fully subscribed
Incremental shopping eligibility fills within
seconds
Exit fees remain a challenge
Community Choice Aggregation still an option
Increase or remove existing 10% electric choice
cap and enable more customers to select their
provider of choice
Current program is fully subscribed
Legislation introduced to raise shopping cap
to 19% to accommodate current waiting list
Significant improvement in retail competition with
the changes in the Electric Security Plan to phase-
in competition but there is room for further
enhancements
50% of eligible Ohio load is served by
competitive suppliers
Outlook suggests competitive solicitations for
utility standard service offer
Utilities moving assets to participate in PJM
RPM market
72
2012 Analyst Meeting – Performance that Drives Progress
Arizona
California
Michigan
Ohio


Asset Divestiture Update
Executed purchase and sale agreement expected by August 2012
Maryland assets to be divested are an attractive investment for potential buyers
Plants are well-positioned to comply with Air Toxics Standards and Cross-State Air
Pollution Rule (CSAPR)
Located
in
Southwestern
MAAC
region,
an
attractive
region
within
PJM
Near major urban centers with stable demand
Brandon Shores
H.A. Wagner
C.P. Crane
1,273 MW capacity
2 unit coal plant
976 MW capacity
5 unit coal/oil/gas
plant
399 MW capacity
3 unit coal/oil plant
73
2012 Analyst Meeting – Performance that Drives Progress


Exelon Utilities
Denis O’Brien
Senior EVP of Exelon and
CEO of Exelon Utilities


Exelon Utilities –
Leveraging Operational Expertise
Exelon Utilities will deliver best-in-class operational and financial performance,
creating greater value for our stakeholders
Achieving best-in-class performance:
Set a strategic direction to be among the best
Ensure that each utility performs to the highest standards
Drive for standardization and sharing of best practices
Realize merger synergies across the utilities
2011 Revenues: $3.0B
Employees: ~3,400
Electric customers: 1.2 million
Gas customers: 0.7 million
Service Territory: 2,300 square miles
All-Time Peak Load: 7,616 MW
Baltimore, Maryland
Philadelphia, Pennsylvania
2011 Revenues: $3.7B
Employees: ~2,400
Electric customers: 1.6 million
Gas customers: 0.5 million
Service Territory: 2,100 square miles
All-Time Peak Load: 8,983 MW
2011 Revenues: $6.1B
Employees: ~5,800
Electric customers: 3.8 million
Service Territory: 11,300 square miles
All-Time Peak Load: 23,753 MW
Chicago, Illinois
75
2012 Analyst Meeting – Performance that Drives Progress


ComEd –
Growth through Investment that Benefits Customers
Driving innovative legislative and regulatory policy to benefit customers, improve
ratemaking process transparency and enable economic development
Energy Infrastructure Modernization Act (EIMA)
Formula Rate Process
Driving investment in electricity infrastructure and
smart meter/smart grid
$2.6B over 10 years
Making investments that benefit customers
Smart meters
Distributed automation
Storm hardening
Monitoring performance standards and metrics
Providing for returns on investment
Performance-based distribution formula rate
recovery
Distribution:
Nov. 2011 initial filing (2010 calendar year + 2011 net
plant additions) proposed $59M decrease in revenue
requirement
10.05% ROE (12-month average of the 30-year US
Treasury yield plus 580 basis point risk premium)
May 2012 ICC ordered $168M decrease
April 2012 first annual update (2011 calendar year +
2012 net plant additions) and 2011 reconciliation filing;
rates effective following January
Latest annual formula rate update filed in May 2012,
increased revenue requirement ~$23M
Rates effective June 2012
FERC approved 11.50% ROE
Economic Development Initiatives
Illinois Economic Development Corporation Act
introduced to form public-private partnership
supporting business expansion and creating jobs
ComEd’s Economic Development team targeting new
facilities in northern Illinois, including  expansion of
data centers, warehouses and manufacturing
Transmission Growth
Several upgrade projects planned
Burnham to Taylor lines will reinforce transmission
system and increase capacity to reliably serve the
Chicago southern business district
Capital spend estimated at ~$150M
In-service date planned for June 2014
Note: ICC = Illinois Commerce Commission; FERC = Federal Energy Regulatory Commission
76
2012 Analyst Meeting – Performance that Drives Progress
Transmission:


77
PECO –
Competitive Market Initiatives
Supporting competitive procurement markets and evaluating longer-term
opportunities of Act 11
Alternative Ratemaking
Rate Case Update
Electricity Supply Procurement
Newly enacted Act 11 (HB 1294) provides a distribution
system improvement charge (DSIC) to support electric
and gas infrastructure investment
Provision for use of fully projected future test year
in rate cases
Requires submission of long-term infrastructure
improvement plan
DSIC capped at 5% of distribution rates
PAPUC DSIC rulemaking underway
Distribution:
In Dec. 2010, PAPUC approved settlement of electric
and gas rate cases; no allowed ROE specified
Increase in annual service revenue of $225M for electric
and $20M for gas effective 1/1/11
No rate cases currently planned; timing of future filings
will depend on load and expense forecasts and
implementation of DSIC
PAPUC-approved Default Service Plan (DSP) Program
has 29-mo. term that ends 5/31/13
PECO filed second DSP outlining plan from 6/1/13
through 5/31/15
As of May 2012, ~28% of total retail customers
purchased energy from alternative suppliers,
representing ~60% of load
PAPUC evaluating alternative default service models to
enhance competition
Growth Initiatives
Executing $650M Smart Grid investment plan with
surcharge recovery for AMI costs
Support potential sales and repurposing of oil refineries
Convert oil and propane usage to natural gas
Enhance economic development outreach
Note: PAPUC = Pennsylvania Public Utility Commission; AMI = Advanced Metering Infrastructure
2012 Analyst Meeting – Performance that Drives Progress


BGE –
Fulfilling Commitments
Fulfilling commitments to stakeholders with continued focus on
safety and reliability
Commitments to Maryland
Rate Case Update
Reinforced ring fencing
Maintaining employment and minimum O&M/capital
spending levels for 2 years
Rate credit of $100 per residential customer provided
in May/June 2012
$113.5M customer investment fund
First contribution to fund within 90 days from
merger close
MD Public Service Commission (MDPSC) set
June 15 deadline for parties to submit
preliminary proposals for allocating fund
MDPSC Service Quality and Reliability Regulations
Effective regulations establish standards in a variety
of service quality and reliability areas
Actions expected to add incremental costs beginning
in 2012 to achieve compliance and enhance system
reliability and customer satisfaction
Distribution:
Last electric and gas rate cases filed 5/7/10
MDPSC approved $31M electric revenue increase with
9.86% ROE and $10M gas increase with 9.56% ROE
New rates effective December 2010
Plan to file electric and gas cases in 2     half of 2012
with rates effective no more than 210 days after filing
Transmission:
Latest annual formula rate update filed in April 2012,
increased revenue requirement ~$18M
Rates effective June 2012
FERC approved 11.3% ROE
Transmission Growth
Transmission-related capital spend expected to total
~$690M through 2016
Majority of spend (~$450M) related to RTEP-
mandated projects for system upgrades and
enhancements
Note: RTEP = PJM’s Regional Transmission Expansion Plan
nd
78
2012 Analyst Meeting – Performance that Drives Progress


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.
Note:  ComEd program may be reevaluated given recent ICC rate order.
ComEd will invest ~$1.3B over
the next 10 years
Installation of nearly 4M smart electric meters to begin Q4 2012
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 formula rate beginning with May 2012
filing
BGE will invest up to $500M 
through 2015
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
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
PECO will invest up to $650M
through 2014
79
2012 Analyst Meeting – Performance that Drives Progress


80
Rate Base and ROE Targets
2012E
Long-Term Target
Equity Ratio
~48%
~53%
(3)
Earned ROE
5 -
6%
2012E
Long-Term Target
Equity Ratio
~45%
~53%
(1)
Earned ROE
6 -
7%
Smart meter and smart grid investment will be a key driver of rate base growth
Based on 30-yr.
US Treasury
(2)
($ in billions)
2014E
$5.5
$3.6
$0.7
$1.2
2013E
$5.2
$3.4
$0.7
$1.1
2012E
$5.1
$3.3
$0.7
$1.1
2011A
$4.9
$3.2
$0.7
$1.1
Electric Distribution
Electric Transmission
Gas Delivery
2012E
Long-Term Target
Equity Ratio
~56%
~53%
Earned ROE
11 -
12%
2014E
$9.7
$7.1
$2.5
2013E
$8.7
$6.5
$2.2
2012E
$8.2
$6.1
$2.1
2011A
$8.0
$6.1
$2.0
Distribution
Transmission
2014E
$5.0
$3.1
$0.9
$1.0
2013E
$4.6
$2.9
$0.7
$0.9
2012E
$4.4
$2.8
$0.6
$0.9
2011A
$4.0
$2.6
$0.5
$0.9
Electric Distribution
Electric Transmission
Gas Delivery
10%
10%
(1)  Equity component for distribution rates will be the actual capital structure adjusted for goodwill.
(2)
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.
(3)
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%.
Note: 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.
2012 Analyst Meeting – Performance that Drives Progress


81
Exelon Utilities
Exelon Utilities will provide opportunities to leverage scale and expertise to
achieve improved operational and financial results
Operational Excellence
Achieve top decile safety and top quartile reliability performance
Enhance customer satisfaction experience
Drive continuous cost management and productivity focus
Regulatory and Legislative Stewardship
Support competitive supply procurements
Invest in smart meter/smart grid infrastructure
Secure constructive rate recovery
Financial Discipline
Maintain strong investment grade credit ratings
Obtain appropriate allowed ROEs
Target long-term earned ROEs close to allowed
2012 Analyst Meeting – Performance that Drives Progress


82
Appendix
2012 Analyst Meeting – Performance that Drives Progress


83
Capital Expenditures
($ in billions)
2014E
$575
$275
$175
$50
$75
2013E
$500
$250
$125
$50
$75
2012E
$425
$225
$75
$50
$75
2011A
$475
$275
$75
$50
$75
Electric Distribution
Smart Meter/Smart Grid
(1)
Electric Transmission
Gas Delivery
2014E
$1,650
$1,100
$200
$350
2013E
$1,650
$1,025
$175
$450
2012E
$1,325
$950
$100
$275
2011A
$1,025
$750
$25
$250
Electric Distribution
Smart Meter/Smart Grid
Electric Transmission
2014E
$725
$325
$100
$150
$150
2013E
$725
$375
$100
$125
$125
2012E
(2)
$650
$350
$75
$75
$150
2011A
$600
$325
$125
$150
Electric Distribution
Smart Meter/Smart Grid
(1)
Electric Transmission
Gas Delivery
(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 $550M.
2012 Analyst Meeting – Performance that Drives Progress


ComEd Load Trends
4Q12
3Q12
2Q12
1Q12
4Q11
3Q11
2Q11
1Q11
Gross Metro Product
Residential
Large C&I
All Customer Classes
Note: C&I = Commercial & Industrial
Chicago
U.S.
Unemployment rate
(1)
8.6%
8.1%
2012 annualized growth in
gross domestic/metro product
(2)
1.6%                   2.1%
(1)
Source:  US Dept. of Labor (April 2012) and
Illinois Department of Security (April 2012)
(2)
Source: Global Insight (February 2012)
(3)
Not adjusted for leap year
2011 
1Q12        2012E
(3)
Average Customer Growth
0.4%  
0.3%    
0.4%
Average Use-Per-Customer
(1.7)%
(0.9)%
(1.3)%
Total Residential
(1.3)%   
(0.6)%       (0.9)%
Small C&I
(0.8)%
1.1%    
(0.1)%
Large C&I
0.6%  
0.9%     
(0.3)%
All Customer Classes
(0.5)%   
0.5%     
(0.3)%
Weather-Normalized Electric Load Year-over-Year
Key Economic Indicators
Weather-Normalized Electric Load
84
2012 Analyst Meeting – Performance that Drives Progress


85
ComEd Distribution Formula Rate Plan
2011 Formula Rate Filing (Docket # 11-0721 filed 11/8/11; rates eff. June 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):
$168 revenue requirement reduction; 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
2012 Formula Rate Filing (Docket # 12-0321 filed 4/30/12)
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)
Supported $106M distribution revenue requirement increase relative to Dec. 2012
rates as ComEd initially proposed  (Revenue requirement and relative increase will
be updated to reflect 11-0721 rate order)
ICC order by year end; rates effective January 2013
Financial  Statement Impacts of Formula Rate Process
Summary of Filings
Income Statement:
Revenues are based on forecasted calendar year revenue requirement and are accrued and recorded monthly
Cash Flow:
Rate adjustments become effective two years after costs are incurred (one year for net plant additions and depreciation expense)
Rate adjustment intended to reconcile revenue requirement and actual costs incurred
Adjustment
for
2011
costs
incurred
(April
30,
2012
filing)
will
take
effect
January
2013
Adjustment for 2012 costs incurred (Spring 2013 filing) will take effect January 2014
Balance Sheet:
A regulatory asset is recorded (with interest) to reflect the difference between revenue recognized and revenue billed
(1)  590 basis point premium applies only to 2011 revenue reconciliation. All subsequent revenue reconciliations will assume a 580 basis point premium.
2012 Analyst Meeting –
Performance that Drives Progress
2010
2011
2012
J
F
M
A
M
J
J
A
S
O
N
D
J
F
M
A
M
J
J
A
S
O
N
D
J
F
M
A
M
J
J
A
S
O
N
D
Costs used for filing
Plant additions used for filing
Formula rate filing
Rates in effect
2011
2012
2013
J
F
M
A
M
J
J
A
S
O
N
D
J
F
M
A
M
J
J
A
S
O
N
D
J
F
M
A
J
J
A
S
O
N
D
Costs used for filing
Plant additions used for filing
Formula rate filing
Rates in effect


Illinois Power Agency (IPA) RFP Procurement
86
Note: Chart is for illustrative purposes only.
ATC = around-the-clock; REC = renewable energy credit; LT Ren = long-term renewable energy; RS = rate stability
Financial Swap Agreement with ExGen
(ATC baseload energy –
notional quantity 3,000 MW)
Results of Rate Stability Standard Product Procurements held February 2012:
Effective ATC of $32.57/MWh for 3 winning Standard Product suppliers for the 2013-14
plan-year.
Prices increase 2.5% annually beginning 6/1/14
Contracts are for 450MW ATC through 12/31/17
Results of REC Rate Stability Procurement held February 2012:
Procured 2.7M RECs through December 2017
Included solar, wind and other qualified renewables
Average price = $1.67/REC
Results of Spring Standard Product Procurement held April 2012:
4 winning Standard Product suppliers for modest volumes within the 2012/13 and
2014/15 plan-years
Results of Spring REC Procurement held May 2012:
Procured 1.3M RECs
Included wind and other qualified renewables
Average price = $0.88/REC
Delivery
Period
Peak
Off-Peak
June 2011 -
May 2012
5,118
4,001
June 2012 -
May 2013
1,129
358
June 2013 -
May 2014
6,494
6,062
Volume procured in 2011 IPA
Procurement (GWh)
Delivery
Period
Peak
Off-Peak
June 2012 -
May 2013
235
176
June 2013 -
May 2014
0
0
June 2014 -
May 2015
308
60
Volume procured in Spring 2012
IPA Procurement (GWh)
Term
Fixed Price ($/MWh)
1/1/12-12/31/12
$52.37
1/1/13-5/31/13
$53.48
2012 Analyst Meeting – Performance that Drives Progress


87
PECO Load Trends
Note: C&I = Commercial & Industrial
4Q12
3Q12
2Q12
1Q12
4Q11
3Q11
2Q11
1Q11
Gross Metro Product
Residential
Large C&I
All Customer Classes
Philadelphia
U.S.
Unemployment rate
(1)
8.1%
8.1%
2012 annualized growth in
gross domestic/metro product
(2)
1.6%                  2.1%
(1)
Source:
US
Dept.
of
Labor
data
(April
2012)
US
US
Dept.
of
Labor
prelim.
data
(March
2012)
Philadelphia
(2)
Source: Global Insight (February 2012)
(3)
Not adjusted for leap year
2011
1Q12        2012E
(3)
Average Customer Growth
0.3%  
0.5%    
0.6%
Average Use-Per-Customer
1.3%
(2.9)%
(2.5)%
Total Residential
1.7%   
(2.5)%       (1.9)%
Small C&I
(0.7)%
(4.9)%   
(2.7)%
Large C&I
(3.3)%  
(1.8)%       (5.6)%
All Customer Classes    
(0.9)%   
(2.7)%   
(3.3)%
Weather-Normalized Electric Load Year-over-Year
Key Economic Indicators
Weather-Normalized Electric Load
Oil
refinery
closing
estimated
direct
impact
to
reduce
Large
C&I
and
total
load
in
2012
by 4.9% and 2.0%, respectively
2012 Analyst Meeting – Performance that Drives Progress


PECO –
Default Service Plan Filing (DSP II)
(1)
FR = Full Requirements;
(2)
FPFR = Fixed-Price Full Requirements
Retention as of:  May 22, 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:
4%
100% spot-priced FR
(1)
products
2011 opt-in FPFR
(2)
product
100% of supply procured directly from the PJM spot
market
Medium
Commercial
Current load retained:
18%
85% 1-year FPFR products, 15% spot-priced FR
products
100% 6-month FPFR products
Small
Commercial
Current load retained:
44%
70% 1-year FPFR products, 20% 2-year FPFR products,
10% spot-priced FR products
100% 1-year FPFR products
Residential
Current load retained:
73%
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
A PAPUC order on the filing is expected in mid-October 2012
Offers a 6-month opt-in auction program with price at least 5% less than PECO’s expected Price to Compare (PTC) as of 6/1/13
Establishes a residential customer referral program for 1-year, fixed price at least 7% below PECO PTC
Provides
customer
information
and
referral
programs
for
various
products;
“seamless”
moves
between
properties
88
2012 Analyst Meeting – Performance that Drives Progress
Incorporates Retail Market Enhancements suggested by PAPUC Order issued 12/15/11:


BGE Load Trends
4Q12
3Q12
2Q12
1Q12
4Q11
3Q11
2Q11
1Q11
Gross Metro Product
Residential
Large C&I
All Customer Classes
Note: C&I = Commercial & Industrial
Baltimore
U.S.
Unemployment rate
(1)
7.1%
8.1%               
2012 annualized growth in
gross domestic/metro product
(2)
1.6%                    2.1%
2011 
1Q12        2012E
(3)
Average Customer Growth
0.2%  
0.0%    
0.4%
Average Use-Per-Customer