 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
(4.4)%
0.4%
0.0%
Total Residential
(4.3)%
0.4% 0.3%
Small C&I
0.8%
(8.3)%
(0.7)%
Large C&I
2.0%
(0.5)%
0.9%
All Customer Classes
(1.1)%
0.3%
0.7%
Weather-Normalized Electric Load Year-over-Year
Key Economic Indicators
Weather-Normalized Electric Load
89
2012 Analyst Meeting – Performance that Drives Progress
Note: As approved by the MDPSC, BGE records a monthly adjustment to residential
and the majority of its commercial and industrial customers to eliminate the
effect of abnormal weather and usage patterns per customer on distribution
volumes, thereby recovering a specified dollar amount of distribution revenues
per customer, by customer class, regardless of changes in consumption levels.
Therefore, while these revenues are affected by customer growth, they will not
be affected by actual weather or usage conditions.
(1)
Source:
US
Dept.
of
Labor
data
(April
2012)
–
US
US
Dept.
of
Labor
prelim.
data
(March
2012)
–
Baltimore
(2)
Source:
Global
Insight
(February
2012)
–
US
Moody’s
Analytics
(February
2012)
–
Baltimore
(3)
Not adjusted for leap year |
 90
BGE –
Standard Offer Service
•
BGE provides Standard Offer Service (SOS) as fixed seasonal rates for those
electric customers who are not shopping. The costs
of
providing
this
service
are
recovered
from
customers
via
an
Administrative
Charge
included
in
the
SOS
rate.
The
Administrative Charge and the Energy & Transmission components of the SOS
Rate are subject to periodic true-ups. BGE procures the
majority of energy for this product via Full Requirements load auctions as ordered by the MDPSC. See table
below:
(1)
FPFR = Fixed-Price Full Requirements
Retention as of: February 2012
Procurement Mix
Class
6/1/11 –
5/31/12
6/1/12 –
5/31/13
Large C&I
(Hourly)
Current load retained:
5%
•
100% of supply procured directly from the PJM spot
market
•
100% of supply procured directly from the PJM spot
market
Medium
Commercial
(Type II)
Current load retained:
28%
•
100% 3-month FPFR
(1)
products
•
Auction Apr ’11 for Jun ’11 –
Aug ’11
•
Auction Jun ’11 for Sep ’11 –
Nov ’11
•
Auction Oct ’11 for Dec ’11 –
Feb ’12
•
Auction Jan ’12 for Mar ’12 –
May ’12
•
100% 3-month FPFR products
•
Auction Apr ’12 for Jun ’12 –
Aug ’12
•
Auction Jun ’12 for Sep ’12 –
Nov ’12
•
Auction Oct ’12 for Dec ’12 –
Feb ’13
•
Auction Jan ’13 for Mar ’13 –
May ’13
Small
Commercial
(Type I)
Current load retained:
63%
•
25% 2-year FPFR products
•
Auction Apr ’09 for Oct ’09 –
Sep ’11
•
Auction Oct ’09 for Jun ’10 –
May ’12
•
Auction Apr ’10 for Oct ’10 –
Sep ’12
•
Auction Oct ’10 for Jun ’11 –
May ’13
•
Auction Apr ’11 for Oct ’11 –
Sep ’13
•
25% 2-year FPFR products
•
Auction Apr ’10 for Oct ’10 –
Sep ’12
•
Auction Oct ’10 for Jun ’11 –
May ’13
•
Auction Apr ’11 for Oct ’11 –
Sep ’13
•
Auction Oct ’11 for Jun ’12 –
May ’14
•
Auction Apr ’12 for Oct ’12 –
Sep ’14
Residential
Current load retained:
75%
•
25% 2-year FPFR products
•
Auction Apr ’09 for Oct ’09 –
Sep ’11
•
Auction Oct ’09 for Jun ’10 –
May ’12
•
Auction Apr ’10 for Oct ’10 –
Sep ’12
•
Auction Oct ’10 for Jun ’11 –
May ’13
•
Auction Apr ’11 for Oct ’11 –
Sep ’13
•
25% 2-year FPFR products
•
Auction Apr ’10 for Oct ’10 –
Sep ’12
•
Auction Oct ’10 for Jun ’11 –
May ’13
•
Auction Apr ’11 for Oct ’11 –
Sep ’13
•
Auction Oct ’11 for Jun ’12 –
May ’14
•
Auction Apr ’12 for Oct ’12 –
Sep ’14
2012 Analyst Meeting – Performance that Drives Progress
|
 91
Regulatory Schedule
Q1
Q2
Q3
Q4
Proposed order for initial
filing (5/1); Final order
(issued 5/30); rates
effective June thru Dec.
Procurements for ATC
supply and RECs for
6/1/13-12/31/17 (Feb.)
ComEd Distribution
Formula Rate
Illinois Power
Agency
Procurement
ComEd
Transmission Rate
Update
Annual update filing
with FERC (5/15);
rates effective June
2012 thru May 2013
First annual update
and reconciliation
filing (4/30)
Rates effective
Jan. thru Dec.
Regular annual
procurement event
(April)
Final order
(by 12/27)
2013
BGE Distribution Rates
PECO Supply
Procurement
BGE Transmission Rate
Update
Annual update filing
with FERC (4/24);
rates effective June
2012 thru May 2013
File case with MDPSC
(2 half of 2012)
Procure DSP I
residential block
supply (April)
BGE Supply
Procurement
Regular
procurement event
(April & June)
Regular
procurement event
(October)
Procure DSP I
residential block
supply (September)
Final DSP II order
(mid-October)
DSIC filing
(tentative)
PECO DSIC Filing
MDPSC order due
210 days after filing
2012
2012 Analyst Meeting – Performance that Drives Progress
nd |
 92
Energy Efficiency Progress
Note: EE = energy efficiency; DR = demand response
2012 Analyst Meeting – Performance that Drives Progress
ComEd –
Illinois
PECO –
Pennsylvania
BGE –
Maryland
•Annual savings requirement 0.8% of energy deliveries for year ended
5/31/12; increases annually to 2.0% beginning 6/1/15 and each year
thereafter, subject to spending cap of ~2% of revenues
•EIMA created process that would allow spending above cap for incremental
cost-effective EE approved by the IPA and ICC
•Achieved annual savings goal in each of the first three years and is
projected to achieve goal in year four
•Recovery of EE/DR program costs approved by ICC
•Electric consumption required to be reduced by 1% and 3% by
5/31/11 and 5/31/13, respectively (vs. 6/09–5/10 baseline)
•Exceeded 1% energy use reduction target and is projected to achieve
3% goal in Q4 2012
•Since program inception, more than 1 million MWh energy reduced
and less than 50% of budget target spent
•Recovery of EE/DR program costs approved by PAPUC
•EmPOWER MD statute 15% by 2015 (vs. 2007 baseline); most
ambitious targets of any state
•Making good progress to achieving demand reduction and toward
energy targets, with further potential from smart grid and recent
program filings
•Revenue decoupling mechanism implemented to mitigate impact of
declines in customer consumption
•Recovery of EE/DR program costs approved by MDPSC
|
 Generation Overview
Chip Pardee
SVP and Chief Operating Officer of
Exelon Generation |
 94
Exelon Generation Fleet
Generation fleet uniquely diversified across regions and technologies
National Scope
•
Power generation assets in 20
states and Canada
Large and Diverse
•
35 GW of diverse generation
(1)
–
19 GW of Nuclear
–
10 GW of Gas
–
2 GW of Hydro
–
2 GW of Oil
–
1 GW of Coal
–
1 GW of Wind/Solar/Other
Clean
•
One of nation’s cleanest fleets
as measured by CO2, SO2 and
NOx intensity
(1)
Total owned generation capacity as of 4/30/2012 for legacy Exelon and legacy
Constellation combined, net of physical market mitigation assumed to be 2,648 MW. Nuclear capacity reflects
EXC ownership of CENG and Salem. Coal capacity shown does not include Eddystone
2 (309 MW) retired on 6/1/2012. 2012 Analyst Meeting – Performance
that Drives Progress |
 95
Operational Excellence
Continue tradition of operational excellence and continuous improvement
Operator
5-Year Average
5-Year Range
12
14
16
18
20
22
24
2007
2008
2009
2010
2011
Industry (Excluding Exelon)
Exelon
Exelon
5
3
9
9
6
98
2008
96
95
2007
100
95
10
5
0
2011
95
2010
97
2009
Hydro Equivalent Availability (closer to 100% is better)
0
10
20
30
40
50
2002
2011
2010
2009
2008
2007
2006
2005
2004
2003
Industry (w/o Exelon)
Exelon
Nuclear 2-Yr Production Cost ($/MWh)
(3)
Fossil
and
Hydro
Fleet
Availability
(2)
Range
of
Nuclear
Fleet
2-Yr
Avg
Capacity
Factor
(2007-2011)
(1)
Industry Leading Refueling Outage Duration
(4)
(1)
Source: Platts Nuclear News, Nuclear Energy Institute and Energy Information
Administration (Department of Energy). Exelon metrics exclude CENG & Salem.
(2)
Excludes legacy Constellation asset performance.
(3)
Source: 2011 Electric Utility Cost Group (EUCG) survey. Includes Fuel Cost plus
Direct O&M divided by net generation. Exelon metrics exclude CENG & Salem.
(4)
Exelon data excludes Salem & CENG. Exelon’s 2009 average includes 23
days of TMI outage that extended into 2010 for a steam generator replacement.
2012 Analyst Meeting – Performance that Drives Progress
Fossil Fleet Equivalent Forced Outage Rate -
Demand (closer to 0% is better) |
 96
NRC Fukushima Related Orders
Working collaboratively with NRC and U.S. Nuclear Industry to invest in long
term enhancements resulting from lessons learned
Tier 1 Staff Requirements
•
Mitigating Strategies:
–
Additional
portable
equipment
purchased
to
enhance
mitigation
capability
for
beyond-design-
basis events
–
Integrated Plan to be submitted to NRC by February 2013
–
All actions will be implemented across the Exelon fleet by the end of 2016
•
Hardened Vents for Mark I and Mark II Containments:
–
Conceptual design for Mark II containments is in progress and conceptual design
for Mark I containments to begin in August 2012
–
Integrated Plan to be submitted to NRC by February 2013
–
All actions will be implemented across the Exelon fleet by the end of 2016
•
Spent Fuel Pool (SFP) Instrumentation:
–
Conceptual design for upgraded SFP instrumentation is in progress
–
Integrated Plan to be submitted to NRC by February 2013
–
All actions will be implemented across the Exelon fleet by the end of 2016
Exelon expects the costs to comply with NRC requirements to be manageable 2012 Analyst
Meeting – Performance that Drives Progress |
 97
Well Positioned for Clean Air Rules
A clean and diverse portfolio that is well positioned for environmental upside
from EPA regulations
(1)
Total owned generation capacity as of 4/30/2012 for legacy Exelon and legacy
Constellation combined, net of physical market mitigation assumed to be 2,648 MW.
(2)
Nuclear capacity shown above reflects EXC ownership of CENG and Salem.
(3)
Coal capacity shown above does not include Eddystone 2 (309 MW) retired on
6/1/2012. •
Largest clean merchant generation
portfolio in the nation
•
Less than 5% of combined generation
capacity will require capital expenditures
to comply with Air Toxic rules
•
Low-cost generation capacity provides
unparalleled leverage to rising commodity
prices
Total
Generation
Capacity
(1)
:
~
34,660
MW
6%
Hydro
Wind/Solar/Other
Gas
28%
Oil
4%
Coal
(3)
4%
Nuclear
(2)
55%
2012 Analyst Meeting – Performance that Drives Progress
3%
Combined Company Portfolio
Approx. $200 million of CapEx,
majority of which is at Conemaugh
(Exelon ownership share ~31%)
– |
 98
Executing on Growth Projects
Exelon adding material amount of new generation over planning horizon with
safe returns
•
Constructing 404 MWs of wind projects in 2012
•
May develop or acquire 500 MWs to 1,000 MWs over the next five years
•
Future wind development to be backed by PPA and tax benefits
•
Antelope Valley Solar Ranch One Project adding 80 MW by year end
2012 and 150 MW in 2013 –
investment recovered by 2015
•
Adding 21 MWs through non-utility scale projects in 2012
(1)
•
Value driven uprate program has added 247 MWs through the end of
2011
•
Adding 85 MWs in 2012 and 850 MWs over the next six years
(1)
Includes projects signed as of 4/30/12.
2012 Analyst Meeting – Performance that Drives Progress
|
 99
Appendix
2012 Analyst Meeting – Performance that Drives Progress
|
 100
Exelon Generation Fleet Overview
(1)
Plant
Location
Owned
Capacity
(MW)
LDA
Hub/Zone
Region for
Disclosure
Mapping
Nuclear
Braidwood
Braidwood,
IL
2,348
Rest of RTO
NiHub
Midwest
Byron
Byron, IL
2,323
Rest of RTO
NiHub
Midwest
Calvert Cliffs I and II
Calvert Co, MD
853
SWMAAC
BGE
Mid-Atlantic
Clinton
Clinton, IL
1,067
n/a
Indiana Hub
Midwest
Dresden
Morris, IL
1,753
Rest of RTO
NiHub
Midwest
LaSalle
Seneca, IL
2,316
Rest of RTO
NiHub
Midwest
Limerick
Limerick
Twp.,PA
2,312
EMAAC
PECO Zone
Mid-Atlantic
Nine Mile Point I and II
Scriba, NY
782
NYPP
Zone C
New York
Oyster Creek
Forked River, NJ
625
EMAAC
PECO Zone
Mid-Atlantic
Peach Bottom
Peach
Bottom
Twp.,
PA
1,150
EMAAC
PECO Zone
Mid-Atlantic
Quad Cities
Cordova, IL
1,380
Rest of RTO
NiHub
Midwest
R.E. Ginna
Ontario, NY
291
NYPP
Zone B
New York
Salem
Hancock's Bridge, NJ
1,004
EMAAC
PECO Zone
Mid-Atlantic
Three Mile Island
Londonderry Twp, PA
837
MAAC
Whub/MetEd Zone
Mid-Atlantic
Coal
(2)
ACE
Trona, CA
32
n/a
Other
Conemaugh
New Florence, PA
533
MAAC
Whub/Penelec Zone
Mid-Atlantic
Jasmin
Kern Co, CA
18
n/a
Other
Keystone
Shelocta, PA
716
MAAC
Whub/Penelec Zone
Mid-Atlantic
POSO
Kern Co, CA
18
n/a
Other
Gas
Colorado Bend
Wharton, TX
550
Houston
ERCOT
Eddystone 3, 4
Eddystone, PA
760
EMAAC
PECO Zone
Mid-Atlantic
Fore River
North Weymouth, MA
688
ROP-NE
Hub
New England
Gould Street
Baltimore City, MD
97
SWMAAC
BGE
Mid-Atlantic
Grande Prairie
Alberta, Canada
93
n/a
Other
Handley 3, 4, 5
Fort Worth, TX
1,265
ERCOT N
ERCOT
Handsome Lake
Rockland Twp, PA
268
MAAC
Whub/Penelec Zone
Mid-Atlantic
Hillabee Energy
Alexander City, Alabama
740
GTC
Other
LaPorte
Laporte, TX
152
ERCOT
ERCOT
Medway
West Medway, MA
105
ISO-NE
Mass Hub
New England
Mountain Creek 6, 7, 8
Dallas, TX
805
ERCOT N
ERCOT
Mystic 7
Charlestown, MA
560
ROP-NE
Hub
New England
Mystic 8,9
Charlestown, MA
1,398
NEMA
Hub
New England
Notch Cliff
Baltimore Co, MD
101
SWMAAC
BGE
Mid-Atlantic
Perryman -Gas
Harford Co, MD
147
SWMAAC
BGE
Mid-Atlantic
Quail Run Energy
Odessa, TX
550
West
ERCOT
Riverside -Gas
Baltimore Co, MD
189
SWMAAC
BGE
Mid-Atlantic
Southeast Chicago
Chicago, IL
296
Rest of RTO
NiHub
Midwest
West Valley
Salt Lake City, UT
200
n/a
Other
Westport
Baltimore Co, MD
116
SWMAAC
BGE
Mid-Atlantic
Wolf Hollow 1, 2, 3
Granbury, TX
705
ERCOT N
ERCOT
Plant
Location
Owned
Capacity
(MW)
LDA
Hub/Zone
Region for
Disclosure
Mapping
Oil
Chester
Chester, PA
39
EMAAC
PECO Zone
Mid-Atlantic
Conemaugh
New Florence, PA
2
MAAC
Whub/Penelec Zone
Mid-Atlantic
Croydon
Bristol Twp., PA
391
EMAAC
PECO Zone
Mid-Atlantic
Delaware
Philadelphia, PA
56
EMAAC
PECO Zone
Mid-Atlantic
Eddystone
Eddystone, PA
60
EMAAC
PECO Zone
Mid-Atlantic
Falls
Falls Twp., PA
51
EMAAC
PECO Zone
Mid-Atlantic
Framingham
Framingham, MA
28
ISO-NE
Mass Hub
New England
Keystone
Shelocta, PA
2
MAAC
Whub/Penelec Zone
Mid-Atlantic
Moser
LowerPottsgrove
Twp.,
PA
51
EMAAC
PECO Zone
Mid-Atlantic
Mystic Jet
Charlestown, MA
9
ROP-NE
Hub
New England
New Boston
South Boston, MA
12
ISO-NE
Mass Hub
New England
Perryman -
Oil
Harford Co, MD
200
SWMAAC
BGE
Mid-Atlantic
Philadelphia Road
Baltimore Co, MD
61
SWMAAC
BGE
Mid-Atlantic
Richmond
Philadelphia, PA
98
EMAAC
PECO Zone
Mid-Atlantic
Riverside -
Oil
Baltimore Co, MD
39
SWMAAC
BGE
Mid-Atlantic
Salem
Hancock's Bridge, NJ
16
EMAAC
PECO Zone
Mid-Atlantic
Schuylkill
Philadelphia, PA
199
EMAAC
PECO Zone
Mid-Atlantic
Southwark
Philadelphia, PA
52
EMAAC
PECO Zone
Mid-Atlantic
Wyman
Yarmouth, ME
36
ISO-NE
Maine Zone
New England
Hydro
Conowingo
Harford Co., MD
572
EMAAC
PECO Zone
Mid-Atlantic
Malacha
Muck Valley, CA
16
n/a
Other
Muddy Run
Lancaster, PA
1,070
EMAAC
PECO Zone
Mid-Atlantic
Safe Harbor
Safe Harbor, PA
278
MAAC
Whub
Mid-Atlantic
Wind
AgriWind
Bureau
Co.,
IL
8
IL Hub/Indiana Hub
Midwest
Blue Breezes
Faribault Co., MN
3
MinnHub
Midwest
Bluegrass Ridge
Gentry Co., MO
56
SERC
Other
Brewster
Jackson Co., MN
6
MinnHub
Midwest
Cassia
Twin Falls Co., ID
29
WECC/Mid-C
Other
Cisco
Jackson Co., MN
8
MinnHub
Midwest
Conception
Nodaway
Co.,MO
50
SERC
Other
Cow Branch
Atchinson
Co.,MO
50
SERC
Other
Cowell
Pipestone Co., MN
2
MinnHub
Midwest
CP Windfarm
Faribault Co., MN
4
MinnHub
Midwest
Criterion
Oakland, MD
70
Whub
Mid-Atlantic
Echo 1
Umatilla Co., OR
34
WECC/Mid-C
Other
Echo 2,3
Morrow Co., OR
30
WECC/Mid-C
Other
Ewington
Jackson Co., MN
20
MinnHub
Midwest
Exelon Wind 1-11
Various Counties, TX
180
SPP
Other
Greensburg
Kiowa Co., KS
13
SPP
Other
Harvest
Huron Co., MI
53
MichHub
Midwest
(1)
Total owned generation capacity as of 4/30/2012 for legacy Exelon and legacy
Constellation combined, net of physical market mitigation assumed to be 2,648 MW.
(2)
Coal capacity shown does not include Eddystone 2 (309 MW) retired on
6/1/2012. 2012 Analyst Meeting – Performance that Drives Progress
|
 101
Exelon Generation Fleet Overview (cont’d)
(1)
Plant
Location
Owned
Capacity
(MW)
LDA
Hub/Zone
Region for
Disclosure
Mapping
Wind (cont’d)
High Plains
Moore Co., TX
10
SPP
Other
Loess Hills
Atchinson Co., MO
5
SERC
Other
Marshall
Lyon Co., MN
19
MinnHub
Midwest
Michigan Wind 1 and 2
Bingham Twp., MI
159
MichHub
Midwest
Mountain Home
Elmore Co., ID
40
WECC/Mid-C
Other
Norgaard
Lincoln Co., MN
9
MinnHub
Midwest
Threemile Canyon
Morrow Co., OR
10
WECC/Mid-C
Other
Tuana Springs
Twin
Falls
Co.,
ID
17
WECC
Other
Wolf
Nobles Co., MN
6
n/a
Midwest
Solar
City Solar
Chicago, IL
10
Rest of RTO
NiHub
Midwest
Constellation Solar
Various
84
n/a
Other
SEGS IV-VI
Kramer Junction, CA
8
n/a
Other
Biomass
Chinese Station
Jamestown, CA
10
n/a
Other
Fresno
Fresno, CA
12
n/a
Other
Rocklin
Placer Co, CA
12
n/a
Other
Landfill Gas
Fairless Hills
Falls Twp, PA
60
EMAAC
PECO Zone
Mid-Atlantic
Pennsbury
Falls Twp., PA
6
EMAAC
PECO Zone
Mid-Atlantic
Waste Coal
Colver
Colver Township, PA
26
n/a
Mid-Atlantic
Panther Creek
Nesquehoning, PA
40
n/a
Mid-Atlantic
Sunnyside
Sunnyside, UT
26
n/a
Other
Total, Net of Physical Mitigation
(1)
34,662
Physical Market Mitigation
Brandon Shores
Anne Arundel Co, MD
1,273
SWMAAC
BGE
Mid-Atlantic
H. A. Wagner
Anne Arundel Co, MD
976
SWMAAC
BGE
Mid-Atlantic
C. P. Crane
Anne Arundel Co, MD
399
SWMAAC
BGE
Mid-Atlantic
(1)
Total owned generation capacity as of 4/30/2012 for legacy Exelon and legacy
Constellation combined, net of physical market mitigation assumed to be 2,648 MW.
2012 Analyst Meeting – Performance that Drives Progress
|
 102
Post Fukushima: NRC Requirements and Anticipated Implications
Requirement
EXC Actions Required
Proactive Steps Taken
Mitigating strategies for beyond-
design-basis events
•
Develop procedures and plant
modifications to implement additional
requirements for mitigation of beyond
design basis events
•
Validated existing strategies
•
Performed preliminary analysis to identify
strategy improvements
•
Purchased additional portable equipment
Reliable hardened vents for Mark
I and Mark II containment
•
Install new hardened vents for Mark II
containments, upgrade existing Mark I
hardened containment vents
•
Validated existing venting procedures
•
Began conceptual design for installation of
Mark II containment vents
Spent Fuel Pool (SFP)
instruments
•
Upgrade existing SFP monitoring
capability to meet new requirements
•
Additional controls established for SFP
cooling equipment monitoring and
equipment availability
Tier 1 Staff Requirements
•
Significant activity is in progress in preparation for seismic and external
flooding walkdowns which are required under additional NRC requests for
information and are scheduled to be completed by the end of November
2012 •
In March, NRC issued its final Tier 1 requirements based on NRC task force and
staff recommendations
Exelon’s actions and commitments are aligned with coordination that is
taking place across the U.S. nuclear industry
2012 Analyst Meeting – Performance that Drives Progress
|
 103
Growing Clean Generation with Uprates
Station
Base Case
MW
Max Potential
MW
MW Online to
Date
Year of Full
Operation
by Unit
MW Recovery & Component Upgrades:
Quad Cities
99
99
99
2011 / 2010
Dresden
3
3
2013 / 2012
Peach Bottom
29
30
15
2011 / 2012
Dresden
106
110
62
2011 / 2013
Limerick
6
6
3
2012 / 2013
Peach Bottom
2
2
2014 / 2015
MUR:
LaSalle
39
39
39
2010 / 2011
Limerick
30
30
30
2011 / 2011
Braidwood
34
42
2012 / 2012
Byron
34
42
2012 / 2012
Quad Cities
21
23
2014 / 2014
Dresden
28
31
2014 / 2015
TMI
12
15
2014
EPU:
Clinton
2
2
2
2010
Peach Bottom
130
137
2015 / 2016
LaSalle
303
336
2018 / 2017
Limerick
306
340
2016 / 2017
Total
1,184
1,287
250
(1)
Includes deferral of LaSalle EPU.
(2)
In 2012 dollars. Overnight costs do not include financing costs or cost
escalation. (3)
Adjusted for actual MW’s achieved.
Estimated
IRR
Overnight
Cost
(2)
Approval
Process
Project
Duration
Megawatt
Recovery &
Component
Upgrades
11-14%
$860 M
Not
required
3-4 Years
MUR
(Measurement
Uncertainty
Recapture)
12-16%
$340 M
Straight
forward
approval
process
2-3 Years
EPU (Extended
Power Uprate)
9-13%
$2,260 M
Straight
forward
approval
process
3-6 Years
Executing uprate projects across our
geographically diverse nuclear fleet –
planned to add 85 MW’s in 2012
Nuclear Uprate Program Summary
(1)
2012 Analyst Meeting – Performance that Drives Progress
(3)
(3)
(1) |
 Phased Execution Lowers Risk
(1)
Dollars shown are nominal in millions (excludes capitalized interest).
(2)
Values shown are rounded and at ownership. Data includes deferral of
LaSalle EPU. •
Highest return projects are being completed in the early years
•
Leverages Exelon’s substantial experience managing successful uprate
projects – 1,100 MW completed prior to 2008
Approximately 134 MWs scheduled to be completed in 2012 and 2013
Total expenditures expected to be $3,825 million from 2008 –
2019
(1)
104
0
50
100
150
200
250
300
350
400
450
500
550
600
650
700
0
200
400
600
800
1,000
1,200
1,400
1,600
2019E
50
2018E
150
2017E
450
2016E
550
2015E
600
2014E
475
2013E
375
2012E
400
2011A
350
2010A
225
2009A
150
2008A
50
MW Online (Cumulative)
Megawatt Recovery
MUR
EPU
2012 Analyst Meeting – Performance that Drives Progress
Exelon’s Uprate Plan Expenditures
(2) |
 Exelon’s Uprate Program Is a Pragmatic Approach to
Nuclear Growth
Key Considerations
Exelon
Uprate
Program
(2)
New
Merchant
Nuclear
(3)
Overnight cost
(1)
$2,700 -
$2,900 / KW
$4,500 -
$6,200 / KW
Time to market
2 -
6 years
At least 9 years
O&M cost
No additional O&M cost
$11 -
$15 / MWh
Ancillary costs –
NDT, maintenance
capital, etc
Minimal ancillary costs
$ 2 -
$3 / MWh
Asset diversification
Operational risk spread amongst several
assets
Operational risk concentrated to single
asset
Market diversification
Diversify revenue source amongst
several power markets / regions
Market risk concentrated to one
location
Market timing risk
Lower risk due to phased execution
Risk of hitting low commodity cycle
Regulatory approval
1 -
2 years review period
3 -
year minimum review period
Financing Source
Leverage balance sheet strength
Loan guarantees needed
Development flexibility
Ability to respond to changing market /
financial conditions
Much less flexibility to cancel
(1)
In 2012 dollars. Overnight costs do not include financing costs or cost
escalation. (2)
Includes deferral of LaSalle EPU.
(3)
Cost estimates are based on Exelon’s internal projections for new merchant
nuclear. Exelon’s uprate program is a proven approach to add clean
generation to the
portfolio, and it provides flexibility to respond to changing economic and
market conditions
105
2012 Analyst Meeting – Performance that Drives Progress
|
 Peach Bottom Uprate Program
•
MW Recovery
•
EPU
106
Unit 2
Unit 3
Uprate Project
MW
Increase
(1)
Online
Date
MW
Increase
(1)
Online
Date
Status
MW Recovery -
Low Pressure
Turbine Retrofit
14
4Q 2012
15
4Q 2011
Unit 3 complete
Unit 2 in progress
MW Recovery -
Adjustable Speed
Drives
2
4Q 2014
2
4Q 2015
Scheduled to start in 2012
EPU
65
1Q 2015
65
1Q 2016
Design phase in progress
(1) Capital investment and MW uprate numbers represent Exelon’s 50%
ownership stake in Peach Bottom Station. $’s used in chart are nominal (excludes capitalized interest).
Peach Bottom Uprate Projects are underway –
15 additional MWs came online in
2011 and the remaining will come online between 2012 and 2016
2012 Analyst Meeting – Performance that Drives Progress
–
Low Pressure Turbine Retrofit in progress with
installation complete for Unit 3 and
completion for Unit 2 planned in 2012
–
Replacement of Reactor Recirculation Pump
Motor Generator sets with energy efficient
Adjustable Speed Drives in 2014 and 2015
–
Funding approved for design work
–
Full project authorization currently in progress
|
 107
LaSalle Uprate Program
•
MUR
•
EPU
Unit 1
Unit 2
Uprate Project
MW
Increase
Online
Date
MW
Increase
Online
Date
Status
MUR
19
2010
20
2011
Complete
EPU
151
3Q 2018
151
3Q 2017
Design phase in progress,
Project completion moved from
2015 / 2016 to 2017 / 2018
(1) $’s used in chart are nominal (excludes capitalized
interest). LaSalle Uprate Projects are underway –
39 additional MWs came online through
2011 and the remaining will come online between 2017 and 2018
2012 Analyst Meeting – Performance that Drives Progress
–
Funding approved for design work
–
Project completion has been moved from
2015/2016 to 2017/2018
–
Completed in 2010 and 2011 |
 108
Limerick Uprate Program
•
MW Recovery
•
MUR
•
EPU
Unit 1
Unit 2
Uprate Project
MW
Increase
Online
Date
MW
Increase
Online
Date
Status
MUR
15
2010
15
2011
Complete
MW Recovery -
Adjustable Speed
Drives
3
1Q 2012
3
2Q 2013
Unit 1 complete
Unit 2 in progress
EPU
153
3Q 2016
153
3Q 2017
Initial studies in progress
(1) $’s used in chart are nominal (excludes capitalized interest).
Limerick Uprate Projects are underway –
33 additional MWs came online through
2012 and the remaining will come online between 2013 and 2017
–
Replacement of Reactor Recirculation Pump
Motor Generator sets with energy efficient
Adjustable Speed Drives completed for Unit 1 in
2012 and planned for Unit 2 in 2013
–
Completed in 2011
–
Funding approved for initial studies
–
Will review in 3Q 2012 before authorizing
start of design work
2012 Analyst Meeting – Performance that Drives Progress
|
 Exelon Nuclear Fleet Overview (including CENG and Salem)
Plant Location
Type/
Containment
Water Body
License Extension Status / License
Expiration
Ownership
Spent Fuel Storage/
Date to lose full core
discharge capacity
(2)
Braidwood, IL
(Units 1 and 2)
PWR
Concrete/Steel Lined
Kankakee River
Expect to file application in 2013 / 2026,
2027
100%
Dry Cask
Byron, IL
(Units 1 and 2)
PWR
Concrete/Steel Lined
Rock River
Expect to file application in 2013 / 2024,
2026
100%
Dry Cask
Clinton, IL
(Unit 1)
BWR
Concrete/Steel Lined / Mark III
Clinton Lake
2026
100%
2018
Dresden, IL
(Units 2 and 3)
BWR
Steel Vessel / Mark I
Kankakee River
Renewed / 2029, 2031
100%
Dry Cask
LaSalle, IL
(Units 1 and 2)
BWR
Concrete/Steel Lined / Mark II
Illinois River
2022, 2023
100%
Dry Cask
Quad Cities, IL
(Units 1 and 2)
BWR
Steel Vessel / Mark I
Mississippi River
Renewed / 2032
75% Exelon, 25% Mid-
American Holdings
Dry Cask
Calvert Cliffs, MD
(Units 1and 2)
PWR
Concrete/Steel Lined
Chesapeake Bay
Renewed / 2034, 2036
100% CENG
(4)
Dry Cask
R.E. Ginna, NY
(Unit 1)
PWR
Concrete/Steel Lined
Lake Ontario
Renewed / 2029
100% CENG
(4)
Dry Cask
Limerick, PA
(Units 1 and 2)
BWR
Concrete/Steel Lined / Mark II
Schuylkill River
Filed application in June 2011 (decision
expected in 2013) / 2024, 2029
100%
Dry Cask
Nine Mile Point, NY
(Units 1 and 2)
BWR
Concrete/Steel Vessel / Mark I /
Concrete/Steel Vessel/ Mark II
Lake Ontario
Renewed / 2029, 2046
100% CENG
(4)
/
82% CENG
(4)
, 18% Long
Island Power Authority
Dry Cask
(Summer 2012)
Oyster Creek, NJ
(Unit 1)
BWR
Steel Vessel / Mark I
Barnegat Bay
Renewed / 2029
(3)
100%
Dry Cask
Peach Bottom, PA
(Units 2 and 3)
BWR
Steel Vessel / Mark I
Susquehanna
River
Renewed / 2033, 2034
50% Exelon, 50% PSEG
Dry Cask
TMI, PA
(Unit 1)
PWR
Concrete/Steel Lined
Susquehanna
River
Renewed / 2034
100%
2023
Salem, NJ
(Units 1 and 2)
PWR
Concrete/Steel Lined
Delaware River
Renewed / 2036, 2040
42.6% Exelon, 57.4%
PSEG
Dry Cask
(1)
Operating license renewal process takes approximately 4-5 years from
commencement until completion of NRC review. (2)
The date for loss of full core reserve identifies when the on-site storage
pool will no longer have sufficient space to receive a full complement of fuel from the reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge
capacity in their on-site storage pools.
(3)
On December 8, 2010, Exelon announced that it will permanently cease generation
operations at Oyster Creek by December 31, 2019. Oyster Creek’s
current NRC license expires in 2029. (4)
Exelon Generation has a 50.01% ownership interest in CENG (Constellation Energy
Nuclear Group, LLC). Electricite de France SA (EDF) has a 49.99% ownership interest in CENG.
109
2012 Analyst Meeting – Performance that Drives Progress
(1) |
 Effectively Managing Nuclear Fuel Costs
(1)
Projected Exelon (100%) Uranium Demand
Components of Fuel Expense in 2012
2012 –
2015: 100% hedged in volume
2016:
~80% hedged in volume
2017:
~55% hedged in volume
11
10
9
8
7
6
5
4
3
2
1
0
2017E
2016E
2015E
2014E
2013E
2012
Enrichment
31%
Tax/Interest
2%
Conversion
3%
Uranium
36%
Nuclear Waste
14%
Fabrication
14%
0
20
40
60
80
100
2017E
2016E
2015E
2014E
2013E
2012
Exelon Average Reload Price
Projected Market Price
(1)
All charts exclude Salem and CENG.
(2)
At ownership, excluding Salem and CENG. Excludes costs reimbursed under the
settlement agreement with the DOE. Data assumes LaSalle’s deferral of EPU.
110
0
200
400
600
800
1,000
1,200
1,400
2017E
1,205
2016E
1,174
2015E
1,110
2014E
1,068
2013E
992
2012
927
Nuclear Fuel Capex
Nuclear Fuel Expense (Amortization + Spent Fuel)
Projected Exelon Average Uranium Cost vs. Market
2012 Analyst Meeting – Performance that Drives Progress
Projected Exelon (100%) Uranium Demand
Components of Fuel Expense in 2012
Projected Total Nuclear Fuel Spend
(2) |
 Q&A |
 112
Exelon Value Proposition
(1) Dividends are subject to declaration by the Exelon board of directors on a
quarterly basis. 2012 Analyst Meeting – Performance that Drives
Progress •
Right strategy, right platform, right set of assets and right
leadership team
•
Merger will be successful
•
Right time to own Exelon stock given robust dividend yield and
unparalleled upside to market recovery
•
Confident in ability to achieve 2012 earnings in range of
$2.55 -
$2.85 per share
•
Commitment to existing dividend
(1)
rate of $2.10 per share |
 113
Exelon Investor Relations Contacts
2012 Analyst Meeting –
Performance that Drives Progress
Exelon Investor Relations
10 South Dearborn Street
Chicago, Illinois 60603
312-394-2345
312-394-4082 (Fax)
For copies of other presentations,
annual/quarterly reports, or to be added to
our email distribution list please contact:
Martha Chavez, Executive Admin Coordinator
312-394-4069
Martha.Chavez@ExelonCorp.com
Investor Relations Contacts:
JaCee Burnes, Vice President
312-394-2948
jacee.burnes@exeloncorp.com
Melissa Sherrod, Director
312-394-8351
melissa.sherrod@exeloncorp.com
Ishaan Kapoor, Manager
312-394-3657
ishaan.kapoor@exeloncorp.com
Sandeep Menon, Principal Analyst
312-394-7279
sandeep.menon@exeloncorp.com
2012 Analyst Meeting – Performance that Drives Progress
|