 Deutsche Bank Alternative Energy, Utilities and
Power Conference
William A. Von Hoene, Jr., EVP Finance & Legal
May 12, 2011
Exhibit 99.1 |
 Cautionary
Statements Regarding Forward-Looking Information
2
Except for the historical information contained herein, certain of the matters discussed in this
communication constitute “forward-looking statements” within the meaning of the
Securities Act of 1933 and the Securities Exchange Act of 1934, both as amended by the Private
Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “anticipate,”
“estimate,” “expect,” “project,” “intend,” “plan,”
“believe,” “target,” “forecast,” and words and terms of similar substance
used in connection with any discussion of future plans, actions, or events identify
forward-looking statements. These forward-looking statements include, but are not
limited to, statements regarding benefits of the proposed merger, integration plans and
expected synergies, the expected timing of completion of the transaction, anticipated future financial
and operating performance and results, including estimates for growth. These statements are based on
the current expectations of management of Exelon Corporation (Exelon) and Constellation Energy
Group, Inc. (Constellation), as applicable. There are a number of risks and uncertainties that
could cause actual results to differ materially from the forward-looking statements
included in this communication. For example, (1) the companies may be unable to obtain
shareholder approvals required for the merger; (2) the companies may be unable to obtain regulatory
approvals required for the merger, or required regulatory approvals may delay the merger or
result in the imposition of conditions that could have a material adverse effect on the
combined company or cause the companies to abandon the merger; (3) conditions to the closing of
the merger may not be satisfied; (4) an unsolicited offer of another company to acquire assets or capital
stock of Exelon or Constellation could interfere with the merger; (5) problems may arise in
successfully integrating the businesses of the companies, which may result in the combined
company not operating as effectively and efficiently as expected; (6) the combined company may
be unable to achieve cost-cutting synergies or it may take longer than expected to achieve
those synergies; (7) the merger may involve unexpected costs, unexpected liabilities or unexpected delays, or
the effects of purchase accounting may be different from the companies’ expectations; (8) the
credit ratings of the combined company or its subsidiaries may be different from what the
companies expect; (9) the businesses of the companies may suffer as a result of uncertainty
surrounding the merger; |
 Cautionary
Statements Regarding Forward-Looking Information
(Continued) 3
(10) the companies may not realize the values expected to be obtained for properties expected or
required to be divested; (11) the industry may be subject to future regulatory or legislative
actions that could adversely affect the companies; and (12) the companies may be adversely
affected by other economic, business, and/or competitive factors. Other unknown or unpredictable
factors could also have material adverse effects on future results, performance or achievements of the
combined company. Discussions of some of these other important factors and assumptions are contained
in Exelon’s and Constellation’s respective filings with the Securities and Exchange
Commission (SEC), and available at the SEC’s website at www.sec.gov, including: (1)
Exelon’s 2010 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) Exelon’s Quarterly
Report on Form 10-Q for the quarterly period ended March 31, 2011 in (a) Part II, Other
Information, ITEM 1A. Risk Factors, (b) Part I, Financial Information, ITEM 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c)
Part I, Financial Information, ITEM 1. Financial Statements: Note 12; (3) Constellation’s
2010 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; and (4) Constellation’s Quarterly Report on
Form 10-Q for the quarterly period ended March 31, 2011 in (a) Part II, Other Information, ITEM
5.Other Information, (b) Part I, Financial Information, ITEM 2. Management’s Discussion
and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial
Information, ITEM 1. Financial Statements: Notes to Consolidated Financial Statements,
Commitments and Contingencies. These risks, as well as other risks associated with the proposed merger,
will be more fully discussed in the joint proxy statement/prospectus that will be included in the
Registration Statement on Form S-4 that Exelon will file with the SEC in connection with
the proposed merger. In light of these risks, uncertainties, assumptions and factors, the
forward-looking events discussed in this communication may not occur. Readers are cautioned
not to place undue reliance on these forward-looking statements, which speak only as of the date of this
communication. Neither Exelon nor Constellation undertake any obligation to publicly release any
revision to its forward- looking statements to reflect events or circumstances after the
date of this communication. |
 Additional
Information and Where to Find It 4
This communication does not constitute an offer to sell or the solicitation of an offer to buy any
securities, or a solicitation of any vote or approval, nor shall there be any sale of
securities in any jurisdiction in which such offer, solicitation or sale would be unlawful
prior to registration or qualification under the securities laws of any such jurisdiction. Exelon intends to
file with the SEC a registration statement on Form S-4 that will include a joint proxy
statement/prospectus and other relevant documents to be mailed by Exelon and Constellation to
their respective security holders in connection with the proposed merger of Exelon and
Constellation. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE JOINT PROXY
STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE THEY
WILL CONTAIN IMPORTANT INFORMATION about Exelon, Constellation and the proposed merger.
Investors and security holders will be able to obtain these materials (when they are available) and
other documents filed with the SEC free of charge at the SEC's website, www.sec.gov. In
addition, a copy of the joint proxy statement/prospectus (when it becomes available) may be
obtained free of charge from Exelon Corporation, Investor Relations, 10 South Dearborn Street,
P.O. Box 805398, Chicago, Illinois 60680-5398, or from Constellation Energy Group, Inc.,
Investor Relations, 100 Constellation Way, Suite 600C, Baltimore, MD 21202. Investors and security
holders may also read and copy any reports, statements and other information filed by Exelon, or
Constellation, with the SEC, at the SEC public reference room at 100 F Street, N.E.,
Washington, D.C. 20549. Please call the SEC at 1-800- SEC-0330 or visit the
SEC’s website for further information on its public reference room.
Participants in the Merger Solicitation Exelon, Constellation, and their respective directors, executive officers and certain other members of
management and employees may be deemed to be participants in the solicitation of proxies in
respect of the proposed transaction. Information regarding Exelon’s directors and
executive officers is available in its proxy statement filed with the SEC by Exelon on March
24, 2011 in connection with its 2011 annual meeting of shareholders, and information regarding
Constellation’s directors and executive officers is available in its proxy statement filed with
the SEC by Constellation on April 15, 2011 in connection with its 2011 annual meeting of
shareholders. Other information regarding the participants in the proxy solicitation and a
description of their direct and indirect interests, by security holdings or otherwise, will be
contained in the joint proxy statement/prospectus and other relevant materials to be filed with the
SEC when they become available.
|
 Transaction
Overview 100%
stock
–
0.930 shares of EXC for each share of CEG
Upfront transaction
premium
of
18.1%
(1)
$2.10 per share Exelon dividend maintained
Expect to close in early 1Q 2012
Exelon and Constellation shareholder approvals in 3Q 2011
Regulatory approvals including FERC, DOJ, MD, NY, TX
Executive Chairman: Mayo Shattuck
President and CEO: Chris Crane
Board of Directors: 16 total (12 from Exelon, 4 from Constellation)
Exelon Corporation
78% Exelon shareholders
22% Constellation shareholders
Corporate headquarters: Chicago, IL
Constellation headquarters: Baltimore, MD
No change to utilities’
headquarters
Significant employee presence maintained in IL, PA and MD
Company Name
Consideration
Pro Forma
Ownership
Headquarters
Governance
Approvals &
Timing
(1) Based on the 30-day average Exelon and Constellation closing stock
prices as of April 27, 2011. 5 |
 Creating Value
Through a Strategic Merger Delivers financial benefits to both sets of
shareholders Increases scale and scope of the business across the value
chain Matches the industry’s premier clean merchant generating fleet
with the leading retail and wholesale customer platform
Diversifies the generation portfolio
Continued upside to power market recovery
Maintains a strong regulated earnings profile with large urban utilities
6
Combining Exelon’s generation fleet and Constellation’s customer-facing
businesses creates a strong platform for growth and delivers benefits to
investors and customers |
 Exelon
Transaction Rationale Increases
geographic
diversity
of
generation,
load
and
customers
in
competitive
markets
Shared
Commitment to
Competitive
Markets
Enhances
Scalable Growth
Platform
Creates
Shareholder
Value
Expands a valuable channel to market our generation
Enhances margins in the competitive portfolio
Diversifies portfolio across the value chain
EPS break-even in 2012 and accretive by +5% in 2013
Maintains strong
credit profile and financial discipline
Maintains earnings upside to future environmental regulations and power market
recovery
Adds stability to earnings and cash flow
Adds mix of clean generation to the portfolio
Clean
Generation Fleet
This transaction meets all of our M&A criteria and can be executed
7 |
 This
Combination Is Good for Maryland Maintains employee presence and platform for
growth in Maryland –
Exelon’s Power Team will be combined with Constellation’s wholesale and
retail business
under
the
Constellation
brand
and
will
be
headquartered
in Baltimore
–
Constellation and Exelon’s renewable energy business headquartered in
Baltimore –
BGE maintains independent operations headquartered in Baltimore
–
No involuntary merger-related job reductions at BGE for two years after
close Supports Maryland’s economic development and clean energy
infrastructure –
$10 million to spur development of electric vehicle infrastructure
–
$4 million to support EmPower Maryland Energy Efficiency Act
–
25 MWs of renewable energy development in Maryland
–
Charitable contributions maintained for at least 10 years
Provides direct benefits to BGE customers
–
$5 million
provided
for
Maryland’s
Electric
Universal
Service
Program
(EUSP)
–
Over $110 million to BGE residential customers from $100 one-time rate
credit 8
We
will
bring
direct
benefits
to
the
State
of
Maryland,
the
City
of
Baltimore
and
BGE
customers. Total investment in excess of $250 million.
|
 5.8
0.5
9.1
Exelon
Constellation
23.2
27.8
MISO (TWh)
South
(1)
(TWh)
ISO-NE & NY ISO
(2)
(TWh)
West (TWh)
Load
Generation
Exelon
Constellation
4.8
27.1
9.1
Exelon
Constellation
Exelon
Constellation
2.4
0.4
0.4
Exelon
Constellation
Load
Generation
Generation
Load
Load
Generation
Load
Generation
6.3
9.1
101.5
179.1
27.8
23.2
27.1
13.9
2.4
0.8
Portfolio Matches Generation with Load in
Key Competitive Markets
(1)
Represents load and generation in ERCOT, SERC and SPP.
(2)
Constellation load includes ~0.7TWh of load served in Ontario
Note: Data for Exelon and Constellation represents expected generation and load for
2011 as of 12/31/10. Exelon load includes ComEd Swap, load sold through
affiliates, fixed and indexed load sales and load sold through POLR auctions.
Constellation load includes load sold through affiliates, fixed and indexed load
sales and load sold through POLR auctions. The combination establishes
an industry-leading platform with regional diversification of the
generation fleet 9
147.3
31.8
42.8
58.7
PJM (TWh) |
 Transaction
Economics Are Attractive for Both Companies
EPS break-even in 2012 and accretive by +5% in 2013
Free cash flow accretive beginning in 2012
Run-rate synergies of ~$260 million
–
Total costs to achieve of ~$500 million
–
Synergies primarily from corporate consolidation and power marketing platform
integration
Lower consolidated liquidity requirements, resulting in cost savings
Investment-grade ratings and credit metrics
10 |
 Wolf
Hollow Acquisition 11
Wolf Hollow Overview
Diversifies generation portfolio
•
Expands geographic and fuel characteristics
of fleet
•
Advances Exelon and Constellation merger
strategy of matching load with generation in
key competitive markets
Creates value for shareholders
•
Purchase price compares favorably to cost of
new build
•
Free cash flow accretive beginning in 2012;
earnings and credit neutral
•
Eliminates current above market purchase
power agreement (PPA) with Wolf Hollow
•
Enhances opportunity to benefit from future
market heat rate expansion in ERCOT
Transaction expected to close in Q3 2011
Location
Granbury, Texas
Commercial Operation Date
August 2003
Nominal Net Operating Capacity
720MW
Equipment Technology
2 Mitsubishi combined-cycle gas
turbines
Primary Fuel
Natural Gas
Secondary Fuel
None
ERCOT = Electric Reliability Council of Texas |
 12
Appendix |
 Coal
6%
Oil
8%
Gas
11%
Hydro
6%
Wind/Solar/Other
3%
Nuclear
67%
A Clean Generation Profile Creates Long-Term
Value in Competitive Markets
(1) Net of market mitigation assumed to be 2,648 MW.
(2)
Constellation generation includes Boston Generation acquisition (2,950 MW of natural
gas) and excludes Quail Run (~550 MW of natural gas). Constellation nuclear reflects 50.01%
interest in Constellation Energy Nuclear Group LLC.
Exelon Standalone
Total Generation: 25,619 MW
Constellation Standalone
(2)
Total Generation: 11,430 MW
Pro forma Company (Net of Mitigation)
(1)
Total Generation: 34,401 MW
Coal
24%
Nuclear
17%
Gas
52%
Wind/Solar/Other
2%
Hydro
3%
Oil
3%
Nuclear
55%
Coal
6%
Oil
7%
Gas
24%
Hydro
6%
Wind/Solar/
Other
2%
13
Combined company remains premier low-cost generator
|
 16%
34%
41%
9%
RTO
EMAAC
MAAC
SWMAAC
8%
15%
15%
63%
EMAAC
MAAC
RTO
SWMAAC
42%
7%
51%
RTO
MAAC
EMAAC
Increased Regional Diversity in PJM:
Capacity Eligible for 2014/15 RPM Auction
(1)
Pro forma Company
4,390 MW
2,535 MW
9,230 MW
11,345 MW
Exelon Standalone
Constellation Standalone
8,700 MW
10,300 MW
1,500 MW
1,035 MW
4,390 MW
1,045 MW
530 MW
14
2014/15
RPM
auction
results
will
be
announced
on
May
13
,
2011
th
(1)
All generation values are approximate and not inclusive of wholesale transactions; all capacity values
are in installed capacity terms (summer ratings) located in the areas and adjusted for mid-year
PPA roll-offs.
|
 15
Factors Influencing PJM RPM Capacity Auction
(Comparison of PY 14/15 and PY 13/14 Price Drivers)
Exelon
Price Impact
Cost of Environmental Upgrades
(1)
Higher Net CONE
(2)
Higher Net ACRs for Coal Units
(3)
Import Transmission Limits and Objectives
(muted impact on portfolio revenues due to regional diversification)
NJ CCGT Proposal / PJM Minimum Offer Price Rules
Peak Load
(4)
Demand Response Growth
2014/15 PJM Capacity Auction: Expected
Changes Since Planning Year 2013/14
Expect overall results to be similar to last year’s auction
N/A
(1) We expect generators to reflect cost of capital expenditures into their
cost based offers at the upcoming auction. (2) Cost of new entry
(CONE) increased by 7.6% (for RTO) and 5.3% to 6.5% (within Locational Deliverability Areas (LDAs)).
(3) Replacing 2007 net revenues with significantly lower 2010 revenues in the
Net ACR (avoidable cost rate) calculations for coal generators may increase offer caps for certain
coal generators
in
the
next
auction.
However,
some
coal
units
may
not
be
affected
due
to
high
net
revenues
compared
to
avoidable
costs.
(4) Peak load reduced by approx. 1% in RTO (excluding the impact from Duke
Ohio integration). Note:
RPM
=
Reliability
Pricing
Model;
CCGT
=
combined
cycle
gas
turbine |
 16
16
16
ComEd Load Trends
Chicago
U.S.
Unemployment rate
(1)
8.5%
8.8%
2011 annualized growth in
gross domestic/metro product
(2)
2.5%
3.2% Note: C&I = Commercial &
Industrial Weather-Normalized Load Year-over-Year
Key Economic Indicators
Weather-Normalized Load
2010
1Q11 2011E
Average Customer Growth
0.2%
0.4%
0.5%
Average Use-Per-Customer
(1.4)%
(2.2)%
0.1%
Total Residential
(1.2)%
(1.8)% 0.5%
Small C&I
(0.6)%
0.6%
(0.3)%
Large C&I
2.6%
1.4%
(0.1)%
All Customer Classes
0.2%
(0.1)%
0.0%
(1)
Source: U.S. Dept. of Labor (March 2011) and Illinois
Department of Security (March 2011)
(2) Source: Global Insight February 2011
-6.0%
-3.0%
0.0%
3.0%
6.0%
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
-6.0%
-3.0%
0.0%
3.0%
6.0%
All Customer Classes
Large C&I
Residential
Gross Metro Product |
 17
17
17
ComEd 2010 Rate Case Update
ComEd Reply Brief (2/23/11)
$343M increase requested
11.50% ROE / 47.28% equity ratio
Rate base $7,349M
2009 test year with pro forma plant additions through 6/30/11
ICC Staff Reply Brief Position (2/23/11)
$113M increase proposed
10.00% ROE / 47.11% equity ratio
Rate base $6,480M
Pro forma plant additions and depreciation reserve through 12/31/10
ALJ Proposed Order (4/1/11)
$152M increase proposed (after correcting ~$14M calculation error)
10.50% ROE / 47.28% equity ratio
Rate base $6,629M
Pro forma plant additions and depreciation reserve through 12/31/10 with very
limited exceptions (ICC Docket No. 10-0467)
Illinois Commerce Commission Final Order will be issued by May 31
|
 Illinois Power Agency (IPA)
RFP Procurement
Note: Chart is for illustrative purposes only.
REC = Renewable Energy Credit; RFP = request for proposal
June 2011
June 2012
June 2013
June 2014
Financial Swap Agreement with ExGen
(ATC baseload energy only –
notional
quantity 3,000 MW)
Term
Fixed Price
1/1/11-12/31/11
$51.26/MWh
1/1/12-12/31/12
$52.37
1/1/13-5/31/13
$53.48
18
Financial Swap
2010 RFP
2011 RFP
2011 RFP
2011 RFP
2012 RFP
2012 RFP
2012 RFP
2013 RFP
2013 RFP
2014 RFP
ICC has approved Long Term REC Procurement held in November 2010
–
1.26 Million MWh of renewable resources annually beginning in June 2012 under 20
year contract –
8 winning suppliers with an average 2012-13 plan-year price of
$55.18/MWh Spring 2011 Procurement Plan
–
IPA Procurement Plan approved by the ICC
•
Standard Product bids due 5/16; ICC decision on 5/20
•
Annual REC bids due 5/18; ICC decision on 5/24
–
Provisions included:
•
Annual energy procurements over a three-year time frame
•
Target a 35%/35%/30% laddered procurement approach
•
No additional Energy Efficiency, Demand Response purchases
•
No additional long term contracts for renewables
•
No 10% overprocurement for summer peak energy
June 2015 |
 19
PECO Load Trends
Philadelphia
U.S.
Unemployment rate
(1)
8.4%
8.8%
2010 annualized growth in
gross domestic/metro product
(2)
3.0%
3.2%
Note: C&I = Commercial & Industrial
Weather-Normalized Load Year-over-Year
Key Economic Indicators
Weather-Normalized Load
2010
1Q11 2011E
Average Customer Growth
0.3%
0.4%
0.4%
Average Use-Per-Customer
0.3%
0.2%
1.7%
Total Residential
0.5%
0.5% 2.1%
Small C&I
(1.9)%
(1.1)% 0.1%
Large C&I
0.8%
(2.7)% (1.6)%
All Customer Classes
0.1%
(1.1)% 0.1%
(1) Source: U.S Dept. of Labor data March 2011 -US
U.S Dept. of
Labor
prelim.
data
February
2011
-
Philadelphia
(2) Source: Global Insight February 2011
-6.0%
-3.0%
0.0%
3.0%
6.0%
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
-6.0%
-3.0%
0.0%
3.0%
6.0%
All Customer Classes
Large C&I
Residential
Gross Metro Product |
 20
PECO Procurement Plan
(1)
See PECO Procurement website (http://www.pecoprocurement.com) for additional
details regarding PECO’s procurement plan and RFP results. (2)
For Large C&I customers who previously opted to participate in the 2011
fixed-priced full requirements product. (3)
Large C&I tranches which were not fully subscribed in the fall 2010
procurement Customer Class
Products
Residential
75% full requirements
20% block energy
5% energy only spot
Small Commercial
(peak demand <100 kW)
90% full requirements
10% full requirements spot
Medium Commercial
(peak demand >100 kW but
<= 500 kW)
85% full requirements
15% full requirements spot
Large Commercial &
Industrial
(peak
demand
>
500 kW)
Fixed-Priced Full
requirements
(2)
Hourly Full requirements
PECO
Procurement
Plan
(1)
Residential
80 MW of baseload (24x7) block energy product (for Jan-Dec 2012)
70 MW of Jun-Aug 2011 summer on-peak block energy product
40 MW of Dec 2011-Feb 2012 winter on-peak block energy product
Large
Commercial
and
Industrial
-
Hourly
36%
of
Hourly
Full
requirements
product
(Jun
2011-May
2012)
(3)
May
2,
2011
RFP
-
Fifth
in
a
series
of
nine procurements for the PUC-
approved Default Service Plan
Spring 2011 RFP was held on May 2, 2011, with results public 15 days thereafter
|
 21
21
EPA Regulations Will Move Forward in 2011
2010
2011
2012
2013
2014
2015
2016
2017
2018
PJM RPM Auction
14/15
15/16
16/17
17/18
Hazardous Air
Pollutants
Criteria
Pollutants
Greenhouse
Gases
Coal
Combustion
By-Products
Cooling Water
Effluents
Develop Toxics Rule
Develop ICI
MACT
Pre Compliance Period
Compliance With Toxics Rule
Pre Compliance Period
Compliance With ICI MACT
Develop
Transport Rule
Compliance With Transport Rule
Interim CAIR
Develop O3
Transport
Rule (TR 2)
Estimated Compliance
Develop Criteria
NSPS revision
Compliance with Revised Criteria NSPS
Develop Revised
NAAQS
SIP provisions developed in response to revised NAAQS
(e.g., Ozone, PM2.5, SO2, NO2, NOx/SOx, CO)
Compliance with Federal GHG Reporting Rule
PSD/BACT and Title V Apply to GHG Emissions (PSD only for new and modified
sources) Develop GHG NSPS
Pre Compliance Period
Compliance With GHG NSPS
Develop Coal Combustion
By-Products Rule
Pre Compliance Period
Compliance With Federal CCB Regulations
Develop 316(b) Regulations
Pre Compliance Period
Phase In Of Compliance
Develop Effluent Regulations
Pre Compliance Period
Phase In Of
Compliance
Notes: RPM auctions take place annually in May.
For
definition
of
the
EPA
regulations
referred
to
on
this
slide,
please
see
the
EPA’s
Terms
of
Environment
(http://www.epa.gov/OCEPAterms/). |
 22
2011 Events of Interest
Q1
Q2
Q3
Q4
RPM Auction results
(5/13)
Illinois Power Agency
RFP (5/16)
ALJ Proposed Order
–
DST Rate Case
(4/1)
Procurement RFP
(bids accepted 5/2;
results by 5/17)
DST Rate Case Final
Order (by 5/31)
EPA Final Toxics
Rule (November)
Retirement of Cromby
1 & Eddystone 1 units
(5/31)
Proposed Toxics Rule
(3/16)
Procurement RFP
(bids due 9/19;
results by 10/19)
Retirement of
Cromby 2 unit
(12/31)
Proposed 316(b) EPA
Regulation (3/28)
For
definition
of
the
EPA
regulations
referred
to
on
this
slide, please see the EPA’s Terms of Environment
(http://www.epa.gov/OCEPAterms/). EPA Final Transport
Rule (June) |
 23
Exelon Generation Hedging Disclosures
(as of March 31, 2011) |
 24
24
Important Information
The following slides are intended to provide additional information regarding the hedging
program at Exelon Generation and to serve as an aid for the purposes of modeling Exelon
Generation’s gross margin (operating revenues less purchased power and fuel expense). The
information on the following slides is not intended to represent earnings guidance or a forecast
of future events. In fact, many of the factors that ultimately will determine Exelon
Generation’s actual gross margin are based upon highly variable market factors outside of
our control. The information on the following slides is as of March 31, 2011. We
update this information on a quarterly basis. Certain
information on the following slides is based upon an internal simulation model that incorporates
assumptions regarding future market conditions, including power and commodity prices, heat rates,
and demand conditions, in addition to operating performance and dispatch characteristics of our
generating fleet. Our simulation model and the assumptions therein are subject to
change. For example, actual market conditions and the dispatch profile of our generation
fleet in future periods will likely differ – and may differ significantly – from the
assumptions underlying the simulation results included in the slides. In addition, the
forward- looking information included in the following slides will likely change over time due
to continued refinement of our simulation model and changes in our views on future market
conditions. |
 25
25
Portfolio Management Objective
Align Hedging Activities with Financial Commitments
Power Team utilizes several product types
and channels to market
•
Wholesale and retail sales
•
Block products
•
Load-following products
and load auctions
•
Put/call options
Exelon’s hedging program is designed to
protect the long-term value of our
generating fleet and maintain an
investment-grade balance sheet
•
Hedge enough commodity risk to meet future cash
requirements if prices drop
•
Consider: financing policy (credit rating objectives,
capital structure, liquidity); spending (capital and
O&M); shareholder value return policy
Consider market, credit, operational risk
Approach to managing volatility
•
Increase hedging as delivery approaches
•
Have enough supply to meet peak load
•
Purchase fossil fuels as power is sold
•
Choose hedging products based on generation
portfolio –
sell what we own
•
Heat rate options
•
Fuel products
•
Capacity
•
Renewable credits
% Hedged
High End of Profit
Low End of Profit
Open Generation
with LT Contracts
Portfolio
Optimization
Portfolio
Management
Portfolio Management Over Time |
 26
26
Percentage of Expected
Generation Hedged
•
How many equivalent MW have been
hedged at forward market prices; all hedge
products used are converted to an
equivalent average MW volume
•
Takes ALL
hedges into account whether
they are power sales or financial products
Equivalent MWs Sold
Expected Generation
=
Our normal practice is to hedge commodity risk on a ratable basis
over the three years leading to the spot market
•
Carry operational length into spot market to manage forced outage and
load-following risks
•
By
using
the
appropriate
product
mix,
expected
generation
hedged
approaches the
mid-90s percentile as the delivery period approaches
•
Participation in larger procurement events, such as utility auctions, and some
flexibility in the timing of hedging may mean the hedge program is not
strictly ratable from quarter to quarter
Exelon Generation Hedging Program |
 27
27
2011
2012
2013
Estimated
Open
Gross
Margin
($
millions)
(1)(2)
$5,250
$4,900
$5,500
Open gross margin assumes all expected generation is sold
at the Reference Prices listed below
Reference Prices
(1)
Henry Hub Natural Gas ($/MMBtu)
NI-Hub ATC Energy Price ($/MWh)
PJM-W ATC Energy Price ($/MWh)
ERCOT North ATC Spark Spread ($/MWh)
(3)
$4.47
$31.32
$44.23
$4.42
$5.06
$31.32
$46.19
$1.88
$5.41
$32.83
$48.10
$2.06
Exelon Generation Open Gross Margin and
Reference Prices
(1)
Based on March 31, 2011 market conditions.
(2)
Gross margin is defined as operating revenues less fuel expense and purchased power expense, excluding
the impact of decommissioning and other incidental revenues. Open gross margin is estimated
based upon an internal model that is developed by dispatching our expected generation to current market power and fossil
fuel prices. Open gross margin assumes there is no hedging in place other than fixed assumptions
for capacity cleared in the RPM auctions and uranium costs for nuclear power plants. Open
gross margin contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA
capacity revenues and payments. The estimation of open gross margin incorporates management
discretion and modeling assumptions that are subject to change.
(3)
ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50 variable
O&M. |
 28
28
2011
2012
2013
Expected Generation
(GWh)
(1)
165,800
165,400
162,800
Midwest
99,000
97,800
96,100
Mid-Atlantic
56,300
57,200
56,400
South & West
10,500
10,400
10,300
Percentage of Expected Generation Hedged
(2)
93-96%
73-76%
38-41%
Midwest
93-96
75-78
35-38
Mid-Atlantic
94-97
72-75
42-45
South & West
76-79
59-62
40-43
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$43.00
$41.00
$41.00
Mid-Atlantic
$56.50
$50.50
$50.50
South & West
$4.50
$0.00
($3.00)
Generation Profile
(1)
Expected
generation
represents
the
amount
of
energy
estimated
to
be
generated
or
purchased
through
owned
or
contracted
for
capacity.
Expected
generation
is
based
upon
a
simulated
dispatch
model
that
makes
assumptions
regarding
future
market
conditions,
which
are
calibrated
to
market
quotes
for
power,
fuel,
load
following
products,
and
options.
Expected
generation
assumes
12
refueling
outages
in
2011
and
10
refueling
outages
in
2012
and
2013
at
Exelon-operated
nuclear
plants
and
Salem.
Expected
generation
assumes
capacity
factors of 93.0%, 93.6% and 93.1% in 2011, 2012 and 2013 at Exelon-operated
nuclear plants. These estimates of expected generation in 2012 and 2013 do not represent guidance or a
forecast of future results as Exelon has not completed its planning or optimization
processes for those years. (2)
Percent of expected generation hedged is the amount of equivalent sales divided by
the expected generation. Includes all hedging products, such as wholesale and retail sales of power,
options, and swaps. Uses expected value on options. Reflects decision to
permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.
(3)
Effective realized energy price is representative of an all-in hedged price, on
a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy
revenues
and
costs
associated
with
our
hedges
and
by
considering
the
fossil
fuel
that
has
been
purchased
to
lock
in
margin.
It
excludes
uranium
costs
and
RPM
capacity
revenue,
but
includes
the
mark-to-market
value
of
capacity
contracted
at
prices
other
than
RPM
clearing
prices
including
our
load
obligations.
It
can
be
compared
with
the
reference
prices
used
to
calculate open gross margin in order to determine the mark-to-market value
of Exelon Generation's energy hedges. |
 29
29
Gross Margin Sensitivities with Existing Hedges ($ millions)
(1)
Henry Hub Natural Gas
+ $1/MMBtu
-
$1/MMBtu
NI-Hub ATC Energy Price
+$5/MWH
-$5/MWH
PJM-W ATC Energy Price
+$5/MWH
-$5/MWH
Nuclear Capacity Factor
+1% / -1%
2011
$5
$(5)
$15
$(10)
$10
$(10)
+/-
$30
2012
$145
$(65)
$145
$(125)
$90
$(90)
+/-
$45
2013
$425
$(380)
$315
$(310)
$180
$(175)
+/-
$45
Exelon Generation Gross Margin Sensitivities
(with Existing Hedges)
(1)
Based on March 31, 2011 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. |
 30
30
95% case
5% case
$5,500
$7,100
$6,800
$6,200
Exelon Generation Gross Margin Upside / Risk
(with Existing Hedges)
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
2011
2012
2013
$6,900
$4,900
(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 2012 and 2013
do not represent earnings guidance or a forecast of future results as Exelon has not completed
its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for power, fuel,
load following products, and options as of March 31, 2011.
|
 31
31
Midwest
Mid-Atlantic
South & West
Step 1
Start with fleetwide open gross margin
$5.25 billion
Step 2
Determine
the
mark-to-market
value
of
energy hedges
99,000GWh * 94% *
($43.00/MWh-$31.32MWh)
= $1.09 billion
56,300GWh * 95% *
($56.50/MWh-$44.23MWh)
= $0.66 billion
10,500GWh * 77% *
($4.50/MWh-$4.42/MWh)
= $0.00 billion
Step 3
Estimate
hedged
gross
margin
by
adding open gross margin to mark-to-
market value of energy hedges
Open gross
margin:
MTM value of energy
hedges:
Estimated hedged gross margin:
Illustrative Example
of Modeling Exelon Generation 2011 Gross Margin
(with Existing Hedges)
$5.25 billion
$1.09billion + $0.66billion + $0.00 billion
$7.00 billion |
 32
35
40
45
50
55
60
65
70
75
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
32
32
20
25
30
35
40
45
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
50
55
60
65
70
75
80
85
90
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
Market Price Snapshot
Forward NYMEX Natural Gas
PJM-West and Ni-Hub On-Peak Forward Prices
PJM-West and Ni-Hub Wrap Forward Prices
2012
$5.21
2013 $5.49
Rolling 12
months,
as
of
May
6th 2011.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
Forward NYMEX Coal
2012
$78.21
2013
$82.04
2012 Ni-Hub $40.60
2013 Ni-Hub
$42.66
2013 PJM-West $54.37
2012 PJM-West
$52.35
2012 Ni-Hub
$25.18
2013 Ni-Hub
$27.24
2013 PJM-West
$40.97
2012 PJM-West
$39.03 |
 33
33
33
4.5
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
8.0
8.2
8.4
8.6
8.8
9.0
9.2
9.4
9.6
9.8
10.0
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
35
40
45
50
55
60
65
70
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
Market Price Snapshot
2013
9.36
2012
9.23
2012
$46.94
2013
$50.23
2012
$5.09
2013
$5.37
Houston Ship Channel Natural Gas
Forward Prices
ERCOT North On-Peak Forward Prices
ERCOT North On-Peak v. Houston Ship Channel
Implied Heat Rate
2012
$7.72
2013
$9.00
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
Rolling 12
months,
as
of
May
6th
2011.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily. |
