 September 2011
Exelon Corporation
Investor Meetings
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 of Exelon Corporation (Exelon)
and Constellation Energy Group, Inc. (Constellation), 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 and 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 regarding the proposed merger. 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; (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 Exelon, Constellation or the combined company. |
 Cautionary Statements Regarding
Forward-Looking Information (Continued)
3
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 June 30, 2011 in (a) Part II, Other Information, ITEM 1A. Risk
Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis
of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1.
Financial Statements: Note 13; (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 June 30, 2011 in (a) Part II, Other Information, ITEM 1A. Risk Factors and 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, are more fully discussed in the
preliminary joint proxy statement/prospectus included in Amendment No. 1 to the Registration
Statement on Form S-4 that Exelon filed with the SEC on August 17, 2011 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 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. On August 17, 2011, Exelon filed with
the SEC Amendment No. 1 to its Registration Statement on Form S-4 that included a
preliminary 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.
|
 Additional Information and Where to Find It
These materials are not yet final and may be amended. WE URGE INVESTORS AND
SECURITY HOLDERS TO READ THE PRELIMINARY JOINT PROXY STATEMENT/PROSPECTUS
AND THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT
DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE
THEY
CONTAIN
OR
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 preliminary joint proxy
statement/prospectus and definitive 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,
is
contained
in
the preliminary joint proxy statement/prospectus and will be contained in the
definitive joint proxy statement/prospectus. 4
|
  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
Successful integration experience from prior mergers and acquisitions
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 |
 •
$8 billion
•
$11 billion
•
11,980 (Total)
•
1,921 (Nuclear)
•
1.2 mil. (MD)
•
0.7 mil. (MD)
•
44 states & D.C.
(5)
•
~110 TWh/yr
•
29% Generation
•
44% Utility
•
27% NewEnergy
Combination Will Result in Enhanced Scale,
Scope, Flexibility and Financial Strength
(1) Market Value as of 9/2/11. Enterprise Value represents Market Value plus
Net Debt as of 6/30/11. (2) Data as of 12/31/10. Exelon data includes
720 MW for Wolf Hollow. Constellation data includes 2,950 MW for Boston Generation assets.
(3) Net of physical market mitigation assumed to be 2,648 MW.
(4) TWh/yr represents 2011 booked electric sales as of 12/31/2010. Exelon load
includes ComEd swap. Data also includes 2011 partial year estimated electric
sales from StarTex and MXEnergy (acquired by Constellation). (5)
Competitive and wholesale business also active in Alberta, British Columbia and Ontario, Canada.
(6) Exelon EBITDA estimates per equity research. Constellation EBITDA
estimates per company guidance. Market Value and
Enterprise
Value
(1)
Pro forma
Standalone
Owned
Generation
(in MW)
(2)
Regulated
Utilities
Competitive Retail
& Wholesale
(4)
Business Mix
(6)
•
$28 billion
•
$41 billion
•
26,339 (Total)
•
17,047 (Nuclear)
Electric customers
•
5.4 mil. (IL, PA)
Gas customers
•
0.5 mil. (PA)
•
4 states
•
~59
TWh/yr
2011 EBITDA
•
61% Generation
•
39% Utilities
•
$36 billion
•
$52 billion
•
44 states & D.C.
(5)
•
~169
TWh energy sales
•
Expect >50% pro forma EBITDA
from competitive business
•
35,671 (Total)
(3)
•
18,968 (Nuclear)
•
6.6 million electric & gas customers
in IL, PA and MD
7 |
 Transaction
Overview •
100%
stock
–
0.930
shares
of
EXC
for
each
share
of
CEG
•
Upfront
transaction
premium
of
18.5%
(1)
•
$2.10 per share Exelon dividend maintained
•
Expect to close in early 2012
•
Exelon and Constellation shareholder approvals in Q4 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 26, 2011. 8 |
 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 clean baseload 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
9
This transaction meets all of Exelon’s M&A criteria and can be
executed |
 Constellation
Transaction Rationale •
Upfront premium of 18.5%
(1)
•
Dividend accretion of 103% post-closing
•
Enhances upside to power market recovery and synergies
Creates
Shareholder
Value
•
Creates balance sheet capacity to pursue growth opportunities
throughout the competitive portfolio
•
Reduces cost of capital and rating agency pressure with potential
credit uplift from existing standalone rating
•
Rating agency reaction has been positive, with S&P and Moody’s
changing Constellation rating outlook to positive
Balance Sheet
Strength
Complementary
Portfolios
•
Advances
strategy of matching load with physical generation in key
competitive markets
•
Lowers collateral costs of competitive businesses
(1) Based on the 30-day average Exelon and Constellation closing stock
prices as of April 26, 2011. 10
The transaction creates financial and strategic value that is consistent with
Constellation’s existing strategy |
 11
Merger Approvals Process on Schedule
(as of 9/1/11)
•
Filed S-4 Amended Registration Statement
August 17, 2011
•
Shareholder approval anticipated in Q4 2011
•
Submitted Hart-Scott-Rodino filing on May 31, 2011
for review under U.S. antitrust laws
•
Approval expected by January 2012
•
Filed merger approval application and related filings
on May 20, 2011, which assesses market power-
related issues
•
Approval expected in Q4 2011
•
Filed for indirect transfer of Constellation Energy
licenses on May 12, 2011
•
Approval expected by January 2012
•
Filed for approval with the Maryland Public Service
Commission on May 25, 2011
•
Approval expected by January 5, 2012
•
Filed for approval with the New York State Public
Service Commission on May 17, 2011
•
Approval expected in Q4 2011
•
Filed for approval with the Public Utility Commission
of Texas on May 17, 2011
•
Approval received on August 3, 2011
Stakeholder
Securities
and
Exchange
Commission
(SEC)
(File
No.
333-175162)
Department of Justice
Federal
Energy
Regulatory
Nuclear
Regulatory
Maryland
PSC
(Case
No.
9271)
New
York
PSC
(Case
No.
11-E-0245)
Texas
PUC
(Case
No.
39413)
Status of Key Milestones
Filed
Approved
(DOJ)
Commission
(FERC)
(Docket
No.
EC
11-83)
(Docket
Nos.
50-317,
50-318,
50-220,
Commission
50-410,
50-244,
72-8,
72-67) |
 Significant Events
Date of Event
•
Filing of Application
May 25, 2011
•
Intervention Deadline
June 24, 2011
•
Prehearing Conference
June 28, 2011
•
Filing of Staff, Office of People Counsel and Intervenor Testimony
September 16, 2011*
•
Filing of Rebuttal Testimony
October 12, 2011*
•
Filing of Surrebuttal Testimony
October 26, 2011
•
Status Conference
October 28, 2011
•
Evidentiary Hearings
October 31, 2011 -
November 10, 2011
•
Public Comment Hearings
November 29, December 1 &
December 5, 2011
•
Filing of Initial Briefs
December 1, 2011
•
Filing of Reply Briefs
December 15, 2011
•
Decision Deadline
January 5, 2012
12
*
Initial
intervenor
testimony
with
respect
to
market
power
is
due
on
September
23
rd
for
all
parties
except
for
the
Independent
Market
Monitor,
and
rebuttal
testimony
with
respect
to
market
power
is
due
on
October
17
.
th
Maryland PSC Review Schedule |
 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 13
We will
bring
direct
benefits
to
the
State
of
Maryland,
the
City
of
Baltimore
and BGE customers. Total investment in excess of $250 million.
|
 Transaction
Economics Are Attractive for Both Companies
•
Refined synergy run-rate and costs to achieve
estimates due to greater accessibility and availability of
data post-merger announcement
–
Higher net O&M savings over 5 years of ~$50
million
•
Updated synergy run-rate of ~$310 million/year
–
Additional synergies primarily from corporate and
commercial consolidation
–
Most synergies to accrue to shareholders
•
Total costs to achieve of ~$650 million
–
Incremental costs to achieve attributable to
employee related costs and transaction costs
Financial Metrics
•
EPS break-even in 2012 and accretive by >5% in 2013
•
Free cash flow accretive beginning in 2012
•
Lower consolidated liquidity requirements, resulting in cost savings
•
Investment-grade ratings and credit metrics
Synergies
14
Other
~20%
Corporate &
Commercial
Consolidation
~80% |
 Scale, Scope
and Flexibility Across the Value Chain
Upstream
Downstream
Reserves (gas)
266 bcf
Owned Generating
Capacity
36 GWs
(1)
Electric
Transmission
7,350 miles
Electric & Gas Dist.
6.6 million customers
Retail &
Wholesale Volumes
(2)
(Electric & Gas)
~169 TWh, 405 bcf
Note: Data as of 12/31/10 unless stated otherwise.
(1) Generation capacity net of market mitigation assumed to be
2,648 MW consisting of Brandon Shores (1,273 MW), H.A. Wagner (976 MW) and
CP Crane (399 MW). Exelon capacity updated to reflect Wolf Hollow. (2)
Electric load includes all booked 2011E competitive retail sales, wholesale sales,
and sales to load serving entities including ComEd swap. Gas load includes
all booked and forecasted 2011E competitive retail sales. Data also
includes
2011
partial
year
estimated
electric
sales
from
StarTex
and
MXEnergy
(acquired
by
Constellation).
15 |
 MISO (TWh)
PJM (TWh)
South
(1)
(TWh)
ISO-NE & NY ISO
(2)
(TWh)
West (TWh)
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 (owned
and contracted) and booked electric sales for 2011 as of 12/31/10. This data
also includes 2011 partial year generation from Wolf Hollow (acquired by Exelon). Data also includes 2011 partial year
estimated electric sales from StarTex and MXEnergy (acquired by
Constellation). 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. Load
102.1
43.4
58.7
Generation
179.1
31.8
147.3
Constellation
Exelon
Load
6.3
5.8
0.5
Generation
9.1
9.1
Load
Generation
14.2
4.8
9.4
Load
Generation
0.8
0.4
0.4
Load
Generation
16
The combination establishes an industry-leading platform with regional
diversification of the generation fleet
23.2
28.5
29.5
2.4 |
  17 |
 18
2011 Operating Earnings Guidance
2011 Prior
Guidance
(2)
ComEd
PECO
Exelon
Generation
Holdco
Exelon
$3.90 -
$4.20
(1)
$0.55 -
$0.65
$0.50 -
$0.60
$2.85 -
$3.05
(1)
We raised 2011 earnings guidance on July 27, 2011, and we are not updating earnings
guidance at this time. Earnings guidance is only reviewed in connection with our
quarterly earnings announcements or if we expressly indicate that we are updating
the guidance. Refer to the Appendix for a reconciliation of adjusted (non-GAAP)
operating EPS to GAAP EPS.
(2)
Earnings guidance for OpCos may not add up to consolidated EPS guidance.
2Q 2011 operating earnings of
$1.05/share
Strong operating results in second
quarter
•
Nuclear capacity factor of 89.6% largely
due to a higher number of nuclear
refueling outages
•
Strong operating results at utilities
despite severe storms in ComEd
service territory
2011 Revised
Guidance
(2)
$4.05 -
$4.25
(1)
$0.55 -
$0.65
$0.50 -
$0.60
$2.95 -
$3.10
Updating
2011
operating
earnings
guidance
to
$4.05
-
$4.25/share
from
$3.90 -
$4.20/share
(1) |
 19
2011 Projected Sources and Uses of Cash
($ millions)
Exelon
(8)
Beginning Cash Balance
(1)
$800
Cash Flow from Operations
(2)
375
875
3,175
4,350
CapEx (excluding Nuclear Fuel, Nuclear
Uprates, Exelon Wind, Utility Growth CapEx
and Wolf Hollow)
(725)
(325)
(850)
(1,950)
Nuclear Fuel
n/a
n/a
(1,050)
(1,050)
Dividend
(3)
(1,400)
Nuclear Uprates and Exelon Wind
(4)
n/a
n/a
(625)
(625)
Wolf Hollow Acquisition
n/a
n/a
(300)
(300)
Utility Growth CapEx
(5)
(300)
(125)
n/a
(425)
Net Financing (excluding Dividend):
Planned Debt Issuances
(6)
1,000
--
--
1,000
Planned Debt Retirements
(6)
(350)
(250)
--
(600)
Other
(7)
300
(125)
200
550
Ending Cash Balance
(1)
$350
(1) Excludes counterparty collateral activity.
(2) Cash Flow from Operations primarily includes net cash flows provided by
operating activities and net cash flows used in investing activities other than capital expenditures.
(3) Assumes 2011 dividend of $2.10/share. Dividends are subject to
declaration by the Board of Directors. (4) Includes $400 million in
Nuclear Uprates and $225 million for Exelon Wind spend. (5) Represents
new business, smart grid/smart meter investment and transmission growth projects.
(6) Planned Issuances of $1B at ComEd reflect the $600M January 18, 2011
issuance and $400M of ComEd’s $600M September 7, 2011 issuance. Incremental $200M of financing
was primarily utilized to retire $191M of tax-exempt debt at ComEd.
(7) “Other”
includes proceeds from options and expected changes in short-term debt.
(8) Includes cash flow activity from Holding Company, eliminations, and other
corporate entities. |
 20
Sufficient Liquidity
($ millions)
Exelon
(3)
Aggregate Bank Commitments
(1)
$1,000
$600
$5,600
$7,700
Outstanding Facility Draws
--
--
--
--
Outstanding Letters of Credit
(195)
(1)
(121)
(324)
Available Capacity Under Facilities
(2)
805
599
5,479
7,376
Outstanding Commercial Paper
--
--
--
(139)
Available Capacity Less Outstanding
Commercial Paper
$805
$599
$5,479
$7,237
Exelon bank facilities are largely untapped
(1) Excludes commitments from Exelon’s Community and Minority Bank
Credit Facility (2) Available Capacity Under Facilities represents the
unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and facility draws. The
amount of commercial paper outstanding does not reduce the available capacity under
the credit agreements. (3) Includes Exelon Corporate’s $500M
credit facility, letters of credit and commercial paper outstanding. Available
Capacity Under Bank Facilities as of July 14, 2011 |
 21
Key Credit Metrics
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
2009A
2010A
2011E
ExGen/Corp
ComEd
PECO
Exelon
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
2009A
2010A
2011E
ExGen/Corp
ComEd
PECO
Exelon
FFO / Debt
(1)
(1)
See slide 53 for reconciliations to GAAP.
(2)
Current senior unsecured ratings for Exelon and Exelon Generation and senior
secured ratings for ComEd and PECO as of September 2, 2011. (3)
FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt
obligations of Exelon Corp. (4)
Moody’s placed Exelon and Generation under review for a possible downgrade
after the proposed merger with Constellation Energy was announced.
Moody’s
Credit
Ratings
(2)
S&P
Credit
Ratings
(2)
Fitch
Credit
Ratings
(2)
FFO / Debt
Target
Range
(2)
Exelon:
Baa1
(4)
BBB-
BBB+
ComEd:
Baa1
A-
BBB+
15-18%
PECO:
A1
A-
A
15-18%
Generation:
A3
(4)
BBB
BBB+
30-35%
(3)
Interest Coverage
(1)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2009A
2010A
2011E
ExGen/Corp
ComEd
PECO
Exelon
Debt / Cap
(1) |
 22
EPA Regulations Are Moving Forward
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
Pre Compliance Period
Compliance With Toxics Rule
Compliance With Cross-State Air Pollution Rule (CSAPR)
Interim CAIR
Develop CSAPR (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/).
Develop Cross-
State Air Pollution
Rule |
 23
Rule encourages future development of transmission infrastructure in
the U.S.
Appropriately assigns the cost of new transmission lines to customers
benefitting from improved reliability
Maintains the ability of transmission providers like ComEd and PECO
to construct transmission upgrades in their service territories
PJM tariffs will require modifications to achieve goals of the final rule
FERC Transmission Ruling Supports
Competitive Markets
Exelon is committed to ensuring PJM’s tariff is modified to achieve the
goals of the FERC Order |
 RITE
Line Project Update Project Background
•
420 miles of 765kV transmission
stretches from Northern Illinois to
Ohio. The RITE Line will be built
from the existing 765kV system in
Ohio in the East to the West
•
Estimated construction to begin
2015 pending regulatory approvals
and siting
Strategic and Financial Objectives
•
Ensures reliability, enables states to
meet RPS standards, and supports
the integration of more renewables
•
ComEd/Exelon investment ~ $1.1
billion
•
Requested ROE 12.70%
Latest Developments
•
Signed partnership agreement with
ETA on July 13
•
Completed FERC incentive rate
filing on July 18. Expect FERC ruling
by October 2011.
24
Note: ETA = Electric Transmission America
RPS = Renewable Portfolio Standards
RTEP = Regional Transmission Expansion Planning
2014
2016
2017
2018
FERC Final Rule on NOPR
PJM Compliance Filing
2010
State Local Outreach & Project Siting
Establish Definitive Agreement
Between Exelon & ETA
2012
FERC Incentive
Filing
Construction
RITE Line
2013
2011
2015
In-Service
Pursue PJM RTEP Approval
RTEP Approval expected
by 2012, depending on
PJM Planning criteria
Time length is dependent on:
1. Land negotiations
2. Receipt of State
Line can be in-serviced in
phases
Construction can range from 3-5 yrs
depending on the length of time
needed to site the project
Non-Project Specific Events |
  25 |
 26
Factors Influencing RPM
Auction (PY 14/15 vs. PY
13/14)
Expected
Exelon
Price
Impact
Actual
Price
Impact
Actual Auction Results and Supplier
Bidding Behavior
Cost of Environmental
Upgrades
and Higher Net
ACRs for Coal Units
•
3,237 MW reduction in offered capacity
(coal/oil/gas)
•
7,746 MW reduction in cleared capacity
(coal/oil/gas)
Import Transmission Limits
and Objectives
(muted impact on portfolio
revenues due to regional
diversification)
•
Total revenue from PY 14/15 capacity
auction close to PY 13/14 revenues for
Exelon fleet
•
Balanced portfolio, split evenly between east
and west, reduces volatility in revenues due
to transmission or demand changes.
Demand Response Growth
•
Increase in cleared DR (~4,836 MW) was
close to internal estimates.
•
Limited DR was capped, causing price
separation for premium products
RPM Results: Favorable and As Expected
Auction results were in line with Exelon’s expectations with EPA
regulations being one of the primary drivers of bidding behavior
|
 27
Exelon Generation Hedging Program
Q2 provided favorable 2013 sales
opportunities
•
Reflects successful participation in Illinois IPA
procurements in the first half of May
Price movements
•
Recovery in heat rates, especially at NI Hub
•
Upward move in NI Hub wrap
2015
PJM NI Hub ATC Heat Rates
2013 PJM West Hub & NI Hub ATC Prices
2013 Hedge % and Value Above Ratable |
 28
Diverse Generation and Sales Mix
Exelon’s diverse portfolio is well positioned to serve a variety of
products 2011-2013 Sales as a Percentage
of Expected Generation
Current Owned & Contracted
Generation Capacity by Fuel Type
Matching Exelon’s favorable asset position with a diverse set of products is
an important aspect of the hedging program
•
Reduces and diversifies our collateral exposure
•
Enables sales to be made closer to assets
•
Increases opportunities for margin via retail, utility solicitations and
mid-marketing channels •
Use of alternate channels and locations help minimize liquidity and congestion
risks Data as of 6/30/2011
(1) Reflects owned and contracted generation as of 6/30/2011. Excludes Cromby
Station 1 & 2, Eddystone 1&2 and PPA with Tenaska Georgia Partners. Includes Wolf Hollow PPA
volume only (350 MW).
(1) |
 Wolf
Hollow Acquisition 29
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
•
$305M purchase price compares favorably to
cost of other recent transactions
•
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 closed on August 24, 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 |
 30
NRC Near-Term Task Force Recommendations
Key Findings :
U.S nuclear plants are safe
No major changes to spent nuclear
fuel storage and licensing
Key Recommendations:
Clarifying regulatory framework
Ensuring protection and enhancing
mitigation
Strengthening emergency
preparedness
Improving efficiency of NRC programs
Report was first step in systematic review that NRC will conduct;
stakeholder input will be sought |
 31
Exelon Nuclear Fleet Overview –
IL
Plant
Location
Type/
Containment
Water Body
License Extension
Status / License
Expiration
(1)
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 (Fall 2011)
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
Clinton Lake
2026
100%
2018
Dresden, IL
(Units 2 and 3)
BWR
Steel Vessel
Kankakee
River
Renewed / 2029,
2031
100%
Dry cask
LaSalle, IL
(Units 1 and 2)
BWR
Concrete/Steel
Lined
Illinois River
2022, 2023
100%
Dry Cask
Quad Cities, IL
(Units 1 and 2)
BWR
Steel Vessel
Mississippi
River
Renewed / 2032
75% Exelon, 25%
Mid-American
Holdings
Dry cask
Exelon pursues license extensions well in advance of expiration to ensure adequate
time for review by the NRC
(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. |
 32
Exelon Nuclear Fleet Overview –
PA and NJ
Plant, Location
Type,
Containment
Water Body
License Extension
Status / License
Expiration
(1)
Ownership
Spent Fuel Storage/
Date to lose full
core discharge
capacity
(2)
Limerick, PA
(Units 1 and 2)
BWR
Concrete/Steel
Lined
Schuylkill
River
Filed application in
June 2011
(decision expected
in 2013)/ 2024,
2029
100%
Dry cask
Oyster Creek, NJ
(Unit 1)
BWR
Steel Vessel
Barnegat Bay
Renewed / 2029
(3)
100%
Dry cask
Peach Bottom, PA
(Units 2 and 3)
BWR
Steel Vessel
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 Generation will permanently cease
generation operations at Oyster Creek by December 31, 2019. The current NRC
license for Oyster Creek expires in 2029.
Exelon pursues license extensions well in advance of expiration to ensure adequate
time for review by the NRC |
 33
Exelon Generation Hedging Disclosures
(as of June 30, 2011) |
 34
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 June 30, 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. |
 35
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 |
 36
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 |
 37
2011
2012
2013
Estimated
Open
Gross
Margin
($
millions)
(1)(2)
$5,450
$5,000
$5,600
Open gross margin assumes all expected generation is sold
at the Reference Prices listed below
Reference Prices
(1)
Henry Hub Natural Gas ($/MMBtu)
NI-Hub ATC Energy Price ($/MWh)
PJM-W ATC Energy Price ($/MWh)
ERCOT
North
ATC
Spark
Spread
($/MWh)
(3)
$4.37
$33.18
$46.07
$3.77
$4.84
$33.10
$46.02
$1.40
$5.16
$34.45
$47.45
$2.27
Exelon Generation Open Gross Margin and
Reference Prices
(1)
Based on June 30, 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, $2.50
variable O&M. |
 38
2011
2012
2013
Expected Generation
(GWh)
(1)
166,100
165,600
163,000
Midwest
99,000
97,900
95,800
Mid-Atlantic
56,300
57,100
56,500
South & West
10,800
10,600
10,700
Percentage of Expected Generation Hedged
(2)
95-98%
82-85%
49-52%
Midwest
95-98
81-84
48-51
Mid-Atlantic
96-99
85-88
50-53
South & West
86-89
63-66
45-48
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$43.00
$41.00
$40.00
Mid-Atlantic
$57.00
$50.00
$50.50
South & West
$4.50
$0.00
($2.00)
Generation Profile
(1)
Expected generation represents the amount of energy estimated to be generated or purchased through
owned or contracted for capacity. Expected generation is based upon a simulated dispatch
model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and
options. Expected generation assumes 12 refueling outages in 2011 and 10 refueling outages in 2012 and
2013 at Exelon-operated nuclear plants and Salem. Expected generation assumes
capacity factors of 93.0%, 93.4% and 93.2% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in 2012
and 2013 do not represent guidance or a forecast of future results as Exelon has not completed its
planning or optimization processes for those years. (2)
Percent of expected generation hedged is the amount of equivalent sales divided by the expected
generation. Includes all hedging products, such as wholesale and retail sales of power,
options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.
(3)
Effective realized energy price is representative of an all-in hedged price, on a per MWh basis,
at which expected generation has been hedged. It is developed by considering the energy
revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs
and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at
prices other than RPM clearing prices including our load obligations. It can be compared
with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. |
 39
Gross
Margin
Sensitivities
with
Existing
Hedges
($
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)
$5
$(5)
$5
$(5)
+/-
$25
2012
$85
$(35)
$95
$(75)
$55
$(55)
+/-
$45
2013
$340
$(290)
$250
$(245)
$155
$(150)
+/-
$50
Exelon Generation Gross Margin Sensitivities
(with Existing Hedges)
(1)
Based on June 30, 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. |
 40
95% case
5% case
$5,500
$7,100
$6,900
$6,000
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
$6,800
$5,200
(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 June 30, 2011. |
 41
Midwest
Mid-Atlantic
South & West
Step 1
Start with
fleetwide open gross margin
$5.45 billion
Step 2
Determine the mark-to-market value
of energy hedges
99,000GWh * 96% *
($43.00/MWh-$33.18MWh)
= $0.93 billion
56,300GWh * 97% *
($57.00/MWh-$46.07MWh)
= $0.60 billion
10,800GWh * 87% *
($4.50/MWh-$3.77MWh)
= $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)
$0.93
billion
+
$0.60
billion
+
$0.00
billion
$5.45 billion
$6.98 billion |
 20
25
30
35
40
45
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
35
40
45
50
55
60
65
70
75
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
4.0
4.5
5.0
5.5
6.0
6.5
7.0
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
50
55
60
65
70
75
80
85
90
95
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
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
$4.58
2013 $5.05
Forward NYMEX Coal
2012
$81.06
2013
$85.51
2012 Ni-Hub $42.62
2013 Ni-Hub
$45.58
2013 PJM-West $56.91
2012 PJM-West
$53.84
2012 Ni-Hub
$27.61
2013 Ni-Hub
$30.00
2013 PJM-West
$42.07
2012 PJM-West
$39.62
42
Rolling 12 months, as of August 31 2011. Source: OTC quotes and electronic trading
system. Quotes are daily. st |
 4.5
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
8.2
8.4
8.6
8.8
9.0
9.2
9.4
9.6
9.8
10.0
10.2
10.4
10.6
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
35
40
45
50
55
60
65
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
Market Price Snapshot
2013
10.14
2012
10.00
2012
$45.27
2013
$50.53
2012
$4.53
2013
$4.99
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
$10.09
2013
$12.06
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
43
Rolling 12 months, as of August 31 2011. Source: OTC quotes and electronic trading
system. Quotes are daily. st |
 44 |
 ComEd
2010 Rate Case Final Order (ICC Docket No. 10-0467)
On 5/24/11, the Illinois Commerce Commission (ICC) issued an order in ComEd’s
2010 distribution rate case
–
new rates went into effect in June 2011
Rate Case Details
ICC Order
(5/24/11)
ComEd Reply Brief
(2/23/11)
Revenue Requirement Increase
$143M
(1)
$343M
Rate Base
$6,549M
$7,349M
ROE
10.50%
11.30%
(2)
Equity Ratio
47.28%
47.28%
(1)
Reflects ~$(13)M adjustment to ICC Order
(2)
Included 40 bp adder for energy efficiency, not approved by ICC
45 |
 ComEd
Load Trends Chicago
U.S.
Unemployment rate
(1)
9.3%
9.2%
2011 annualized growth in
gross domestic/metro product
(2)
2.5%
Note: C&I = Commercial & Industrial
2010
2Q11 2011E
Average Customer Growth
0.2%
0.4%
0.4%
Average Use-Per-Customer
(1.4)%
(2.0)%
0.0%
Total Residential
(1.2)%
(1.6)% 0.4%
Small C&I
(0.6)%
(0.2)%
(0.3)%
Large C&I
2.6%
(0.9)%
0.0%
All Customer Classes
0.2%
(0.8)%
0.0%
(1)
Source: U.S. Dept. of Labor (June 2011) and Illinois
Department of Security (June 2011)
(2) Source: Global Insight (May 2011)
46
-
6.0%
-
3.0%
0.0%
3.0%
6.0%
-
6.0%
-
3.0%
0.0%
3.0%
6.0%
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
All Customer Classes
Large C&I
Residential
Gross Metro Product
Weather-Normalized Load Year-over-Year
Key Economic Indicators
Weather-Normalized Load
2.7% |
 Illinois Power Agency (IPA)
RFP Procurement
Note: Chart is for illustrative purposes only.
REC
=
Renewable
Energy
Credit;
RFP
=
request
for
proposal;
ATC
=
Around
the
Clock
June 2012
June 2013
June 2014
Financial Swap Agreement with ExGen
(ATC baseload energy –
notional quantity
3,000 MW)
Standard Products and Annual REC Procurement held in
May 2011
–
Effective ATC of $34.77/MWh for 9 winning Standard Product
suppliers for the 2011-12 plan-year
–
2.12
million
MWh
of
renewable
resources
for
the
2011-12
plan-year
from 12 winning suppliers
–
Provisions included:
•
Annual energy procurements over a three-year time frame
•
Target a 35%/35%/30% laddered procurement approach
•
No additional Energy Efficiency, Demand Response purchases
•
No additional long-term contracts for renewables
•
No 10% overprocurement for summer peak energy
June 2015
Delivery
Period
Peak
Off-Peak
June 2011 -
May 2012
5,118
4,001
June 2012 -
May 2013
1,129
358
June 2013 -
May 2014
6,494
6,062
Volume procured in the 2011 IPA
Procurement Event (GWh)
Term
Fixed Price
($/MWh)
1/1/11-12/31/11
$51.26
1/1/12-12/31/12
$52.37
1/13/13-5/31/13
$53.48
47
June 2011
Financial Swap
2010 RFP
2011 RFP
2011 RFP
2011 RFP
2012 RFP
2012 RFP
2012 RFP
2013 RFP
2013 RFP
2014 RFP |
  48 |
 49
PECO Load Trends
Philadelphia
U.S.
Unemployment rate
(1)
7.9%
9.2%
2011 annualized growth in
gross domestic/metro product
(2)
2.4%
Note: C&I = Commercial & Industrial
Key Economic Indicators
Weather-Normalized Load
2010
2Q11 2011E
Average Customer Growth
0.3%
0.5%
0.4%
Average Use-Per-Customer
0.3%
2.8%
1.7%
Total Residential
0.5%
3.2% 2.2%
Small C&I
(1.9)%
1.7% 0.7%
Large C&I
0.8%
(3.3)% (2.3)%
All Customer Classes
0.1%
(0.1)% (0.0)%
(1) Source:
U.S
Dept.
of
Labor
data
June
2011
-
US
U.S
Dept.
of
Labor
prelim.
data
May
2011
-
Philadelphia
(2) Source: Global Insight May 2011
Weather-Normalized Load Year-over-Year
-6.0%
-3.0%
0.0%
3.0%
6.0%
-
6.0%
-3.0%
0.0%
3.0%
6.0%
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
All Customer Classes
Large C&I
Residential
Gross Metro Product
2.7% |
 50
PECO Procurement Plan
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 –
weighted average wholesale prices
80 MW of baseload (24x7) block energy product (for Jan-Dec 2012) –
$51.52/MWh
70 MW of Jun-Aug 2011 summer on-peak block energy product –
$67.24/MWh
40 MW of Dec 2011-Feb 2012 winter on-peak block energy product
– $63.05/MWh
Large Commercial and Industrial (Hourly) –
weighted average
wholesale price
36%
of
hourly
full
requirements
product
(for
Jun
2011-May
2012)
(3)
–
$4.97/MWh
(4)
May
2,
2011
RFP
-
Fifth
in
a
series
of
nine
procurements for the PUC-approved
Default Service Plan
Next RFP to be held on September 19, 2011
(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. (4)
The price for the hourly
full requirements product includes only ancillary services/Alternative Energy
Portfolio Standard (AEPS) and miscellaneous costs. The price does not
include energy and capacity costs. Energy costs will be based on the PECO
Zone Day-Ahead locational marginal pricing (LMP) price, and capacity will be based on the
PJM RPM price per day. |
 51
Appendix |
 52
Exelon Consolidated Metric Calculations and Ratios
$ in millions
FFO / Debt Coverage =
FFO (a)
Adjusted Debt (b)
FFO Interest Coverage =
FFO (a) + Adjusted Interest (c)
Adjusted Interest (c)
Adjusted Capitalization (e) =
Adjusted Debt (b) + Adjusted Equity (d)
=
32,606
Rating Agency Debt Ratio =
Adjusted Debt (b)
Adjusted Capitalization (e)
32%
7.2x
58%
=
=
=
2010A Credit Metrics
(1)
Includes changes in A/R, Inventories, A/P and other accrued expenses, option premiums,
counterparty collateral and income taxes. Impact to FFO is opposite of impact to cash flow
(2)
Reflects retirement of variable interest entity + change in restricted cash
(3)
Reflects net capacity payment – interest on PV of PPAs (using weighted average cost of debt)
(4)
Reflects employer contributions – (service costs + interest costs + expected return on
assets), net of taxes at 35%
(5)
Reflects operating lease payments – interest on PV of future operating lease payments (using
weighted average cost of debt)
(6)
Includes AFUDC / capitalized interest
(7)
Reflects PV of net capacity purchases (using weighted average cost of debt)
(8)
Reflects unfunded status, net of taxes at 35%
(9)
Reflects PV of minimum future operating lease payments (using weighted average cost of debt)
(10)
Nuclear decommissioning trust fund balance > asset retirement obligation. No debt imputed
(11)
Includes accrued interest less securities qualifying for hybrid treatment (50% debt / 50% equity)
(12)
Reflects interest on PV of minimum future operating lease payments (using weighted average cost of
debt)
(13)
Reflects interest on PV of PPAs (using weighted average cost of debt)
(14)
Includes AFUDC / capitalized interest and interest on securities qualifying for hybrid treatment (50%
debt / 50% equity)
(15)
Includes interest on securities qualifying for hybrid treatment (50% debt / 50% equity)
Exelon 2010 YE Adjustments
FFO Calculation
2010 YE
Source -
2010 Form 10-K (.pdf version)
Net Cash Flows provided by Operating Activities
5,244
Pg 159 -
Stmt. of Cash Flows
+/-
Change in Working Capital
644
Pg
159
-
Stmt.
of
Cash
Flows
(1)
-
PECO Transition Bond Principal Paydown
(392)
Pg
174
-
Stmt.
of
Cash
Flows
(2)
+ PPA Depreciation Adjustment
207
Pg
295
-
Commitments
and
Contingencies
(3)
+/-
Pension/OPEB Contribution Normalization
448
Pg 268-269 -
Post-retirement Benefits
(4)
+ Operating Lease Depreciation Adjustment
35
Pg
299
-
Commitments
and
Contingencies
(5)
+/-
Decommissioning activity
(143)
Pg 159-
Stmt. of Cash Flows
+/-
Other Minor FFO Adjustments
(6)
(54)
= FFO (a)
5,989
Debt Calculation
Long-term Debt (incl. Current Maturities and A/R agreement)
12,828
Pg 161 -
Balance Sheet
Short-term debt (incl. Notes Payable / Commercial Paper)
-
Pg 161 -
Balance Sheet
-
PECO Transition Bond Principal Paydown
-
N/A -
no debt outstanding at year-end
+ PPA Imputed Debt
1,680
Pg
295
-
Commitments
and
Contingencies
(7)
+ Pension/OPEB Imputed Debt
3,825
Pg
268
-
Post-retirement
benefits
(8)
+ Operating Lease Imputed Debt
428
Pg
299
-
Commitments
and
Contingencies
(9)
+ Asset Retirement Obligation
-
Pg
261-267
-
Asset
Retirement
Obligations
(10)
+/-
Other Minor Debt Equivalents
(11)
84
= Adjusted Debt (b)
18,845
Interest Calculation
Net Interest Expense
817
Pg 158 -
Statement of Operations
-
PECO Transition Bond Interest Expense
(22)
Pg 182 -
Significant Accounting Policies
+ Interest on Present Value (PV) of Operating Leases
29
Pg
299
-
Commitments
and
Contingencies
(12)
+ Interest on PV of Purchased Power Agreements (PPAs)
99
Pg
295
-
Commitments
and
Contingencies
(13)
+/-
Other Minor Interest Adjustments
(14)
37
= Adjusted Interest (c)
960
Equity Calculation
Total Equity
13,563
Pg 161 -
Balance Sheet
+ Preferred Securities of Subsidaries
87
Pg 161 -
Balance Sheet
+/-
Other Minor Equity Equivalents
(15)
111
= Adjusted Equity (d)
13,761 |
 53
YTD GAAP EPS Reconciliation
Six Months Ended June 30, 2011
ExGen
ComEd
PECO
Other
Exelon
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.69
$0.26
$0.32
$(0.04)
$2.22
Mark-to-market impact of economic hedging activities
(0.25)
-
-
-
(0.25)
Unrealized gains related to nuclear decommissioning trust funds
0.04
-
-
-
0.04
Retirement of fossil generating units
(0.04)
-
-
-
(0.04)
Non-cash charge resulting from Illinois tax rate change legislation
(0.03)
(0.01)
-
-
(0.04)
Recovery of costs pursuant to distribution rate case order
-
0.03
-
-
0.03
Constellation merger costs
-
-
-
(0.02)
(0.02)
YTD 2011 GAAP Earnings (Loss) Per Share
$1.41
$0.28
$0.32
$(0.06)
$1.94
NOTE: All amounts shown are per Exelon share and represent contributions to
Exelon's EPS. Amounts may not add due to rounding. Six Months Ended June
30, 2010 ExGen
ComEd
PECO
Other
Exelon
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.35
$0.37
$0.31
$(0.04)
$1.99
2007 Illinois electric rate settlement
(0.01)
-
-
-
(0.01)
Mark-to-market impact of economic hedging activities
0.10
-
-
-
0.10
Unrealized losses related to nuclear decommissioning trust funds
(0.05)
-
-
-
(0.05)
Non-cash charge resulting from health care legislation
(0.04)
(0.02)
(0.02)
(0.02)
(0.10)
Non-cash charge remeasurement of income tax uncertainties
0.10
(0.16)
(0.03)
(0.01)
(0.10)
Retirement of fossil generating units
(0.03)
-
-
-
(0.03)
YTD 2010 GAAP Earnings (Loss) Per Share
$1.42
$0.19
$0.26
$(0.07)
$1.80 |
 54
GAAP to Operating Adjustments
Exelon’s 2011 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
•
Significant impairments of assets, including goodwill
•
Changes in decommissioning obligation estimates
•
Non-cash charge to remeasure deferred taxes at higher Illinois corporate tax
rates •
Financial impacts associated with the planned retirement of fossil generating
units •
One-time benefits reflecting ComEd’s 2011 distribution rate case order
for the recovery of previously
incurred
costs
related
to
the
2009
restructuring
plan
and for the passage of Federal
health care legislation in 2010
•
Certain costs associated with Exelon’s proposed merger with
Constellation •
Other unusual items
•
Significant changes to GAAP
Operating
earnings
guidance
assumes
normal
weather
for
remainder
of the year |
 55
Exelon Investor Relations Contacts
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:
Stacie Frank, Vice President
312-394-3094
Stacie.Frank@ExelonCorp.com
Melissa Sherrod, Director
312-394-8351
Melissa.Sherrod@ExelonCorp.com
Ishaan Kapoor, Manager
312-394-3657
Ishaan.Kapoor@ExelonCorp.com
Marybeth Flater, Manager
312-394-8354
Marybeth.Flater@ExelonCorp.com
Sandeep Menon, Principal Analyst
312-394-7279
Sandeep.Menon@ExelonCorp.com |