Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - EXELON GENERATION CO LLC | d8k.htm |
| EX-99.1 - PRESS RELEASE AND EARNINGS RELEASE ATTACHMENTS - EXELON GENERATION CO LLC | dex991.htm |
 Earnings Conference Call
2
nd
Quarter 2011
July 27, 2011
EXHIBIT 99.2 |
 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 or 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
June
30,
2011
(to
be
filed
on
July
27,
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
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,
are
more
fully
discussed
in
the
preliminary
joint
proxy
statement/prospectus
included
in
the
Registration Statement on Form S-4 that Exelon filed with the SEC on June 27,
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 June 27, 2011,
Exelon
filed
with
the
SEC
a
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. Cautionary Statements Regarding
Forward-Looking Information (Continued)
3 |
 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
Use of Non-GAAP Financial Measures
This presentation includes references to adjusted (non-GAAP) operating earnings
and non-GAAP cash flows that exclude the impact of certain factors. We
believe that these adjusted operating earnings and cash flows are representative of the
underlying
operational
results
of
the
Companies.
Please
refer
to
the
appendix
to
this
presentation
for
a
reconciliation of
adjusted (non-GAAP) operating earnings to GAAP earnings. Please refer to
the footnotes of the following slides for a reconciliation of non-GAAP
cash flows to GAAP cash flows. 4
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. |
 5
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
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)
(1)
Refer to Earnings Release Attachments for additional details and 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. |
 Status of
Merger Approvals (as of 7/26/11) Stakeholder
Status of Key Milestones
Filed
Approved
Securities
and
Exchange
Commission
(SEC)
(File
No.
333-175162)
•
Filed S-4 Registration Statement June 27, 2011
•
Shareholder approval anticipated in Q3 2011
Department
of
Justice
(DOJ)
•
Submitted Hart-Scott-Rodino filing on May 31, 2011
for review under U.S. antitrust laws
•
Approval expected by January 2012
Federal
Energy
Regulatory
Commission
(FERC)
(Docket
No.
EC
11-83)
•
Filed merger approval application and related filings
on May 20, 2011, which assesses market power-
related issues
•
Approval expected in Q4 2011
Nuclear
Regulatory
Commission
(Docket
Nos.
50-317,
50-318,
50-
220,
50-410,
50-244,
72-8,
72-67)
•
Filed for indirect transfer of Constellation Energy
licenses on May 12, 2011
•
Approval expected by January 2012
Maryland
PSC
(Case
No.
9271)
•
Commission on May 25, 2011
•
Approval expected by January 2012
New
York
PSC
(Case
No.
11-E-0245)
•
Filed for approval with the New York State Public
Service Commission on May 17, 2011
•
Approval expected in Q4 2011
Texas
PUC
(Case
No.
39413)
•
Filed for approval with the Public Utility Commission
of Texas on May 17, 2011
•
Approval expected in Q3 2011
6
Filed for approval with the Maryland Public Service |
 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
7
Maryland PSC Review Schedule |
 8
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
|
 9
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
is
first
step
in
systematic
review
that
NRC
will
conduct;
stakeholder
input
will
be
sought |
 10
Key Financial Messages
Higher than expected 2Q 2011 operating earnings of
$1.05/share
(1)
•
NDT funds special transfer tax deduction benefit of $0.07 per share in 2Q;
additional benefit of $0.01 per share expected in second half of
2011
ICC approved revenue increase of $143 million in ComEd’s
2010 distribution rate case
Expect to generate $4.3 billion cash from operations in 2011
Expect
3Q
2011
operating
earnings
of
$1.00
-
$1.10/share
(1)
(1) Refer to Earnings Release Attachments for additional details
and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
Note: NDT = Nuclear Decommissioning Trust |
 11
Exelon Generation
Operating EPS Contribution
2010
2011
Outage Days
(3)
2Q10
2Q11
Refueling
44
103
Non-refueling
15
24
2Q
YTD
$0.69
$1.35
Note: PPA = Power Purchase Agreement
Key Drivers –
2Q11 vs. 2Q10
(1)
Higher margins due to expiration of the
PECO PPA: $0.15
Favorable market/portfolio conditions:
$0.07
(2)
NDT funds special transfer tax deduction:
$0.07
Higher O&M costs, including planned
nuclear refueling outages: $(0.07)
Nuclear volume: $(0.05)
Higher nuclear fuel costs: $(0.02)
Higher depreciation and interest expense:
$(0.03)
$0.79
$1.69
(1)
Refer to the Earnings Release Attachments for additional details and to the Appendix for a
reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. (2)
Favorable market/portfolio conditions include: $0.02 Wind, $0.02 Hydro volume and $0.03 higher
realized prices in Mid-Atlantic (3) Outage days exclude
Salem. |
 12
Key Drivers –
2Q11 vs. 2Q10
(1)
IL distribution tax refund recorded in
2010: $(0.02)
Higher O&M costs: $(0.02)
Higher depreciation and interest
expense: $(0.02)
One-time impacts of distribution rate
case order: $0.03
Electric distribution rates: $0.01
ComEd Operating EPS Contribution
(1) Refer to the Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
2010
2011
2Q
YTD
$0.18
2Q11
Actual
Actual
Normal
Heating Degree-Days
519 823 766
Cooling Degree-Days 312
237
224 $0.37
$0.15
$0.26
2Q10 |
 13
PECO Operating EPS Contribution
Key Drivers –
2Q11 vs. 2Q10
(1)
2010 CTC collections, net of
amortization expense: $(0.06)
Electric and gas distribution rates: $0.02
Decreased storm costs: $0.01
Lower interest expense: $0.01
2010
2011
(1) Refer to the Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. 2Q
YTD
$0.15
2Q11
$0.31
Note: CTC = Competitive Transition Charge
$0.32
$0.13
Actual
Actual
Normal
Heating Degree-Days
299 331 458
Cooling Degree-Days 586
494
332 2Q10
|
 14
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
2013 Hedge % and Value Above Ratable
2013 PJM West Hub & NI Hub ATC Prices
PJM NI Hub ATC Heat Rates |
 15
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
(1)
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). |
 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 ~ $1.1
billion
Requested ROE 12.70%
Latest Developments
Signed partnership agreement with
ETA on July 13
Completed FERC incentive rate
filing on July 18. Expect FERC ruling
by October 2011.
16
Note: ETA = Electric Transmission America
RPS = Renewable Portfolio Standards
RTEP = Regional Transmission Expansion Planning |
 17
($ 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
(350)
(250)
--
(600)
Other
(7)
300
(125)
200
550
Ending Cash Balance
(1)
$350
2011 Projected Sources and Uses of Cash
(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)
Excludes ComEd’s $191 million of tax-exempt bonds that are backed by letters of credit
(LOCs). Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank
of Tokyo. PECO’s A/R Agreement was extended in accordance with its terms through September 6, 2011.
(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.
|
 18
Exelon Generation Hedging Disclosures
(as of June 30, 2011) |
 19
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. |
 20
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 |
 21
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 |
 22
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)
(3)
ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50
variable O&M. Gross margin is defined as operating revenues less fuel expense and purchased
power expense, excluding the impact of decommissioning and other incidental revenues. Open
gross margin is estimated based upon an internal model that is developed by dispatching our expected generation to current market power and fossil fuel prices. Open
gross margin assumes there is no hedging in place other than fixed assumptions for capacity cleared in
the RPM auctions and uranium costs for nuclear power plants. Open gross margin contains
assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity revenues and payments. The
estimation of open gross margin incorporates management discretion and modeling assumptions that are
subject to change. |
 23
2011
2012
2013
Expected Generation
(GWh)
(1)
166,100
165,600
163,000
Midwest
99,000
97,900
95,800
Mid-Atlantic
56,300
57,100
56,500
South & West
10,800
10,600
10,700
Percentage of Expected Generation Hedged
(2)
95-98%
82-85%
49-52%
Midwest
95-98
81-84
48-51
Mid-Atlantic
96-99
85-88
50-53
South & West
86-89
63-66
45-48
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$43.00
$41.00
$40.00
Mid-Atlantic
$57.00
$50.00
$50.50
South & West
$4.50
$0.00
($2.00)
Generation Profile
(1)
Expected generation represents the amount of energy estimated to be generated or purchased through
owned or contracted for capacity. Expected generation is based upon a simulated dispatch
model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products,
and options. Expected generation assumes 12 refueling outages in 2011 and 10 refueling outages in 2012
and 2013 at Exelon-operated nuclear plants and Salem. Expected generation assumes
capacity factors of 93.0%, 93.4% and 93.2% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in
2012 and 2013 do not represent guidance or a forecast of future results as Exelon has not completed
its planning or optimization processes for those years. (2)
Percent of expected generation hedged is the amount of equivalent sales divided by the expected
generation. Includes all hedging products, such as wholesale and retail sales of power,
options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.
(3)
Effective realized energy price is representative of an all-in hedged price, on a per MWh basis,
at which expected generation has been hedged. It is developed by considering the energy
revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium
costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted
at prices other than RPM clearing prices including our load obligations. It can be
compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges.
|
 24
Gross Margin Sensitivities with Existing Hedges ($ 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. |
 25
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.
|
 26
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 |
 Market Price Snapshot
20
25
30
35
40
45
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
35
40
45
50
55
60
65
70
75
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
50
55
60
65
70
75
80
85
90
95
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
Forward NYMEX Natural Gas
PJM-West and Ni-Hub On-Peak Forward Prices
PJM-West and Ni-Hub Wrap Forward Prices
2012
$4.79
2013 $5.16
Forward NYMEX Coal
2012
$81.91
2013
$86.11
2012 Ni-Hub $42.20
2013 Ni-Hub
$44.54
2013 PJM-West $56.95
2012 PJM-West
$54.64
2012 Ni-Hub
$27.02
2013 Ni-Hub
$28.96
2013 PJM-West
$42.06
2012 PJM-West
$39.97
27
Rolling
12
months,
as
of
July
21 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
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8.2
8.4
8.6
8.8
9.0
9.2
9.4
9.6
9.8
10.0
10.2
10.4
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
35
40
45
50
55
60
65
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
Market Price Snapshot
2013
10.13
2012
9.91
2012
$46.86
2013
$51.26
2012
$4.73
2013
$5.06
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
$10.24
2013
$12.25
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
28
Rolling
12
months,
as
of
July
21 2011.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
st |
 29
Appendix |
 30
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
Develop Cross-
State Air Pollution
Rule
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/). |
 Wolf
Hollow Acquisition 31
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 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 |
 32
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 (Summer
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
(1)
Operating license renewal process takes approximately 4-5 years from
commencement until completion of NRC review. (2)
Exelon pursues license extensions well in advance of expiration to ensure adequate time
for review by the NRC
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. |
 33
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
(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
core. Dry cask storage will be in operation at those sites prior to losing full core discharge
capacity in their on-site storage pools. |
 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
34 |
 ComEd
Load Trends Chicago
U.S.
Unemployment rate
(1)
9.3%
9.2%
2011 annualized growth in
gross
domestic/metro
product
(2)
2.5%
2.7%
Note: C&I = Commercial & Industrial
Weather-Normalized Load Year-over-Year
Key Economic Indicators
Weather-Normalized Load
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)
35
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
Residential
Large C&I
Gross Metro Product |
 Illinois Power Agency (IPA)
RFP Procurement
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
36
June 2011
Financial Swap
2010 RFP
2011 RFP
2011 RFP
2011 RFP
2012 RFP
2012 RFP
2012 RFP
2013 RFP
2013 RFP
2014 RFP
Note: Chart is for illustrative purposes only.
REC = Renewable Energy Credit; RFP = request for proposal; ATC = Around the Clock
|
 37
PECO Load Trends
Philadelphia
U.S.
Unemployment rate
(1)
7.9%
9.2%
2011 annualized growth in
gross domestic/metro product
(2)
2.4%
2.7% Note: C&I = Commercial &
Industrial Weather-Normalized Load Year-over-Year
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
February
2011
-
Philadelphia
(2) Source: Global Insight May 2011 |
 38
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)
–
$4.97/MWh
(4)
May 2, 2011
RFP
-
Fifth
in
a
series
of nine
procurements for the PUC-approved
Default Service Plan
Spring
2011
RFP
was
held
on
May
2,
2011,
with
results
announced
on
May
18
th
(1)
See PECO Procurement website (http://www.pecoprocurement.com) for additional details regarding
PECO’s procurement plan and RFP results. (2)
For Large C&I customers who previously opted to participate in the 2011 fixed-priced full
requirements product. (3)
Large C&I tranches which were not fully subscribed in the fall 2010 procurement.
(4)
The price for the hourly full requirements product includes only ancillary services/Alternative Energy
Portfolio Standard (AEPS) and miscellaneous costs. The price does not include energy and
capacity costs. Energy costs will be based on the PECO Zone Day-Ahead locational marginal pricing (LMP) price, and capacity will be based on the
PJM RPM price per day. |
 39
Sufficient Liquidity
($ 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
|
 40
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 41 for reconciliations to GAAP.
(2)
Current senior unsecured ratings for Exelon and Exelon Generation and senior
secured ratings for ComEd and PECO as of July 22, 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) |
 41
Exelon Consolidated Metric Calculations and Ratios
(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)
$ in millions
(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) 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
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 |
 42
2Q GAAP EPS Reconciliation
Three Months Ended June 30, 2011
ExGen
ComEd
PECO
Other
Exelon
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.79
$0.15
$0.13
$(0.01)
$1.05
Mark-to-market impact of economic hedging activities
(0.12)
-
-
-
(0.12)
Unrealized gains related to nuclear decommissioning trust funds
0.01
-
-
-
0.01
Retirement of fossil generating units
(0.02)
-
-
-
(0.02)
Recovery of costs pursuant to distribution rate case order
-
0.03
-
-
0.03
Constellation merger costs
-
-
-
(0.02)
(0.02)
2Q 2011 GAAP Earnings (Loss) Per Share
$0.67
$0.17
$0.13
$(0.03)
$0.93
NOTE: All amounts shown are per Exelon share and represent contributions to
Exelon's EPS. Amounts may not add due to rounding. Three Months Ended
June 30, 2010 ExGen
ComEd
PECO
Other
Exelon
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.69
$0.18
$0.15
$(0.02)
$0.99
2007 Illinois electric rate settlement
(0.01)
-
-
-
(0.01)
Mark-to-market impact of economic hedging activities
(0.11)
-
-
-
(0.11)
Unrealized losses related to nuclear decommissioning trust funds
(0.08)
-
-
-
(0.08)
Retirement of fossil generating units
(0.02)
-
-
-
(0.02)
Non-cash remeasurement of income tax uncertainties
0.10
(0.16)
(0.03)
(0.01)
(0.10)
2Q 2010 GAAP Earnings (Loss) Per Share
$0.57
$0.02
$0.11
$(0.03)
$0.67 |
 43
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 |
 44
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 |