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8-K - FORM 8-K - EXELON GENERATION CO LLC | d249992d8k.htm |
Exhibit 99.1
Exelon and Constellation Energy: Merger and Company Update
Edison Electric Institute Financial Conference
November 7-8, 2011 |
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 Exelons
and Constellations respective filings with the Securities and Exchange Commission (SEC),
and available at the SECs website at www.sec.gov, including: (1) Exelons 2010
Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary
Data: Note 18; (2) Exelons Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2011 in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b)
Part 1, Financial Information, ITEM 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 13; (3)
Constellations 2010 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM
7. Managements Discussion and Analysis of Financial Condition and Results of Operations
and (c) ITEM 8. Financial Statements and Supplementary Data: Note 12; and (4) Constellations 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.
Managements 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 definitive joint proxy statement/prospectus included in
the Registration Statement on Form S-4 that Exelon filed with the SEC and that the SEC
declared effective on October 11, 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 In
connection with the proposed merger between Exelon and Constellation, Exelon filed with the SEC a Registration Statement on
Form S-4 that included the definitive joint proxy statement/prospectus. The Registration Statement
was declared effective by the SEC on October 11, 2011. Exelon and Constellation mailed the
definitive joint proxy statement/prospectus to their respective security holders on or about
October 12, 2011. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE DEFINITIVE JOINT PROXY
STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, BECAUSE THEY CONTAIN
IMPORTANT INFORMATION about Exelon, Constellation and the proposed merger. Investors and security holders may
obtain copies of all documents filed with the SEC free of charge at the SEC's website, www.sec.gov. In
addition, a copy of the definitive joint proxy statement/prospectus 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.
|
4
Compelling Merger Rationale
Creates the leading competitive energy
provider in the U.S.
Matches Exelons clean generation fleet
with Constellations customer-facing
leading retail and wholesale platform
Creates economies of scale through
expansion across the value chain
Strategic Benefits
Financial Benefits
Diversifies generation portfolio across
regions
Adds clean generation to the portfolio
Enhances margins in the competitive
portfolio
Competitive Portfolio
Earnings and cash flow accretive
Dividend uplift for Constellation
shareholders
Continued upside to power market
recovery
Strong balance sheet for combined
company
Utility Benefits
Maintains a regulated earnings profile
with three large urban utilities
Enables operational enhancements
from sharing of best practices across
utilities
Transaction creates incremental strategic and financial value
aligned with both companies
existing goals |
5
Merger Appeals to Key Stakeholders and Governments
(1) Based on the 30-day average Exelon and Constellation closing stock
prices as of April 26, 2011. Stakeholder
Commitments & Benefits
Customers
$100 one
-time credit for BGE residential customers
Direct benefit from merger synergies at the utilities
Opportunities for operational improvements through sharing of
utilities
best practices
$15 million for various programs with direct benefits to BGE
customers
Investors
Upfront premium of 18.5%
(1)
to CEG shareholders
Dividend accretion of 103% post-close for CEG shareholders
EPS accretion of >5% in 2013
Earnings upside to power market recovery
Strong credit profile maintained for combined company
State of Maryland and City
of Baltimore
Maintains a large employee presence and platform for growth
in Maryland
New LEED-certified headquarters for wholesale, retail and
renewable energy development business in Baltimore
BGE to maintain independent operations and remain
headquartered in Baltimore
25 MWs of renewable energy development in MD
$4 million to support EmPower Maryland Energy Efficiency Act
Charitable contributions maintained at current levels for at
least 10 years after the merger closes |
6
Enhanced Maryland Proposal
Our additional commitments address a number of key stakeholder concerns
Intervenor Concerns
Key Exelon/Constellation Additional Commitments
Additional Customer
Benefits
Added flexibility for Maryland PSC to determine use of $15 million offered for
programs directly benefiting BGE customers
Ring-Fencing
No corporate reorganization under certain defined circumstances relating to RF
HoldCo, BGE or Exelon Energy Delivery Company without prior Commission
approval Obtain a new non-consolidation opinion to ensure the
effectiveness of BGE ring- fencing
No requests for modification of BGE ring-fencing for 3 years
Financial
Regular reporting on credit ratings and metrics of BGE to Maryland PSC
Specific commitments regarding the level of BGE capital and O&M expenditures
in 2012 and 2013
Report comparative pre-
and post-merger shared services costs to PSC
Corporate Governance
BGEs CEO will be a member of Exelon Managements Executive
Committee Executive Committee will meet periodically in Baltimore
Service and Operation
Commitment to meet existing BGE supplier diversity requirements
Provide assessment of BGE CAIDI (outage duration) performance within 12 months
after the merger closes
Market Power
In
addition
to
2,648
MW
of
identified
plant
divestitures,
comply
with
settlement
terms
with PJM Market Monitor restricting buyers of divested plants and imposing other
behavioral commitments |
7
Strong Proposal to Address Market Power
The companies have offered a comprehensive, robust mitigation package
C.P. Crane
399 MW
Brandon Shores
1,273 MW
H.A. Wagner
976 MW
Note:
Assets
to
be
divested
Brandon
Shores
(Coal),
H.A.
Wagner
(Coal/Oil/Gas)
and
C.P.
Crane
(Oil/Coal).
Analyzed market power considerations and proposed
mitigation plan to address market concentration
concerns
Proposed comprehensive mitigation plan to address
market concentration in PJM in initial application,
including:
Physical sale of 3 baseload generation facilities
totaling 2,648 MW
Additional sale of 500 MW via contracts to
mitigate temporary market power issues
Filed with FERC and Maryland PSC on October 11,
2011
No change to assets identified in original proposal
Additional commitment not to sell plants to certain
identified PJM generators
Additional assurances on how we will bid units in PJM
energy and capacity markets
Future retirement of units will be conditioned on meeting
specified requirements
Proactive
divestiture
proposal
Settlement with
PJM
Independent
Market Monitor
(IMM) |
8
Note: Data as of 9/30/11. Exelon solar addition MW based on alternating
current (AC); Constellation solar additions (in MW) based on direct current
(DC). (1) Generation capacity net of physical market
mitigation assumed to be 2,648 MW consisting of Brandon Shores (1,273 MW), H.A. Wagner
(976 MW) and C.P. Crane (399 MW).
(2) Electric load includes all booked 2011E competitive retail
and wholesale sales, including index products. Exelon load does not include the
ComEd swap (~26 TWh). Gas load includes all booked and forecasted 2011E competitive
retail sales as of 9/30/11. Reserves (gas)
266 bcf
Owned Generating
Capacity
35 GWs
(1)
Electric
Transmission
7,350 miles
Electric & Gas Dist.
6.6 million
customers
Retail &
Wholesale Volumes
(2)
(Electric & Gas)
~167 TWh, 372 bcf
Notable Generation Acquired or
Under Development in 2011
Exelon Additions
720 MW Wolf Hollow CCGT (TX)
230 MW Antelope Valley Solar Ranch
One (CA)
230 MW Michigan Wind Projects (MI)
Constellation Additions
2,950 MW Boston Generating gas
fleet
30.4 MW Sacramento Municipal Utility
District Solar (CA)
16.1 MW Maryland Generating Clean
Horizons Solar (MD)
7.8 MW Vineland Municipal Electric
Utility Solar (NJ)
5.4 MW Toys R
Us Solar (NJ)
5.2 MW Johnson Matthey, West
Deptford Solar (NJ)
5.0 MW U.S. State Department Solar
(NJ)
Transaction creates the largest
and growing
competitive energy
company in the U.S.
Scale, Scope and Flexibility Across the
Value Chain
Upstream
Downstream |
Well Positioned
for Evolving Regulatory Requirements (1)
Total owned generation capacity as of 9/30/2011 for Exelon and Constellation, net
of physical market mitigation assumed to be 2,648 MW.
(2)
Coal capacity shown above includes Eddystone 2 (309 MW) to be retired on
6/1/2012. (3)
Oil capacity shown above includes Cromby 2 (201 MW) to be retired on
12/31/2011. (4)
Pending approval of owner group.
A clean and diverse portfolio that is well positioned for environmental
upside from EPA regulations
9
Total Generation Capacity
(1)
: 35,327 MW
5%
Wind/Solar/Other
3%
Gas
Hydro
Oil
(3)
Nuclear
54%
6%
Coal
(2)
5%
Cleanest large merchant generation
portfolio in the nation
Less than 5% of combined generation
capacity will require capital expenditures
to comply with Air Toxic rules
-
Approx. $200 million of CapEx, majority of
which is at Conemaugh
(4)
(Exelon and
Constellation ownership share ~31%)
Low-cost generation capacity provides
unparalleled leverage to rising commodity
prices
Incremental 500 MW
of coal and oil
capacity to be retired by middle of next
year
Combined Company Portfolio
27% |
10
Texas Generation Portfolio Is Well Suited to Serve Load
ERCOT Generation
Capacity
MW
(1)
5,311
CEG Intermediate
1,839
EXC Intermediate
2,210
Exelon Peaking
1,262
(1)
Generation and capacity for Exelon and Constellation includes owned and contracted
units, less any PPAs or tolls sold, as of 09/30/2011.
Exelon
wind
assets
in
Texas
(open
or
hedged)
are
not
included
in
the
capacity
shown
above.
Constellation
capacity
includes 517 MWs under a contract that expires in December 2011.
The combined generation portfolio will enhance the hedging capability for
managing load positions in Texas
Premium
Location
A
sizeable
generation
Hedging
Flexibility
Leverage
strong
asset
Strong
Asset
Mix
Intermediate
and
peaking
base and utilize market-based hedging
instruments to effectively manage load-
following obligations
position close to large load pockets in Dallas
and Houston
generation assets are effectively call options at
various heat rates that benefit from price
volatility |
11
We will continue to use a well-defined hedging strategy to carefully
balance risk management and value creation
Increase the amount of generation
hedged over time, leaving some open
generation length
Exhibit flexibility in timing and type of
sales executed based on market
expectations
Select products and markets that
optimize the value of the generation
portfolio
Integrate hedging policy with financial
planning process to protect investment-
grade credit rating
Wholesale and Retail Businesses
Grow our generation to load strategy in multiple regions of the country by
identifying attractive investments and markets
Expand product offerings to customers in regions we serve
Growing the Portfolio
Growing the Portfolio
Hedging Program Characteristics
Hedging Program Characteristics |
Transaction
Maintains Solid Financial Position Achievable Synergies
Annual
run rate
BGE
8%
ComEd & PECO
29%
Unregulated
Businesses
63%
Year 4
$310
Year 3
Year 2
Year 1
$200
Annual O&M Expense Savings
(1)
(in $MM)
12
Lower Liquidity Requirements
Existing liquidity
(ex-utilities)
Pro-forma liquidity
$10.3
Reduction in
existing liquidity
(in $B)
5-Year
Total
Synergies
Allocation
(2)
Maintaining
Strong
Investment
Grade
Ratings
(3)
Moodys Credit
Ratings
S&P Credit
Ratings
Fitch Credit
Ratings
Exelon
Baa1
BBB-
BBB+
ComEd
Baa1
A-
BBB+
PECO
A1
A-
A
Generation
A3
BBB
BBB+
Constellation
Baa3
BBB-
BBB-
BGE
Baa2
BBB+
BBB+
$3-$4
-39%
$6.3
-
$7.3
Pro-Forma
$6.1
Exelon
$4.2
Constellation
Annual cost
savings of
$35M-$45M
(1)
Before total costs to achieve of ~$650M primarily attributable to employee-related costs and
transaction costs. (2)
Source: DeGregorio testimony filed with Maryland PSC on May 25, 2011.
(3)
Ratings as of November 1, 2011. Represents senior unsecured ratings of Exelon, Generation,
Constellation and BGE and senior secured ratings for ComEd and PECO. S&P and Fitch
affirmed all Exelon ratings upon announcement of merger. Moodys affirmed the ratings of ComEd and PECO and
placed the ratings of Exelon and Generation on review for downgrade. S&P and Moodys placed
Constellation on credit watch positive and affirmed BGE ratings. Fitch affirmed
Constellation and BGE ratings upon announcement. |
13
Phased Approach to Designing the Future
Our past experience with successful integration and our phased
approach to integrating Exelon and Constellation will enable the
realization of merger benefits
Success is defined by:
Closing the transaction in early 2012
Maintaining consistent and reliable operations
Capturing value and meeting synergy targets
Meeting commitments to stakeholders, regulators and governments
Acting as one to build an integrated enterprise that is positioned for
continued growth
August
December
Begins post-close
Completed in August
Begins in November |
Exelon
& Constellation Energy Appendix |
15
Merger Approvals Process on Schedule
(as of 11/1/11)
Note: The Department of Public Utilities in Massachusetts concluded on September
26, 2011 that it does not have jurisdiction over the merger.
Stakeholder
Status of Key Milestones
Approved
Texas PUC
(Case No. 39413)
Filed for approval with the Public Utility Commission of Texas on May 17,
2011
Approval received on August 3, 2011
Securities and Exchange Commission
(SEC)
(File No. 333-175162)
Joint proxy statement declared effective on October 11, 2011
Shareholder Approval
Proxies mailed to shareholders of record at October 7, 2011
Shareholder meetings set for November 17, 2011
New York PSC
(Case No. 11E0245)
Filed with the New York Public Service Commission on May 17, 2011
seeking a declaratory order confirming that a Commission review is not
required
Decision expected in Q4 2011
Department of Justice (DOJ)
antitrust laws and certified compliance with second request
Clearance 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
Settlement agreement filed with PJM Market Monitor on October 11, 2011
Order expected by November 16, 2011 (end of statutory period)
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
Order expected by January 2012
Maryland PSC
(Case No. 9271)
Filed for approval with the Maryland Public Service Commission on May 25,
2011
Evidentiary hearings begin October 31, 2011
Order expected by January 5, 2012
Submitted Hart-Scott-Rodino filing on
May 31, 2011 for review under U.S.
assesses market power-related issues |
16
Maryland PSC Review Schedule (Case No. 9271)
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 18, 2011
Public Comment Hearings
November 29, December 1 &
December 5, 2011
Filing of Initial Briefs
December 5, 2011
Filing of Reply Briefs
December 19, 2011
Decision Deadline
January 5, 2012
* Initial
intervenor
testimony
with
respect
to
market
power
was
due
on
September
23
for
all
parties
except
for
the
Independent
Market
Monitor
and
rebuttal
testimony
with
respect
to
market
power
was
due
on
October
17 .
rd
th |
Portfolio
Matches Generation with Load in Key Competitive Markets
MISO (TWh)
PJM
(1)
(TWh)
South
(2)
(TWh)
ISO-NE & NY ISO
(3)
(TWh)
West
(4)
(TWh)
The combination establishes an industry-leading platform with regional
diversification of the generation fleet and customer-facing load business
Note: Data for Exelon and Constellation represents available expected generation
(owned and contracted) and booked electric sales for 2011 as of 9/30/11. Expected
generation is adjusted for assets that have long term PPAs sold by Exelon or
Constellation, including but not limited to wind and South assets. Exelon load doesnt include
the ComEd swap (~26 TWh). Index load, which is a pass through load product with no
price or volumetric risk to the seller, is not included in the load estimate.
(1)
Constellation
generation
includes
output
from
Brandon
Shores,
C.P.
Crane
and
H.A.
Wagner
(total
generation
~8.5
TWh).
(2)
Represents load and generation in ERCOT, SERC and SPP.
(3)
Constellation load includes ~0.7 TWh of load served in Ontario.
(4)
Constellation generation includes ~0.4 TWh of generation in Alberta.
Load
75.1
42.0
33.1
Generation
175.6
29.8
145.8
Constellation
Exelon
5.7
Load
5.1
0.6
Generation
8.6
8.6
18.5
Load
30.3
Generation
26.2
7.7
1.9
Load
Generation
0.6
Load
29.2
Generation
32.1
32.1
29.2
17 |
Manageable
Debt Maturities Debt
Maturity
Profile
(2012-2020)
EXC
EXC
EXC
Exelon
1,652
1,686
1,589
ExGen
PECO
ComEd
Exelon
BGE
Constellation
~70%
of
2012
2016
debt
maturities
consist
of
regulated
utility
debt
(in $M)
18
Weighted Average Cost of
Debt
(2)
Exelon
5.2%
ComEd
5.4%
PECO
5.5%
ExGen
5.5%
Constellation
6.2%
BGE
6.3%
152
552
74
552
(1)
2020
550
550
2019
602
600
2018
1,342
500
840
2017
1,261
702
516
41
2016
1,117
665
379
2015
260
800
75
2014
500
250
617
70
2013
1,020
300
252
467
2012
1,001
375
450
2
2
2
173
3
2
(1)
Debt maturity schedule and weighted average cost of debt as of 9/30/11. Amounts do not include
fair value swaps at Constellation. BGE debt balances include annual transition bond payments
from 2012 2017. (2)
Weighted average cost of debt excludes any benefits for interest rate swaps. Utilities weighted
average cost of debt includes debt amortization costs. |
19
Exelon Dividend
Exelons Board of Directors approved a contingent stub dividend for Exelon
shareholders of $0.00571/share
per
day
for
Q1
2012
in
anticipation
of
the
merger
close
($0.525/share
for
the
quarter)
Stub dividend declaration ensures that Exelon shareholders continue to receive all
dividends at the current $2.10 per share annualized rate
Pre-
and post-close stub dividends must be declared separately to account for
Constellation shareholders becoming Exelon shareholders at merger
close Assuming
a
February
1,
2012
close
for
illustrative
purposes
only:
$0.525
Current Exelon shareholders will continue to receive a total dividend of
$0.525 per quarter
Record Date
Payment Date
Per Share
Amount
11/15/2011
12/09/2011
Regular Dividend
$0.525
1/31/2012
3/1/2012
Pre-close Stub Dividend
$0.440
2/15/2012
3/09/2012
Post-close Stub Dividend
$0.085
5/15/2012
6/09/2012
Regular Dividend
$0.525
(1)
(1)
(2)
(1)
Assuming a 2/1/2012 merger close; for Exelon shareholders, Q1 2012 dividend will be based on a per
diem rate of $0.00571 ($0.525 divided by 92 days).
(2)
Future dividend, following the stub dividend, is subject to approval by the Board of Directors. |
20
Constellation Dividend
Record Date
Payment Date
Per Share
Amount
12/12/2011
1/03/2012
Regular CEG Dividend
$0.24
1/31/2012
3/1/2012
Pre-close CEG Stub
Dividend
(1)
$0.132
2/15/2012
3/09/2012
Post-close EXC Stub
Dividend
(1)
$0.085
5/15/2012
6/09/2012
Regular
EXC
Dividend
(2)
$0.525
Constellation Energys Board of Directors approved a contingent stub dividend
for Constellation shareholders of $0.00264/share per day for Q1 2012 in
anticipation of merger close Stub dividend declaration ensures that
Constellation shareholders continue to receive their existing quarterly
dividend rate prior to the merger, and benefit from the Exelon annualized dividend rate
($2.10 per share) beginning on the day the merger closes
Pre-
and post-close stub dividends must be declared separately to account for
Constellation shareholders becoming Exelon shareholders at merger
close Constellation shareholders will receive the Exelon dividend rate
upon
merger close
(1)
Assuming a 2/1/2012 merger close, Q1 2012 dividend will be based on a per diem rate of $0.00264 ($0.24
divided by 91 days). Post-close Exelon Q1 2012 stub dividend will be based on a
per diem rate of $0.00571.
(2)
Assuming a 2/1/2012 merger close, Constellation shareholders will start receiving the full quarterly
Exelon dividend of $0.525 per share in Q2 2012. Future dividend, following the stub dividend,
is subject to approval by the Board of Directors.
Assuming
a
February
1,
2012
close
for
illustrative
purposes
only: |
21
Financial and Operating Data |
22
2011 Operating Earnings Guidance
(1)
Earnings guidance for OpCos may not add up to consolidated EPS guidance.
(2)
Refer to slides 29 and 30 for a reconciliation of adjusted (non-GAAP)
operating EPS to GAAP EPS. 2011 operating earnings guidance is
$4.15-$4.30/share (2)
;
2012 guidance for combined company to be provided after merger close
$0.55 -
$0.65
$4.05 -$4.25
$0.55 -
$0.65
$4.15 -
$4.30
$3.00 -
$3.10
$1.12
$0.50 -
$0.60
$0.55 -
$0.65
$2.95 -
$3.10
$0.79
$0.17
$0.16
$0.13
$0.79
$1.05
$0.15
$1.17
$0.90
$0.19
$0.11
HoldCo
ExGen
PECO
ComEd
Q1
Actual
Q2
Actual
Q3
Actual
2011 Prior
Guidance
(1)
2011 Revised
Guidance
(1) |
23
Exelons Commitment to Growth
Organic Growth
Competitive Markets
Renewables
Utility Infrastructure
Nuclear Fleet Expansion via Uprates:
Industry leading, proven and value driven program to add
1,175
1,300 MW to the nations largest nuclear fleet
RiteLine Transmission Project:
First major foray into development of backbone
transmission projects with $1.1 billion investment
Wolf Hollow Acquisition:
Diversify generation technology and expand footprint in
Texas via acquisition of 720 MW combined cycle plant
Merchant Transmission Projects:
Investments to improve transmission infrastructure in
western PJM and MISO to reduce congestion
Wind Development:
Exelon Wind to expand its portfolio to at least 965 MW of
capacity by year end 2012 with operations in eight states
Solar Investment:
Acquisition of Antelope Valley Solar Ranch One (230
MW), one of the largest solar PV projects in the world
PECO Smart Grid:
Investment of $650 million with rate recovery to build out
advanced meter infrastructure network
ComEd System Modernization:
$2.6B of incremental investment over 10 years and
formula rates for distribution
Exelon continues to diversify and grow on a standalone basis with
investments that are earnings and cash flow accretive |
Exelon Capital Expenditures Expectations
325
2012E
5,375
2,125
1,100
1,550
275
2011E
4,275
2,000
1,050
825
150
250
2010
3,325
1,850
850
250
125
250
Base CapEx
Nuclear Fuel
Nuclear Uprates and Solar/Wind
Smart Grid
New Business at Utilities
(1)
Excludes potential capex associated with NRC Post-Fukushima
requirements which have not yet been finalized.
(2)
Nuclear fuel shown at ownership, including Salem.
(3)
Includes capex associated with SB 1652 in 2012.
(4)
Includes transmission growth projects.
$ millions
24
2010
2011E
2012E
Exelon Generation
Base CapEx
(1)
775
850
825
Nuclear Fuel
(2)
850
1,050
1,100
Nuclear Uprates
250
375
450
Solar / Wind
-
450
1,100
Total ExGen
1,875
2,725
3,475
ComEd
Base CapEx
(3)
650
750
975
Smart Grid/Meter
(3)
100
75
250
New Business
(4)
200
200
225
Total ComEd
950
1,025
1,450
PECO
Base CapEx
425
350
300
Smart Grid/Meter
25
75
75
New Business
50
50
50
Total PECO
500
475
425
Corporate
-
50
25
|
25
Investment strategy achieved positive 2011 YTD
returns in a very challenging market environment due
to effectiveness of asset allocations and hedging
strategy:
Diversified asset allocation
Liability hedge
Pension plans are 83% funded as of September 30,
2011
Anticipate no substantial changes to contribution plan
S&P 500
Exelon
Pension
Fund Assets
-8.7%
5.3%
Pension Funds Performance
Exelons pension investment strategy has effectively dampened the
volatility of plan assets and plan funded status
2011 YTD Returns at 9/30/2011
o
Decreased equity investments and
increased investment in fixed income
securities and alternative investments
o
The liability hedge has offset more than
50% of the pension liability increase
caused by lower interest rates |
26
2012 Pension and OPEB Sensitivities
Tables
below
provide
sensitivities
for
Exelons
2012
pension
and
OPEB
expense
and
contributions
(1)
under
various discount rate and S&P 500 asset return scenarios
Pension and OPEB asset returns are driven by overall market performance (S&P
500 is used as a proxy) as well as discount rates
2012 Pension Sensitivity
(2)
Discount Rate on 12/31/11
S&P 500 Returns in Q4 2011
(3)
5%
0%
-5%
Pre-Tax
Expense
(in M)
Contribution
(in M)
Pre-Tax
Expense
(in M)
Contribution
(in M)
Pre-Tax
Expense
(in M)
Contribution
(in M)
4.85%
(4)
$290
$140
$300
$140
$305
$140
+50 bps (5.35%)
$260
$140
$265
$140
$270
$140
-50 bps (4.35%)
$330
$130
$335
$130
$340
$135
2012 OPEB Sensitivity
(2)
Discount Rate on 12/31/11
S&P 500 Returns in Q4 2011
(3)
5%
0%
-5%
Pre-Tax
Expense
(in M)
Contribution
(in M)
Pre-Tax
Expense
(in M)
Contribution
(in M)
Pre-Tax
Expense
(in M)
Contribution
(in M)
4.92%
(4)
$260
$340
$265
$345
$265
$350
+50 bps (5.42%)
$235
$310
$240
$315
$240
$320
-50 bps (4.42%)
$290
$375
$290
$380
$295
$385
(1)
Contributions shown in the table above are based on Exelons current contribution policy. (2) Pension and OPEB expenses assume
25% capitalization rate.
(3)
Final 2011 asset return for pension and OPEB will depend in part on overall equity market returns in
Q4 2011 as proxied by the S&P 500. As of 9/30/11, YTD S&P return was -8.7%.
(4)
Projected 12/31/11 discount rate as of 9/30/11.
Note: Tables above for illustrative purposes and not intended to represent a forecast of future
outcomes. |
27
Exelon Credit Metric Outlook
Credit metrics continue to be very strong at each operating company
Managing 5-year financial plan to ensure each operating company can maintain
strong investment grade credit ratings under a variety of economic scenarios
Expect to be at or above target ranges through 2013, while funding growth
projects and meeting future obligations including dividend, pension and
uprates FFO/Debt Forecast and Target Range
Through 2013, Exelon expects to maintain credit metrics at or above targets
10%
20%
30%
40%
50%
Exelon
PECO
ComEd
2011E
2010A
2009A
FFO / Debt
Target
Range
ComEd:
15-18%
PECO:
15-18%
Generation:
30-35%
(1)
(1)
FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt obligations of Exelon Corp.
Range represents FFO/Debt to maintain current ratings at current business risk.
ExGen/
Corp |
RITE
Line Transmission Project 420
miles
of
765kV
transmission
stretches
from
Northern
Illinois
to
Ohio
border
ComEd/Exelon
investment
~$1.1
billion
no
significant
investment
expected
in
2012
FERC accepted Formula Rate and granted incentives for the project, with a 11.43%
total ROE
100% CWIP and 100% cost recovery if the project is abandoned through no fault of
developers
9.93% base ROE with 150 basis points of incentives
Pursuing PJM RTEP Approval, expect confirmation in 2012 or 2013
Project ensures reliability, enables states to meet RPS standards, and reduces
congestion 28
Note: ETA = Electric Transmission America
RPS = Renewable Portfolio Standards
RTEP = Regional Transmission Expansion Planning
2010
2011
2012
2013
2014
2015
2016
2017
2018
In-Service
Construction
State Local Outreach & Project Siting
Pursue PJM RTEP Approval
PJM Compliance Filing
FERC Order No. 1000
FERC Incentive Filing and Order
Established Definitive Agreement
Between Exelon & ETA
Non-project Specific Event
RTEP Approval expected in 2012 or 2013,
dependent on PJM Planning criteria
Time length depends on:
1. Land negotiations
2. Receipt of State Certifications
Construction can range from 3-5 years depending
on the length of time needed to site the project
Lines can be in-serviced phases |
YTD
GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share
and represent contributions to Exelon's EPS. Amounts may not add due to rounding.
Nine Months Ended September 30, 2010
ExGen
ComEd
PECO
Other
Exelon
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$2.10
$0.55
$0.51
$(0.06)
$3.10
2007 Illinois electric rate settlement
(0.01)
-
-
-
(0.01)
Mark-to-market impact of economic hedging activities
0.25
-
-
-
0.25
Unrealized gains related to nuclear decommissioning trust funds
0.04
-
-
-
0.04
Non-cash charge resulting from health care legislation
(0.04)
(0.02)
(0.02)
(0.02)
(0.10)
Non-cash remeasurement of income tax uncertainties
0.10
(0.16)
(0.03)
(0.01)
(0.10)
Retirement of fossil generating units
(0.05)
-
-
-
(0.05)
Emission allowances impairment
(0.05)
-
-
-
(0.05)
YTD 2010 GAAP Earnings (Loss) Per Share
$2.34
$0.37
$0.46
$(0.09)
$3.08
Nine Months Ended September 30, 2011
ExGen
ComEd
PECO
Other
Exelon
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$2.47
$0.43
$0.47
$(0.03)
$3.34
Mark-to-market impact of economic hedging activities
(0.34)
-
-
-
(0.34)
Unrealized losses related to nuclear decommissioning trust funds
(0.07)
-
-
-
(0.07)
Retirement of fossil generating units
(0.04)
-
-
-
(0.04)
Asset retirement obligation
(0.03)
-
0.00
-
(0.02)
Constellation acquisition costs
(0.00)
(0.00)
(0.00)
(0.03)
(0.04)
AVSR 1 acquisition costs
(0.01)
-
-
-
(0.01)
Non-cash charge resulting from Illinois tax rate change legislation
(0.03)
(0.01)
-
(0.00)
(0.04)
Wolf Hollow acquisition
0.03
-
-
-
0.03
Recovery of costs pursuant to distribution rate case order
-
0.03
-
-
0.03
YTD 2011 GAAP Earnings (Loss) Per Share
$1.99
$0.44
$0.47
$(0.07)
$2.84
29 |
GAAP
to Operating Adjustments Exelons 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 and asset retirement 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 ComEds 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 Exelons acquisition of a wind portfolio (now
known as Exelon Wind) and AVSR 1, and Exelons proposed merger with
Constellation
Non-cash
gain
on
purchase
in
connection
with
the
acquisition
of
Wolf
Hollow,
net
of
acquisition
costs
Non-cash charge remeasurement of income tax uncertainties
Non-cash charge resulting from passage of Federal health care
legislation
Costs associated with the 2007 electric rate settlement agreement
Impairment of certain emission allowances
Other unusual items
Significant changes to GAAP
Operating
earnings
guidance
assumes
normal
weather
for
remainder
of
the
year
30 |
31
Exelon Consolidated Metric Calculations
and Ratios
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
(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 |
32
Environmental |
Exelons Clean Fleet Is a Product of
Long-Term Planning
1999
2007
2008
2009
Exelon 2020
Announced
plan to offset
or displace
more than 15
million metric
tons of
greenhouse
gas emissions
per year by
2020
2011
Exelon has made numerous investment decisions over time to prepare for the
countrys mandated transition to cleaner air, and will invest nearly $5 billion
in cost-efficient, clean energy products from 2010 to 2015
2010
Acquisition
Announced
acquisition of
wind portfolio
with 735 MW
operating and
230 MW under
advanced
development
33
Nuclear
Capacity
Factor
(1)
Nuclear
Operations
Set goal to run
nuclear units
at world-class
operating
levels
89.4%
94.5%
93.9%
93.6%
93.9%
93.4%
1997
48.8%
Coal PPA
Terminated
PPA with
State Line
coal facility
Uprates, Coal/Oil
Retirements &
Keystone
Announced $3.3
billion nuclear uprate
program designed to
add 1,175 -1,300
MW through 2017
Announced
retirements of
Eddystone 1&2 and
Cromby 1&2 coal /oil
units by 2012
Invested more than
$140 million to install
scrubbers at
Keystone coal plant
2003
93.4%
ComEd
Fossil Plants
& Uprates
ComEd
divested
5,645 MW of
fossil
generation
plants
Through
2008, added
~1,100 MW
from nuclear
uprates
AmerGen
Nuclear Units
Purchased
remaining
50% interest
in AmerGens
nuclear units
from British
Energy
Acquisition &
Energy Efficiency
Announced 230
MW acquisition of
AVSR 1 solar
project
Invested more
than $240 million
through mid-2011
on energy
efficiency
programs
(1) Capacity factors in 1997, 1998 and 1999 represents Unicom nuclear units performance, and
2011 data represents performance through 9/30/11 for Exelons nuclear units. |
34
EPA Rulemaking Timeline
Note: For definition of the EPA regulations referred to on this slide, please see
the EPA Terms of Environment (http://www.epa.gov/OCEPAterms/). CSAPR
EPA is committed to rulemaking timeline as mandated under Clean Air Act
Air Toxic Rules
316(b) Rules
Targets reductions in
So
2
and NoX to
downwind states
Compliance standards
can be met with a variety
of controls
Modest changes
proposed but no change
in compliance timing
Targets the cooling
water intake structures
Technology decisions
based on site-specific
factors, and cost-benefit
analysis
Implementation of
cooling towers not
mandated
Targets mercury and
other toxic air pollutants
Rules provide certainty
to industry
3-year implementation
period provides
adequate time to invest
in required technology
2010
2011
2012
2015
2016
Draft CSAPR
issued
Draft Air
Toxic rules
issued
Final
CSAPR
Issued
Final Air
Toxic Rules
Expected
Compliance
with CSAPR
Compliance
with Air
Toxics Rule
Phase in of
Compliance with
316(b) Rules
Draft 316(b)
rules issued |
Myths
& Facts about EPA Clean Air Rules Topic
Myth
Fact
Supporting Facts
Jobs
Jobs will be lost during the
economic recovery
Between 2010 and 2015, the new
jobs created through investments
spurred by the EPA clean air rules
will more than offset any job
reductions from plant retirements
A June 2011 Economic Policy Institute report concludes
that the Toxics Rule will have a modest positive net
impact on overall employment
Reliability
Plant retirements will lead
to rolling blackouts
Blanket delay of the rules is
the only option to prevent
local reliability issues
Reliability of the electric system
will not be compromised
If and when necessary, state and
federal regulators have tools to
mitigate any issues
PJM August 2011 report finds that resource adequacy
will not be at risk in spite of projected retirements
PJM May 2011 RPM forward capacity auction results
indicate that there will be ample electricity after
proposed EPA rules take effect in 2015
Clean Air Act provides an opportunity for a 1-year
extension to install pollution controls
U.S. Secretary of Energy has authority to order units to
operate on a limited basis in emergency situations
Timeline
The rules are a surprise
and utilities need more time
to plan
Utilities dont have enough
time to install pollution
controls
Companies have known about
these rules for almost decade and
most, including Exelon, have
planned accordingly and invested
billions of dollars
Utilities have installed pollution
controls in less than 3 years
The Hazardous Air Pollutants (HAP) regulations have
been in the pipeline for more than 10 years and about
60% of coal-burning plants have already installed
controls
Most controls like Activated Carbon Injection (ACI) and
Dry Sorbent Injection (DSI), can be installed in 2 years
or less, and companies will have 3 years to complete
installation until the Air Toxic rules take effect in 2015
Control
Technology
Pollution control technology
is not proven
Pollution control technology is
already in use and widely
available
The industry has extensive experience installing and
operating a range of control technologies
Arguments used to recommend blanket delays to implementing
EPA regulations are not supported by facts
35 |
36 |
37
Antelope Valley Solar Ranch One
Transaction Summary
(1) Based on alternating current (AC).
AVSR 1 further diversifies Exelons clean generation portfolio with a unique
entry point into large-scale solar generation with attractive
economics Los
Angeles
Antelope Valley Solar Ranch One (AVSR 1)
230-MW
(1)
solar photovoltaic (PV) facility located in Los Angeles County
o
Technology: FS Series 3 cadmium telluride (CdTe) PV panels; single-
axis tracking system
First portion of plant on line in Oct. 2012; fully operational by end of 2013
AVSR 1 will be one of the largest solar PV projects in the world
Financing
All-in cost of up to $1.36 billion
Up to $646M of a non-recourse loan guaranteed by U.S. Department of
Energys Loan Programs Office
Exelon to invest up to $713M from closing to the end of 2013
funded with cash and short-term debt
Tax benefits from investment tax credit (ITC) and depreciation provide
additional source of cash beginning in 2012
Initial investment recovered by 2015
Power Purchase Agreement (PPA)
25-year PPA with Pacific Gas & Electric generates long-term regulated
cash flow stream
Contract for all output produced by project
Structure
AVSR 1 is a wholly owned indirect subsidiary of Exelon Generation |
-400
-300
-200
-100
0
100
200
300
400
2015E
2014E
2013E
2012E
2011E
$0.03
$0.03
$0.02
2015E
2014E
2013E
Antelope Valley Solar Ranch One
Attractive Economics
Free cash flow accretive beginning in 2013
Cash
outflows
in
2011-2012
during
construction
mitigated
significantly
by
tax
benefits
and
operating cash inflows received as portions of project come online
EBITDA run-rate of ~$75M per year post full commercial operation date
Expect transaction to have minimal impact on credit metrics
EPS Accretion
Net Equity Cash Flows ($ millions)
Equity Payback
Cumulative Equity Cash Flows
Annual Equity Cash Flows
Expect to recover investment by 2015, largely driven by investment tax
credits and other tax benefits
38 |
Exelon Wind Development Strategy
1,115
735
EOY 2012
Position
2012 Additions
140
150
2011 Additions
90
2010
MW Additions
MW by state
735 MW at EOY 2010
Texas
Oregon
10%
Missouri
22%
Minnesota
11%
Michigan
17%
Kansas
Illinois
Idaho
12%
1%
2%
Longer term pipeline of 500 to 1,000 MW of wind projects may be developed or
acquired over the next five years
Several states under consideration, including ID, ND, CA, NM, KS, OK, PA, MN,
MI
Growth strategy post 2013 assumes tax benefits are extended beyond 2012
MI development projects with signed PPAs
Exelons balance sheet strength and ability to monetize tax benefits are
key competitive advantages in the wind development business
Invest in new wind projects that are primarily
hedged via PPAs and meet internal hurdle rates
Focus on geographic diversity to minimize
production risk for the overall portfolio
Growth Plans
$250 million
CapEx
$550 million
CapEx
26%
Near
term
pipeline
(1)
(1) New wind development will depend on ability to sign PPAs and meet internal hurdle rates. 39
|
Wolf
Hollow Acquisition 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
The acquisition of Wolf Hollow strengthens Exelons position in a
valuable Texas market
720 MW Combined Cycle
Natural Gas Plant
Located in Granbury, Texas
(near Dallas)
40 |
41
Growing Clean Generation with Uprates
Station
Base Case
MW
Max Potential
MW
MW Online
to Date
Year of Full
Operation
by Unit
MW Recovery & Component Upgrades:
Quad Cities
97
104
99
2011 / 2010
Dresden
3
3
2013 / 2012
Peach Bottom
25
32
2011 / 2012
Dresden
103
110
19
2012 / 2013
Limerick
4
4
2012 / 2013
Peach Bottom
2
2
2014 / 2015
MUR:
LaSalle
35
39
39
2011 / 2011
Limerick
33
41
30
2011 / 2011
Braidwood
34
42
2012 / 2012
Byron
34
42
2012 / 2012
Quad Cities
21
23
2014 / 2014
Dresden
28
31
2014 / 2015
TMI
12
15
2014
EPU:
Clinton
2
2
2
2010
Peach Bottom
134
148
2015 / 2016
LaSalle
303
336
2016 / 2015
Limerick
306
340
2016 / 2017
Total
1,176
1,314
189
(1)
In 2011 dollars. Overnight costs do not include financing costs or cost
escalation.
Est. IRR
Overnight
Cost
(1)
Approval
Process
Project
Duration
Megawatt
Recovery &
Component
Upgrades
12-14%
$790 M
Not required
3-4
Years
MUR
(Measurement
Uncertainty
Recapture)
13-16%
$330 M
Straight
forward
approval
process
2-3
Years
EPU
(Extended
Power Uprate)
10-14%
$2,155 M
Straight
forward
approval
process
3-6
Years
Executing uprate projects across our
geographically diverse nuclear fleet, and
expect to add 99 MW in 2011
Nuclear Uprate Program Summary |
Exelons Uprate Program Is a Pragmatic
Approach to Nuclear Growth
42
Key Considerations
Exelon Uprate Program
New Merchant Nuclear
(2)
Overnight cost
(1)
$2,500
$2,800 / KW
$4,500
$6,000 / KW
Time to market
2
6 years
At least 9 years
O&M cost
No additional O&M cost
$10
$15 / MWh
Ancillary costs
NDT, maintenance
capital, etc
Minimal ancillary costs
$ 2
$3 / MWh
Asset diversification
Operational risk spread amongst
several assets
Operational risk concentrated to single
asset
Market diversification
Diversify revenue source amongst
several power markets/ regions
Market risk concentrated to one
location
Market timing risk
Lower risk due to phased execution
Risk of hitting low commodity cycle
Regulatory approval
1
2 years review period
3-year minimum review period
Financing Source
Leverage balance sheet strength
Loan guarantees needed
Development flexibility
Ability to respond to changing market /
financial conditions
Much less flexibility to cancel
(1)
In 2011 dollars. Overnight costs do not include financing costs or cost
escalation. (2)
Cost estimates are based on Exelons internal projections for new merchant
nuclear. Exelons
uprate
program
is
a
proven
approach
to
add
clean
generation
to
the
portfolio,
and it provides flexibility to respond to changing economic and market
conditions |
43
Nuclear Fuel and Outage Management
(1)
Exelon
data
includes
Salem.
The
2009
average
includes
23
days
of
TMI
outage
that
extended
into
2010
for
a
steam
generator
replacement.
Effectively Managing Nuclear Fuel Spend
Note:
At
100%,
excluding
Salem.
Excludes
costs
reimbursed
under
the
settlement
agreement
with
the
DOE.
Industry Leading Refueling Outage Duration
(1)
All Exelon owned units are on a 24-month
refueling cycle except for Braidwood, Byron and
Salem, which are on 18-month cycles
12 planned refueling outages (six in Spring and
six in Fall) in 2011, including two at Salem
10 planned refueling outages (four in Spring and
six in Fall) in 2012, including one at Salem
0
200
400
600
800
1,000
1,200
1,400
1,200
1,100
2012E
1,025
2015E
2014E
2016E
2013E
1,375
1,275
Nuclear Fuel Capex
Nuclear Fuel Expense (Amortization + Spent Fuel)
0
5
10
15
20
25
30
35
40
45
50
55
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
Industry (w/o Exelon)
Exelon
Exelon Nuclears uranium demand is 100%
physically hedged through 2015
Nuclear fuel expenditures are capitalized in the
period of investment
Capitalized nuclear fuel is amortized to expense
over three refueling outage cycles |
Exelons actions are aligned with coordination that is taking place across the
U.S. nuclear industry Exelon
agrees
with
the
Commissions
recognition
of
the
need
for
performance-based,
flexible
approaches
to
address
site-
-
specific circumstances
Other Staff Recommendations:
Implement
other
tier
1
recommendations
from
2013
2016
Post Fukushima: NRC Staff Review
Process and Anticipated Implications
Recommendation
Anticipated Impact on Exelon
Exelon Actions
Protect back up
equipment from external
events
and
provide equipment for
multi-unit events (B5b)
2011:
Obtain additional back up equipment to establish multi-unit
capability at dual unit sites and perform evaluations of back up
equipment storage locations at all sites to minimize vulnerability to
external events
2012:
Participate in stakeholder process on equipment and
reasonable protection
requirements
Spent Fuel Pool (SFP)
instruments
In or beyond 2012:
Design and install
SFP instrumentation
2011:
Conducting preliminary evaluation of available technology
2012:
Participate in stakeholder process to define requirements.
Potentially
begin
conceptual
design
and/or
installation,
in
line
with
the
schedule to be indentified by the NRC
Reliable hardened vents
for Mark I and II
containment
Beyond 2012:
Evaluate reliability of
existing Mark I hardened vents
(1)
Design and install new Mark II hardened
vents as required in final order
2011:
Evaluate whether procedures or staging can be updated to
improve ease of using hardened containment vents within current
plant configurations
2012:
Participate in developing stakeholder process on hardened
vent criteria and begin conceptual design
Improve station blackout
coping time
2014 and beyond:
Begin implementing
requirements of rule
2011:
Analyzing current extended station blackout capability and
developing actions to improve capability
2012-2013:
Participate in stakeholder process on coping time
requirements
Key
Tier
1
Staff
Recommendations
Exelon expects the costs to comply with NRC recommendations to be manageable
(1)
All Exelon units with Mark I containment have hardened vents.
44
In or beyond 2012:
Develop plans for
reasonably protecting back up equipment
and evaluate new regulatory requirements
to determine whether additional backup or
upgraded equipment is required |
45
Exelon Nuclear Fleet Overview
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
(Unit 1 and 2)
PWR
Concrete/Steel Lined
Kankakee River
Expect to file application in
2013/ 2026, 2027
100%
Dry Cask (Fall 2011)
Byron, IL
(Unit1 and 2)
PWR
Concrete/Steel Lined
Rock River
Expect to file application in
2013/ 2024, 2026
100%
Dry Cask
Clinton, IL
(Unit 1)
BWR
Concrete/Steel Lined / Mark III
Clinton Lake
2026
100%
2018
Dresden, IL
(Unit 2 and 3)
BWR
Steel Vessel / Mark I
Kankakee River
Renewed / 2029, 2031
100%
Dry Cask
LaSalle, IL
(Unit 1 and 2)
BWR
Concrete/Steel Lined / Mark II
Illinois River
2022, 2023
100%
Dry Cask
Quad Cities, IL
(Unit 1 and 2)
BWR
Steel Vessel / Mark I
Mississippi River
Renewed / 2032
75% Exelon, 25%
Mid-American
Holdings
Dry Cask
Limerick, PA
(Units 1 and 2)
BWR
Concrete/Steel Lined / Mark II
Schuylkill River
Filed application in June
2011 (decision expected in
2013) / 2024, 2029
100%
Dry Cask
Oyster Creek, NJ
(Unit 1)
BWR
Steel Vessel / Mark I
Barnegat Bay
Renewed / 2029
(3)
100%
Dry Cask
Peach Bottom, PA
(Units 2 and 3)
BWR
Steel Vessel / Mark I
Susquehanna River
Renewed / 2033, 2034
50% Exelon, 50%
PSEG
Dry Cask
TMI, PA
(Unit 1)
PWR
Concrete/Steel Lined
Susquehanna River
Renewed / 2034
100%
2023
Salem, NJ
(Units 1 and 2)
PWR
Concrete/Steel Lined
Delaware River
Renewed / 2036, 2040
42.6% Exelon, 57.4%
PSEG
Dry Cask
(1)
Operating license renewal process takes approximately 4-5 years from
commencement until completion of NRC review. (2)
The date for loss of full core reserve identifies when the on-site storage pool
will no longer have sufficient space to receive a full complement of fuel from the reactor core. Dry cask
storage
will
be
in
operation
at
those
sites
prior
to
losing
full
core
discharge
capacity
in
their
on-site
storage
pools.
(3)
On December 8, 2010, Exelon announced that 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 |
46
Flexible Hedging Program and Diverse
Sales Mix Enhance Portfolio Value
(1) Reflects owned and contracted generation (in MW) as of 9/30/2011.
Excludes PPA with Tenaska Georgia Partners. (2) Data as of 9/30/2011.
Utility procurements includes Full Requirements, Block Energy and Power Sales Agreements.
2012-2014
Sales
as
a
Percentage
of
Expected
Generation
(2)
Current
Owned
&
Contracted
Generation
Capacity
by
Fuel
Type
(1)
43%
Standard Product Sales
27%
Utility Procurements
20%
Retail
4%
Options
5%
Open Generation
PJM East & West
MISO
SPP
Entergy
ERCOT
Multiple
Products
Wholesale
-
OTC, Mid Marketing
and Origination
Retail
-
Multiple
Channels
Multiple
Regions
0
5,000
10,000
15,000
20,000
25,000
30,000
Mid-Atlantic
Midwest
South & West
Total Portfolio
Coal
Gas
Oil
Nuclear
Hydro
Wind/Solar/Other
Standard Products
Full Requirements
Options
Power, Gas
& Heat Rate
Bilateral Transactions
Exelon Energy |
Reliability Pricing Model (RPM)
47
(1)
Weighted average $/MW-Day would apply if all owned generation cleared. Prices
are rounded. Revenues reflect capacity cleared in base and incremental auctions.
NOTE: For definitions of RPM related terms, refer to PJM Manual 18 for capacity
markets at http://pjm.com/documents/manuals.aspx PJM
RPM
Capacity
Prices
and
Revenues
0
20
40
60
80
100
120
140
160
180
200
0
200
400
600
800
1,000
1,200
$99
2012
$133
2013
2014
$95
2011
$148
Exelon fleet weighted average price ($/MW-day)
The Brattle Group assessment of the PJM RPM market
indicates that it has achieved resource adequacy and
reduced costs by fostering competition. The Brattle Group
proposed changes that appear to have some traction
include:
Modify the 2.5% holdback so it increases the amount of
generation and premium DR products that will clear in the
base residual auction
Update the methodology of calculating the E&AS offset used
in Net CONE for a CT to be consistent with actual margins
Increase the slope of the demand curve when supply falls
below reserve margin
AEP Ohio and Duke Ohio are expected to move their
capacity assets and load from their FRR plan into RPM
NJ and MD have both issued RFPs for new CCGTs to
be built in their states, which could possibly be bid into
the 15/16 BRA. Currently, these CCGT projects will be
subject to MOPR when bidding into the capacity auction
PJM reports for PY 14/15 indicate that elevated bidding
most likely reflected environmental compliance costs
and highlight the benefits of Exelons regionally
balanced portfolio
Exelon
benefits
from
a
balanced
capacity
position
across
PJM
and
has
significant
revenues
locked in via the PJM capacity market
Revenues ($ millions)
RPM Update
(1) |
48
Exelon Generation Hedging Disclosures
(as of September 30, 2011) |
Important Information
49
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
Generations 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
Generations actual gross margin are based upon highly variable market factors outside of
our control. The information on the following slides is as of September 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. |
50
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
Exelons 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
Portfolio
Optimization
Portfolio
Management
Portfolio Management Over Time
Open Generation
with LT Contracts |
51
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 |
52
2012
2013
2014
Estimated
Open
Gross
Margin
($
millions)
(1)(2)
$5,150
$5,900
$6,550
Reference Prices
(1)
Henry Hub Natural Gas ($/MMBtu)
NI-Hub ATC Energy Price ($/MWh)
PJM-W ATC Energy Price ($/MWh)
ERCOT
North
ATC
Spark
Spread
($/MWh)
(3)
$4.24
$33.69
$45.46
$4.32
$4.80
$36.49
$48.45
$4.69
$5.13
$39.25
$51.47
$5.69
Exelon Generation Open Gross Margin and
Reference Prices
(1)
Based on September 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, $2.50
variable O&M. |
53
2012
2013
2014
Expected Generation
(GWh)
(1)
169,600
166,100
166,100
Midwest
98,300
96,100
95,400
Mid-Atlantic
56,800
56,100
55,800
South & West
14,500
13,900
14,900
Percentage
of
Expected
Generation
Hedged
(2)
85-88%
56-59%
23-26%
Midwest
85-88
56-59
22-25
Mid-Atlantic
88-91
57-60
22-25
South & West
68-71
49-52
38-41
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$41.00
$40.00
$38.00
Mid-Atlantic
$50.00
$50.50
$52.00
South & West
$1.00
$0.00
($1.50)
Generation Profile
(1)
Expected generation represents the amount of energy estimated to be generated or purchased through
owned or contracted for capacity. Expected generation is based upon a simulated dispatch
model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options.
Expected generation assumes 10 refueling outages in 2012 and 2013 and 11 refueling outages in 2014 at
Exelon-operated nuclear plants and Salem. Expected generation assumes capacity
factors of 93.5%, 93.3% and 93.4% in 2012, 2013 and 2014 at Exelon-operated nuclear plants. These estimates of expected generation in 2012, 2013 and 2014
do not represent guidance or a forecast of future results as Exelon has not completed its planning or
optimization processes for those years. (2)
Percent of expected generation hedged is the amount of equivalent sales divided by the expected
generation. Includes all hedging products, such as wholesale and retail sales of power,
options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.
(3)
Effective realized energy price is representative of an all-in hedged price, on a per MWh basis,
at which expected generation has been hedged. It is developed by considering the energy
revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity
revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM
clearing prices including our load obligations. It can be compared with the reference
prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges.
|
54
Gross
Margin
Sensitivities
with
Existing
Hedges
($
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%
2012
$65
$(30)
$70
$(50)
$40
$(35)
+/-
$45
2013
$305
$(265)
$210
$(205)
$145
$(140)
+/-
$50
2014
$610
$(580)
$380
$(375)
$235
$(230)
+/-
$55
Exelon Generation Gross Margin Sensitivities
(with Existing Hedges)
(1)
Based on September 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. |
55
95% case
5% case
$5,500
$6,200
$5,700
$6,900
Exelon
Generation
Gross
Margin
Upside
/
Risk
(with
Existing
Hedges)
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
2012
2013
2014
$8,300
$5,100
(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 , 2013 and 2014 do not represent earnings guidance or a forecast of future
results as Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range
are calibrated to market quotes for power, fuel, load following products, and options as of September
30, 2011. |
56
Midwest
Mid-Atlantic
South & West
Step 1
Start
with
fleetwide
open
gross
margin
$5.15 billion
Step 2
Determine the mark-to-market value
of energy hedges
98,300GWh * 86% *
($41.00/MWh-$33.69MWh)
= $0.62 billion
56,800GWh * 90% *
($50.00/MWh-$45.46MWh)
= $0.24 billion
14,500GWh * 69% *
($1.00/MWh-$4.32MWh)
= $(0.03) 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
2012
Gross
Margin
(with
Existing
Hedges)
$0.62billion + $0.24billion + $(0.03) billion
$5.15 billion
$5.98 billion |
20
25
30
35
40
45
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
9/11
10/11
35
40
45
50
55
60
65
70
75
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
9/11
10/11
4.0
4.5
5.0
5.5
6.0
6.5
7.0
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
9/11
10/11
50
55
60
65
70
75
80
85
90
95
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
9/11
10/11
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 $4.15
2013 $4.68
Rolling 12 months, as of October 28
th
2011. Source: OTC quotes and electronic trading system. Quotes are daily.
Forward NYMEX Coal
2012 $75.38
2013 $78.21
2012 Ni-Hub $40.62
2013 Ni-Hub $42.52
2013 PJM-West $54.51
2012 PJM-West $52.08
2012 Ni-Hub $26.96
2013 Ni-Hub $28.52
2013 PJM-West $40.39
2012 PJM-West $38.98
57 |
4.5
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
9/11
10/11
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
10.8
11.0
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
9/11
10/11
35
40
45
50
55
60
65
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
9/11
10/11
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
10/10
11/10
12/10
1/11
2/11
3/11
4/11
5/11
6/11
7/11
8/11
9/11
10/11
Market Price Snapshot
2013 10.70
2012 11.08
2012 $44.79
2013 $48.82
2012 $4.04
2013 $4.56
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 $13.12
2013 $13.41
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
Rolling 12 months, as of October 28
th
2011. Source: OTC quotes and electronic trading system. Quotes are daily.
58 |
59 |
60
ComEd Load Trends
Weather-Normalized Load YoY Growth
2011E
0.1%
-0.8%
-1.2%
-0.6%
1.0%
2010
2.6%
-0.6%
-1.2%
0.2%
1.8%
GMP
Large C&I
Small C&I
Residential
All Customers
Note: C&I = Commercial & Industrial
(1)
Source for economic data: Global Insight August 2011.
Driver or
Indicator
(1)
2012 Outlook
Gross Metro
Product (GMP)
1.8% growth in GMP, which reflects
slow growth economy
Housing Starts
Chicago housing market is
expected to remain weak with no
meaningful improvement until 2014
as deleveraging
continues to be a
drag on the economy
Manufacturing
2.3% increase in manufacturing
employment
Unemployment
Little improvement expected in
2012 vs. 2011
Energy
Efficiency
Continued expansion of EE
programs with ~1% reduction to
usage
2012 expected to be another transition year as regional indicators point to an
economy that continues to grow slowly
Economic Forecast of Drivers that Influence Load
|
2010
2011E
Long-Term Target
Equity Ratio
~45%
~43%
45 -
50%
(2)
Earned ROE
10.6%
9 -
10%
61
ComEd Rate Case Results and Rate Base
Electric
Distribution
Current Rates
Rates Effective
June 1, 2011
Test Year
2009 pro forma
Rate Base
(1)
$6,549 million
ROE
10.5%
Equity %
47%
Transmission
FERC Formula Rate
Rates Effective
June 1, 2011
Test Year
2010 pro forma
Rate Base
$2,054 million
ROE
11.5%
Equity %
55%
Transmission:
FERC formula rate
adjusted every
year on June 1
Distribution:
formula rate
adjusted every
year on Jan. 2
Rate Base in Rates
End of Year Balance ($ in billions)
Recent Rate Cases
Based on 30-yr. US Treasury
(3)
Note: Amounts may not add due to rounding.
(1)
Amounts include pro forma adjustments. On September 30, 2010, the Illinois
Appellate Court ruled with regard to ComEds 2007 distribution rate case and held that the ICC abused its
discretion in not reducing ComEds rate base to account for an additional 18
months of accumulated depreciation while including pro forma plant additions post-test year through that
period. On May 24, 2011, the ICC issued an order in ComEds 2010 rate case,
following the Courts position on the post-test year accumulated depreciation issue.
(2)
Equity component for distribution rates will be the actual capital structure
adjusted for goodwill. (3)
Earned ROE will reflect the weighted average of 11.5% allowed Transmission ROE and
Distribution ROE resulting from 30-year Treasury plus 580 basis points for each calendar year.
$2.1
$2.1
$1.9
2012E
$8.9
$6.6
2011E
$8.6
$6.5
2010
$8.6
$6.7
Distribution
Transmission |
Illinois Energy Modernization Act
62
Innovative regulatory and legislative strategy will benefit customers, improve the
transparency of the ratemaking process and enable economic development in
Illinois Incremental investment of $2.6B of capital over next 10
years
Incorporates an annual formula rate proceeding, similar
to FERC transmission rate
Includes an annual reconciliation of costs included in
rates with actual costs incurred
Rates go into effect after ICC review (~8 months)
Legislation sunsets in May 2014 if the residential rate
increases by more than an average of 2.5% per year
and terminates on December 31, 2017 without an
extension from the General Assembly
Key
Provisions
of
Legislation
SB
1652
and
HB
3036
(Trailer
Bill)
(1)
Expect to prevent 700,000 service interruptions per year
Put a smart meter in every home and provide extensive
consumer education
Significantly improve meter reading and reduce frequency
and duration of outages
Contribute $10M per year for 5 years to fund customer
assistance programs
Contribute $15M to Science and Energy Innovation Trust
Fund to fund energy innovation
Create 2,000 full-time equivalent jobs at the peak of the
investment cycle
Enhance the economic competitiveness of Illinois; make
the state better positioned to attract businesses and jobs
Benefits to Customers and to Illinois
Timeline of Filings
By November 10, 2011
ComEd makes initial performance-based rate filing based on a 2010 test year
plus 2011 net plant additions
By May 31, 2012
ICC issues order based on its review of the prudence and reasonableness of
costs May 2012
ComEd files rate filing with 2011 test year plus 2012 net plant additions and 2011
reconciliation
January 2, 2013
Adjusted rates take effect after ICC review
Each May and January thereafter
Annual rate filings take place in May; new rates effective in January after ICC
review (1)
All information provided assumes the Trailer Bill is enacted into law in addition
to SB 1652. |
Illinois Energy Modernization Act
Key Impacts
63
ComEd will record a regulatory asset and income statement
adjustments to reflect the implementation of the legislation
regarding amortization of storm costs and the reconciliation
~$50-$60M of 2011 storm costs will be deferred over 5 years
Revenue requirement reconciliation estimated at $20-$30M
which will not be billed to customers until 2013
$15M contribution required to fund the Illinois Science and
Energy Innovation Trust
2011 earnings dependent on final costs, rate base and
Treasury rates
($ in millions)
Years 1-5
Years 6-9
Total
Smart
Meter/Smart
Grid
$850
$450
$1,300
Infrastructure
Upgrades
$1,300
$0
$1,300
Total
$2,150
$450
$2,600
Initial Filing (Nov. 2011): 2010 + 2011 net plant additions:
12-month average of the 30-year US Treasury yield plus
580 basis point risk premium
4.25% (Jan. to Dec. 2010) average Treasury yield
Second Filing (May 2012): 2011 + 2012 plant additions:
12-month average of the 2011 30-year US Treasury yield
plus 580 basis points
2011 reconciliation allowed ROE includes 590 basis point
risk premium
Subsequent Filings (May of each year):
12-month average of the 30-year US Treasury yield plus
580 basis points for both annual rate and reconciliation
filings
ROE can be reduced by up to 30 basis points if performance
metrics are not met
Includes a 50 basis point collar as defined in the legislation
Current IPA procurement process maintained with annual
events procuring one-third of the load over a three-year
period
Legislation allows the IPA to conduct a special event to
procure power covering load through May 2017 if resulting
prices are deemed to be beneficial to full-service customers
Energy contracts, if ultimately procured for ComEd, will be
multi-year with pricing escalating at 2.5% per annum
Note: All information provided assumes the Trailer Bill is enacted into law in
addition to SB 1652. Estimated Capital Expenditures
Financial Statement Impact
ROE
Formula Rate
Illinois Power Agency (IPA) Procurement
~$30-$40M of after-tax earnings impact will be recorded in 2011
|
64 |
65
PECO Load Trends
Note: C&I = Commercial & Industrial
(1)
Source for economic data: Global Insight August 2011.
Weather-Normalized Load YoY Growth
-1.9%
0.5%
0.1%
3.6%
0.7%
2010
2011E
-2.7%
-1.0%
2.3%
-0.5%
0.8%
GMP
Large C&I
Small C&I
Residential
All Customers
Economic Forecast of Drivers that Influence Load
Driver or
Indicator
(1)
2012 Outlook
Gross Metro
Product (GMP)
2012 GMP growth expected to
increase to 2.0% from 0.7%
Employment
2012 Employment growth is
expected to be 1.2%, slightly
below 2011
Manufacturing
Challenged with weakness in
pharmaceutical and oil refinery
sectors, and energy efficiency
initiatives
Households
2012 Household growth expected
to increase to 0.4%, slightly above
2011
Energy
Efficiency
Expected to reduce total 2012
load by ~0.7% per PAPUC filing
Expect weak economic outlook in 2012 to slightly offset energy efficiency
|
66
PECO Positioned for Continued Strong
Financial Performance
Electric
Distribution
(1)
Current Rates
Rates Effective
January 1, 2011
Test Year
2010
Revenue Increase
$225 million
Gas Delivery
(1)
Current Rates
Rates Effective
January 1, 2011
Test Year
2010
Revenue Increase
$20 million
2010A
2011E
Long-Term Target
Equity Ratio
(1)
53%
55%
53%
Earned ROE
11.8%
~13%
Ratemaking ROE
(3)
10%
~11%
Rate Base in Rates
End
of
Year
Balance
($
in
billions)
(2)
Recent Rate Cases
Electric
Transmission
Stated rate; no
recent rate cases
Periodic rate
cases
as needed;
none expected
in 2012
10%
$0.6
$0.6
$0.6
2012E
$5.0
2011E
$4.9
$1.1
2010
$4.8
$1.1
$1.1
$3.1
$3.2
$3.3
Gas Delivery
Electric Transmission
Electric Distribution
10%
(1)
PAPUC approved a joint settlement; no allowed return was specified.
(2)
As determined for ratemaking purposes. Amounts reflect pro forma adjustments that may be made to
determine rate base for rate case filing purposes.
(3)
Reflects an average of electric distribution, transmission and gas. |
67
PECO Procurement
PECO
Procurement
Plan
(1)
Supply Procurement RFPs to Date
Full
Requirements
Average
Price
$/MWh
(2)
Customer
Class
Products
June
2009
Sept
2009
May
2010
Sept
2010
May
2011
Sept
2011
Residential
75% full
requirements
20% block energy
5% energy only
spot
$88.61
$79.96
$69.38
$66.83
-
$76.27
Small
Commercial
(peak demand
<100 kW)
90% full
requirements
10% full
requirements spot
-
$85.43
$72.47
$70.82
-
$77.71
Medium
Commercial
(peak demand
>100 kW but
<= 500 kW)
85% full
requirements
15% full
requirements spot
-
$86.70
$74.59
$70.36
-
$74.13
Large C&I
(peak demand
>500 kW)
Fixed-priced full
requirements
Hourly full
requirements
(3)
-
-
-
Large
Hourly:
$4.83
(3)
Large
Hourly:
$4.97
(3)
-
(1)
See PECO Procurement website (http://www.pecoprocurement.com) for additional
details regarding PECOs procurement plan and RFP results. (2)
Wholesale prices. No Small/Medium Commercial products were procured in the
June 2009 and May 2011 RFP. (3)
Large Hourly price includes only ancillary services supplier-provided
Alternative Energy Portfolio Standard (AEPS) cost and miscellaneous costs. Six
supply procurements completed; three procurements scheduled in 2012 |