Attached files
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| 8-K - FORM 8-K - EXELON GENERATION CO LLC | d8k.htm |
 Barclays Capital CEO Energy-Power Conference
September 15, 2010
William
A.
Von
Hoene,
Jr.,
EVP
Finance
and
Legal
EXHIBIT 99.1 |
 2
Forward-Looking Statements
This presentation includes forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995, that are subject to risks
and uncertainties. The factors that could cause actual results to differ
materially from these forward-looking statements include those discussed
herein as well as those discussed in (1) Exelon’s 2009 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 Second Quarter 2010 Quarterly Report on Form 10-Q 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 12 and (3) other factors discussed in
filings with the Securities and Exchange Commission (SEC) by Exelon
Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon
Generation Company, LLC (Companies). Readers are cautioned not to place
undue reliance on these forward-looking statements, which apply only as of
the date of this presentation. None of the Companies undertakes any obligation to
publicly release any revision to its forward-looking statements to
reflect events or circumstances after the date of this presentation.
|
 3
EPA Regulations –
Market Implications
Leading up to 2012 Compliance
Notes: Reliability Pricing Model (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/). |
 4
EPA Clean Air Standards Will Not Threaten
Electric System Reliability
(1) M.J. Bradley & Associates, LLC and Analysis Group. 2010. Ensuring
a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability.
Proactive steps by EPA, the industry and other agencies will allow orderly plant
retirements without impacting system reliability
M.J. Bradley and Analysis Group report
(1)
in August 2010 concluded industry is
well-positioned to respond to proposed standards
•
System has >100 GWs of excess capacity
•
Regulators
have
tools
to
address
localized
reliability
concerns,
including
appropriate
price signals from capacity markets
•
Industry has proven track record of adding generation capacity and transmission
solutions
New clean air standards will help modernize US power generation
infrastructure •
Proven technologies for controls are commercially available: >50% of coal
units have installed controls demonstrating that compliance costs can be
managed •
Pollution-intensive plant retirements will create room for cleaner, more
efficient generation |
 5
PJM RPM Capacity Prices and Auction ($MW-day)
74.75
134.46
174.29
110.00
143.90
0
500
1,000
1,500
2009/2010
2010/2011
2011/2012
2012/2013
2013/2014
0
100
200
300
PJM RPM Capacity Auction
Note: Data contained on this slide is rounded.
(1)
Weighted average $/MW-Day would apply if all generation cleared in the
highlighted zone. (2)
All
generation
values
are
approximate
and
not
inclusive
of
wholesale
transactions;
All
capacity
values
are
in
installed
capacity
terms
(summer
ratings)
located
in
the
areas.
(3)
Elwood
contract
expires
on
12/31/12
and
Kincaid
contract
expires
on
2/28/13.
(4)
Reflects
decision
in
December
2010
to
permanently
retire
Cromby
Station
and
Eddystone
Units
1&2
as
of
5/31/11.
None
of
these
933
MW
cleared
in
the
2011/2012
or
2012/2013
auctions.
RTO = Regional Transmission Organization; EMAAC =Eastern Mid-Atlantic Area
Council; MAAC = Mid-Atlantic Area Council Capacity by Region Eligible for
2014/15 RPM Base Residual Auction
(2)
7%
42%
51%
RTO
EMACC
MACC
8,700 MW
1,500 MW
10,300 MW
(4)
2013/14 RPM capacity prices result in a $400 million revenue increase to Exelon over
the prior auction; expect 2014/15 auction to result in blended prices at least
as high (3)
Left axis
~$400M
Increase |
 6
John Deere Renewable Wind Acquisition
735 operating MW of clean, renewable
energy, along with 230 MW in advanced
stages of development in Michigan
75% of the operating portfolio is contracted
Purchase price of $860 million plus an
option for $40 million upon commencement
of construction of the development projects
Attractive
economics
-
EPS
and
cash
flow
accretive
Acquisition positions Exelon as a large wind operator,
complementing its world-class nuclear fleet
TX, 26%
MO,
22%
MI, 17%
ID, 12%
MN,
11%
OR,
10%
KS, 2%
IL, 1%
Operating
Assets
–
Geographical
Distribution
Transaction Summary |
 7
PECO –
Electric & Gas Distribution
Rate Case Settlements
Joint settlement filed with the PAPUC on August 31, 2010 for both electric and gas
rate cases
Settlements are subject to administrative law judges review and PAPUC approval by
mid-December 2010
$20 million
(46% of ask)
$225 million
(71% of ask)
Revenue Requirement Increase in
settlement
(1)
R-2010-2161592
R-2010-2161575
Docket #
<10%
(2)
Electric
~8%
2011 Distribution Price Increase as %
of Overall Customer Bill for Residential
customers
Gas
Rate Case Details
(1)
Settlements are “Black box”, meaning no details are provided for allowed
ROE, rate base or capital structure. (2)
Excluding Alternative Energy Portfolio Standards and default service surcharge.
Assumes results from final procurement in September 2010 are the same as May
2010 procurement. Note: Electric and gas rate case filings available on
Pennsylvania Public Utility Commission (PAPUC) website (www.puc.state.pa.us) or www.peco.com/know.
New rates scheduled to go into effect on January 1, 2011
|
 8
ComEd Delivery Rate Case
Alternative Regulation (Alt Reg) Proposal
ComEd submitted an Alt Reg filing on August 31, 2010 proposing to recover the costs
of pre- approved projects outside of the traditional rate case
process •
9-month statutory process
$60 million proposal would create a collaborative framework for increased
investments in the future implementation of ICC-approved Smart Grid
investments Customer benefits include:
•
Assured
savings
to
customers
–
$2
million
on
capped
O&M
costs
for
program
costs
(excluding
CARE)
•
An incentive/penalty mechanism for performance above or under budget
Proposal would allow for accelerated modernization of the distribution system,
increased assistance to low-income households and the purchase of electric
vehicles $30
$15
Man-hole refurbishment and cable replacement
-
$10
Expanded
funding
for
low
income
CARE
programs
(1)
$5
-
Electric Vehicle Fleet Purchase
Capital
O&M
$ millions
(1)
CARE
=
Customers’
Affordable
Reliable
Energy.
Total
CARE
amount
for
two-year
proposal
is
$20
million. |
 9
$2.03
$0.88
$0.96
$1.26
$1.60
$1.60
$1.76
$2.10
$2.10
2002
2003
2004
2005
2006
2007
2008
2009
2010E
Exelon’s Dividend Track Record
Note: Chart represents dividends per share paid by Exelon for 2002-2009 and
expected dividend for 2010, which is subject to Board approval. (1)
Dividend yield as of August 31, 2010. Competitive Integrated Yield average
includes AYE, CEG, EIX, ETR, FE, NEE, PPL, and PEG. Regulated Integrated
Yield average includes AEP, AEE, D, DTE, DUK, PCG, PGN, SO, WEC, and XEL.
Exelon
has
a
proven
track
record
of
maintaining
its
dividend
and
currently
offers one of the highest yields among its peers
Dividend Yield
(1)
Exelon: 5.2%
Competitive Integrateds: 4.5%
Regulated Integrateds: 4.8% |
 10
Exelon Generation Hedging Disclosures
(As disclosed on July 22, 2010) |
 11
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, 2010. 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. |
 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
12 |
 13
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 |
 14
2010
2011
2012
Estimated Open Gross Margin ($ millions)
(1)(2)
$5,700
$5,300
$5,100
Open gross margin assumes all expected generation is
sold at the Reference Prices listed below
Reference Prices
(1)
Henry Hub Natural Gas ($/MMBtu)
NI-Hub ATC Energy Price ($/MWh)
PJM-W ATC Energy Price ($/MWh)
ERCOT
North
ATC
Spark
Spread
($/MWh)
(3)
$4.77
$33.17
$44.76
$1.28
$5.34
$32.63
$45.54
$(0.02)
$5.68
$34.22
$46.86
$0.53
Exelon Generation Open Gross Margin and
Reference Prices
(1)
Based on June 30, 2010 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, $2.50
variable O&M. |
 15
2010
2011
2012
Expected Generation
(GWh)
(1)
167,500
163,000
162,600
Midwest
100,000
98,700
97,500
Mid-Atlantic
58,900
57,000
57,000
South
8,600
7,300
8,100
Percentage of Expected Generation Hedged
(2)
96-99%
86-89%
57-60%
Midwest
96-99
86-89
54-57
Mid-Atlantic
96-99
90-93
59-62
South
97-100
66-69
51-54
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$46.00
$43.50
$44.50
Mid-Atlantic
$36.50
$57.50
$51.00
ERCOT North ATC Spark Spread
$0.00
$(2.00)
$(5.50)
Generation Profile
(1)
Expected generation represents the amount of energy estimated to be generated or purchased through
owned or contracted for capacity. Expected generation is based upon a simulated dispatch
model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products,
and options. Expected generation assumes 10 refueling outages in 2010 and 11 refueling outages
in 2011 and 2012 at Exelon-operated nuclear plants and Salem. Expected generation
assumes capacity factors of 94.1%, 93.2% and 92.9% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected
generation in 2011 and 2012 do not represent guidance or a forecast of future results as Exelon has
not completed its planning or optimization processes for those years. (2)
Percent of expected generation hedged is the amount of equivalent sales divided by the expected
generation. Includes all hedging products, such as wholesale and retail sales of power,
options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.
Current RMR discussions do not impact metrics presented in the hedging disclosure.
(3)
Effective realized energy price is representative of an all-in hedged price, on a per MWh basis,
at which expected generation has been hedged. It is developed by considering the energy
revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium
costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted
at prices other than RPM clearing prices including our load obligations. It can be
compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges.
|
 16
Gross Margin Sensitivities with Existing Hedges ($ 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%
2010
$20
$(15)
$10
$(5)
$5
$ -
+/-
$25
2011
$100
$(90)
$75
$(65)
$30
$(25)
+/-
$45
2012
$260
$(245)
$220
$(210)
$130
$(125)
+/-
$45
Exelon Generation Gross Margin Sensitivities
(with Existing Hedges)
(1)
Based on June 30, 2010 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. |
 17
95% case
5% case
$6,600
$6,400
$5,100
$7,100
$6,500
$6,600
Exelon Generation Gross Margin Upside / Risk
(with Existing Hedges)
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
2010
2011
2012
(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 2011 and 2012 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, 2010.
|
 18
Midwest
Mid-Atlantic
ERCOT
Step 1
Start
with
fleetwide
open
gross
margin
$5.70 billion
Step 2
Determine the mark-to-market value
of energy hedges
100,000GWh * 97% *
($46.00/MWh-$33.17/MWh)
= $1.24 billion
58,900GWh * 97% *
($36.50/MWh-$44.76/MWh)
= $(0.47 billion)
8,600GWh * 98% *
($0.00/MWh-$1.28/MWh)
= $(0.01) billion
Step 3
Estimate
hedged
gross
margin
by
adding open gross margin to mark-to-
market value of energy hedges
Open gross
margin: $5.70 billion
MTM value of energy
hedges: $1.24 billion + $(0.47 billion) + $(0.01) billion
Estimated hedged gross margin:
$6.46 billion
Illustrative Example
of Modeling Exelon Generation 2010 Gross Margin
(with Existing Hedges) |
 19
19
Market Price Snapshot
Forward NYMEX Natural Gas
PJM-West and Ni-Hub On-Peak Forward Prices
PJM-West and Ni-Hub Wrap Forward Prices
2011
$4.64
2012 $5.26
Forward NYMEX Coal
2011
$66.50
2012
$74.59
2011 Ni-Hub $37.43
2012 Ni-Hub
$39.48
2012 PJM-West $49.82
2011 PJM-West
$47.47
2011 Ni-Hub
$24.48
2012 Ni-Hub
$25.97
2012 PJM-West
$36.76
2011 PJM-West
$35.09
35
40
45
50
55
60
65
70
75
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
20
25
30
35
40
45
50
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
50
55
60
65
70
75
80
85
90
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
Rolling
12
months,
as
of
September
8
th
,
2010.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily. |
 20
20
Market Price Snapshot
2012
$9.14
2011
$9.04
2011
$40.93
2012
$46.82
2011
$4.53
2012
$5.13
Houston Ship Channel Natural Gas
Forward Prices
ERCOT North On-Peak Forward Prices
ERCOT North On-Peak v. Houston Ship Channel
Implied Heat Rate
2011
$5.76
2012
$7.34
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
8.0
8.2
8.4
8.6
8.8
9.0
9.2
9.4
9.6
9.8
10.0
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
40
45
50
55
60
65
70
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
Rolling
12
months,
as
of
September
8
th
,
2010.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily. |
  21
Appendix |
 22
John Deere Renewable Acquisition –
Transaction Summary
Components of purchase price
•
$860M for operating assets and advanced-stage Michigan development
projects •
Up to $40M in additional payments contingent on commencement of construction
on Michigan development projects
•
Equivalent to ~$1,000/KW
Financing
•
Exelon will fund transaction with Exelon Generation debt (no equity
issuance) •
Clean
capital
structure
with
no
tax
equity
and
project
debt
(1)
•
Ability to utilize production tax credits
735 MW operating portfolio spread across 36 projects located in eight states
•
75% of the operating portfolio is sold under long-term power purchase
arrangements
•
86% of contracted portfolio has PPAs through 2026 or beyond
1,468 MW in development pipeline
•
PPAs
have
already
been
executed
for
230
MW
in
Michigan
–
projects
expected
to
be operational in 2012-2013
Acquisition positions Exelon as a large wind operator, complementing its
world-class nuclear fleet
(1) Except for $1.8M loan from Illinois Finance Authority for AgriWind project in
IL |
 23
John Deere Renewable Acquisition -
Strategic Rationale
Diversify with additional clean generation
•
JDR’s proven wind platform provides unique opportunity and entry point into
U.S. wind business
•
Provides diversity in geographic presence and generation type
•
Supports
Exelon
2020
by
adding
more
“clean”
generation
to
our
portfolio
and
positions us for potential federal renewable portfolio standard (RPS)
Contracted portfolio with option for future growth
•
75% of operating portfolio sold under long-term PPAs
•
1,468 additional MW in pipeline, of which 230 MW have executed PPAs
•
Only plan further development of contracted assets
Attractive economics and good fit
•
Purchase price compares favorably with other wind transactions
•
Disciplined investment approach aligned with Exelon’s approach
•
Addition of strong renewable energy development team
Acquisition further enhances Exelon’s strong environmental leadership and
provides future opportunities for incremental development
|
  24
John Deere Renewable Acquisition -
Financials Are Attractive
EPS breakeven in 2011, accretive beginning in 2012
•
Assumes transaction is funded with 100% debt
EBITDA
run-rate
of
~$150M/year
including
PTCs
(1)
(including
Michigan
development
projects)
Free cash flow accretive by 2013
•
Includes estimated capex (before tax incentives) of $450-$500M in
2011-2012 for Michigan development projects
Expect transaction to have minimal impact on credit metrics
EPS Accretion / Dilution
0.0%
0.6%
1.5%
2011E
2012E
2013E
(1) Production Tax Credits |
 25
25
John Deere Renewable Acquisition
Asset Profile –
Operating
The portfolio is largely made up of contracted operating assets
Geographic Distribution
TX, 26%
MO,
22%
MI, 17%
ID, 12%
MN,
11%
OR,
10%
KS, 2%
IL, 1%
Note:
There is ongoing litigation with Southwest Public Service related to PURPA
contracts which could impact the price at which the generation
from
these
units
is
sold.
Cracking
issues
experienced
by
Deere
on
certain
Suzlon
turbine
blades
have
been
addressed
to
our
satisfaction.
We
have
factored
both
items
into
our
valuation.
Project State
MW
# of Wind
Projects
Ownership
Placed in
Service
Date
PPA End
Date
Federal
Incentive
Off-Taker
Idaho
88.2
3
100%
2009/2010
2028/2030
ITC Grant
Idaho Power
Illinois
8.4
1
99%
2008
2018
PTC
Wabash Valley Power
Kansas
12.5
1
100%
2010
2030
PTC
Kansas Power Pool
Michigan
121.8
2
100%
2008
2018/2028
PTC
Wolverine Power Supply
/ Consumers Energy
Minnesota
77.7
9
94%-100%
2003/2008
2018/2028
PTC
Various
Missouri
162.5
4
99%-100%
2008
2027
PTC
Associated Electric /
MO Joint Municipal
Oregon
74.5
4
99%-100%
2009
2029
ITC Grant
PacifiCorp
Texas
189.8
12
100%
2006/2009
N/A
PTC
Southwest Public Service
Total
735.4
36 |
 26
26
John Deere Renewable Acquisition
Asset Profile –
Development Pipeline
PPAs already executed for these
projects
Development pipeline includes
wind projects ranging from 20 MW
to 300 MW
Development of projects to be
considered on a case-by-case
basis
State
Project Name
MW
MI
Michigan Wind II
90
MI
Harvest II
59
MI
Blissfield (MW IV)
81
Total
230
Projects to be developed by Exelon
Optional projects for development
Ohio
198
Michigan
40
Idaho
20
Texas
760
Maine
50
Colorado
40
Oregon
30
California
100
Total
1,238
Total
1,468 |
 27
John Deere Renewable Acquisition
Regulatory Approval Process
FERC approval required
DOJ antitrust approval required under the Hart-Scott-Rodino Antitrust
Improvements Act
Other than Texas, no state approval is necessary
Expect to close transaction in fourth quarter of 2010; no material issues
expected |
 28
111.91
148.80
102.04
191.32
174.29
110.00
16.46
133.37
139.73
27.73
226.15
245.00
2008/2009
2009/2010
2010/2011
2011/2012
2012/2013
2013/2014
RTO
MAAC + APS
MAAC
Eastern MAAC
Only shown
if cleared
at separate
price and
generation
is located
in that zone
(1)
PJM RPM Auction Results
Note: Data contained on this slide is rounded.
(1)
MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System.
(2)
All generation values are approximate and not inclusive of wholesale
transactions. (3)
All capacity values are in installed capacity terms (summer ratings) located in the
areas. (4)
Obligation represents the remainder of the ComEd auction load that ends in May
2010. $134.46
1,500
8,700
(7)
10,300
(6)
Capacity
(3)
2013/2014
2009/2010
2010/2011
2011/2012
2012/2013
in MW
Capacity
(3)
Obligation
Capacity
(3)
Obligation
Capacity
(3)
Capacity
(3)
RTO
12,800
3,800 -
4,100
(5)
23,900
9,300 -
9,400
(4)
23,200
12,100
(6)
EMAAC
9,500
MAAC + APS
11,100
9,300 –
9,400
(5)
MAAC
1,500
Avg ($/MW-Day)
(8)
$143.90
$174.29
$110.00
$74.75
PJM RPM Auction ($MW-day)
(5)
Obligation consists of load obligations from PECO. PECO PPA expires December 2010.
(6)
Elwood contract expires on 12/31/12 and Kincaid contract expires on 2/28/13.
(7)
Reflects decision in December 2010 to permanently retire Cromby Station and Eddystone Units
1&2 as of 5/31/11. None of these 933 MW cleared in the 2011/2012 or 2012/2013 auctions.
(8)
Weighted average $/MW-Day would apply if all generation cleared in the highlighted zones.
Exelon Generation Eligible Capacity within PJM Reliability Pricing Model
|
 29
ComEd Delivery Service
Rate Case Filing Summary
$396
Total
($2,337
million
revenue
requirement)
(6)
$45
Other adjustments
(5)
$22
Bad debt costs (resets base level of bad debt to 2009 test year)
$55
Pension
and
Post-retirement
health
care
expenses
(4)
$95
Capital Structure
(3)
: ROE –
11.50% /
Common
Equity
–
47.33%
/
ROR
–
8.99%
$179
(2)
Rate Base: $7,717 million
(1)
Requested Revenue
Increase
($ in millions)
Primary drivers of rate request are new plant investment, pension/retiree
health care and cost of capital
(1)
Filed
June
30,
2010
based
on
2009
test
year,
including
pro
forma
capital
additions
through
June
2011,
and
certain
other
2010
pro
forma adjustments. ICC Docket #: 10-0467,
http://www.icc.illinois.gov/docket/casedetails.aspx?no=10-0467. (2)
Includes increased depreciation expense.
(3)
Requested capital structure does not include goodwill; ICC docket 07-0566
allowed 10.3% ROE, 45.04% equity ratio and 8.36% ROR. ROE includes 0.40%
adder for energy efficiency incentive. (4)
Reflects 2010 expense levels, compared to 2007 expense levels allowed in last rate
case. (5)
Includes reductions to O&M and taxes other than income, offset by wage
increases, normalization of storm costs and the Illinois Electric
Distribution Tax, other O&M increases, and decreases in load.
(6)
Net of Other Revenues.
Note: ROE = Return on Equity, ROR = Return on Rate Base, ICC = Illinois
Commerce Commission. |
 30
3.82
4.73
7.44
7.03
0.73
0.73
0.65
0.60
ComEd Delivery Rate Case
Residential Rate Impacts 2010 to 2011
(1)
(1)
Reflects change in distribution rates only. Assumes Energy, Transmission and
all other components remain constant as of June 2010, except as noted
above. (2)
"All Other" includes impact of riders that are applicable to residential
bills. Unit rates: cents / kWh
All Other
(2)
Transmission
Energy
Distribution
Approximately
4% increase
July 1, 2010
July 1, 2011
Transmission: Subject to FERC
formula rate annual update
Comments
Energy: Reflects reduced PJM capacity
price that PJM has published for the
June
2011
–
May
2012
planning
period. Energy component may vary
Distribution: As proposed
12.63
13.09
Note: Amounts may not add due to rounding.
Proposed residential rate impact of 7% will be mitigated by impact
of lower capacity prices resulting in a net increase of 4%
|
 31
ComEd Delivery Service Rate Case
Schedule
Delivery
Service
Rate
Case
Filed
–
June
30,
2010
Alt
Reg
Proposal
Filed
–
August
31,
2010
Intervenor
and
Rebuttal
Testimony
–
4Q
2010
Hearings –
January 2011
Administrative
Law
Judge
Order
–
March
31,
2011
Final
Order
Expected
–
May
2011
New
Rates
Effective
–
June
2011 |
 32
PECO Procurement
(1)
See PECO Procurement website (http://www.pecoprocurement.com) for additional
details regarding PECO’s procurement plan and RFP results. (2)
Wholesale prices. No Small/Medium Commercial products were procured in the
June 2009 RFP. (3)
For Large C&I customers who have opted to participate in the 2011
fixed-priced full requirements product. Large Commercial and
Industrial Average
price
of
$77.55/MWh
(2)
100%
of
fixed-price
full
requirements
procured
in
May
’10
(3)
Medium Commercial
Sept
’09
/
May
’10
RFP
aggregate
result
$77.89/MWh
(2)
Remaining 42% of full requirements to be procured in Sep ‘10
Residential
June
’09
RFP
average
price
of
$88.61/MWh
(2)
Sept
’09
RFP
average
price
of
$79.96/MWh
(2)
May
‘10
RFP
average
price
of
$69.38/MWh
(2)
Remaining 28% of full requirements to be procured in Sep ‘10
Small Commercial
Sept
’09
/
May
’10
RFP
aggregate
result
$77.65/MWh
(2)
Remaining 40% of full requirements to be procured in Sep ‘10
85% full requirements
15% full requirements
spot
Medium Commercial
(peak demand >100
kW but <= 500 kW)
Fixed-priced full
requirements
(3)
Hourly full requirements
Large Commercial &
Industrial
(peak
demand >500 kW)
90% full requirements
10% full requirements
spot
75% full requirements
20% block energy
5% energy only spot
Products
Small Commercial
(peak demand <100
kW)
Residential
Customer Class
PECO
Procurement
Plan
(1)
2011 Supply Procured
Final RFP for 2011 supply to be held on September 20, 2010;
results will be public 30 days thereafter |
 33
Exelon Investor Relations Contacts
Exelon Investor Relations
10 South Dearborn Street
Chicago, Illinois 60603
312-394-2345
312-394-4082 (Fax)
For copies of other presentations,
annual/quarterly reports, or to be added
to our email distribution list please
contact:
Martha Chavez, Executive Admin
Coordinator
312-394-4069
Martha.Chavez@ExelonCorp.com
Investor Relations Contacts:
Stacie Frank, Vice President
312-394-3094
Stacie.Frank@ExelonCorp.com
Melissa Sherrod, Director
312-394-8351
Melissa.Sherrod@ExelonCorp.com
Paul Mountain, Manager
312-394-2407
Paul.Mountain@ExelonCorp.com
Marybeth Flater, Manager
312-394-8354
Marybeth.Flater@ExelonCorp.com
Sandeep Menon, Principal Analyst
312-394-7279
Sandeep.Menon@ExelonCorp.com |