Attached files
| file | filename |
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| 8-K - FORM 8-K - EXELON GENERATION CO LLC | d8k.htm |
 Credit Suisse 2011 Energy Summit
William A. Von Hoene, Jr., EVP Finance & Legal
February 9, 2011
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
Third 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 13 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. This presentation includes references to adjusted
(non-GAAP) operating earnings and non-GAAP cash flows that exclude
the impact of certain factors. We believe that these adjusted operating
earnings and cash flows are representative of the underlying operational results of
the Companies. Please refer to the appendix to this presentation for a
reconciliation of adjusted (non-GAAP) operating earnings
to
GAAP
earnings.
Please
refer
to
the
footnotes
of
the
following
slides
for
a
reconciliation
non-GAAP cash flows to GAAP cash flows. |
 3
(1)
Refer to 1/26/11 Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(2)
Cash from operations primarily includes net cash flows provided by operating
activities, excludes counterparty collateral and includes net cash from investing activities other than
capital expenditures, acquisition of Exelon Wind (in 2010) and change in restricted
cash. 2011: Expect a Solid Year
EPS guidance of $3.90-$4.20
(1)
Strong cash flow –
expect to
generate cash from operations
of $4.3 billion
(2)
Increasing investment in growth
projects at ExGen and Utilities
Efficient use of cash benefits
from bonus depreciation
Key Financial Messages
2010: Another Strong Year
Financial and operational
performance
•
Operating earnings of
$4.06/share
(1)
•
2010 cash from operations
of $5.3 billion
(2)
•
Returned $1.4 billion in cash
to shareholders through
dividends
•
93.9% capacity factor at
Nuclear
Continuing to position Exelon
for cleaner energy future |
 4
Largest merchant nuclear fleet in the U.S.
Consistent world-class performance in nuclear
operations
Utilities serving two of the largest metropolitan areas
in the U.S.
Stable dividend that has yielded ~5% on average
over the past year
Why Is Exelon a Good Investment?
Commitment to investment grade credit ratings and
financial discipline
Exelon is able to execute from a position of strength based on solid
fundamentals |
 5
Exelon Wind Expenditures
(Advanced Development Projects)
$0
$50
$100
$150
$200
$250
$300
2010A
2011E
2012E
0
50
100
150
200
250
300
Annual Project CapEx
MW Online (Cumulative)
Growing Our Clean Generation
(1) Dollars shown are nominal, reflecting 6% escalation, in millions and
exclude TMI and Clinton extended power uprates, which are currently under review. MW shown at ownership.
Note: PPA = power purchase agreement; MUR = measurement uncertainty recapture; EPU
= extended power uprate. Data contained in this slide is rounded.
$150
$275
$550
$475
$475
$ millions
$50
Exelon is positioned as a key player in the US wind market and has the
largest size and scale for nuclear uprates
$ millions
Wind Development Projects
Nuclear Uprates Program
Highest return projects are being completed
in early years
Leverages Exelon’s substantial experience
managing
successful
uprate
projects
–
1,100
MW completed from 1999 to 2008, 101 MWs
added in 2009-2010
Attractive economics for both operating and
advanced
development
projects
–
PPAs
already executed
Provides diversity in geographic presence
and generation type
$225
$265
$20
Exelon's Uprate
Plan Expenditures
(1)
$0
$100
$200
$300
$400
$500
$600
$700
2008A
2009A
2010A
2011E
2012E
2013E
0
100
200
300
400
500
Megawatt Recovery
MUR
EPU
MW Online (Cumulative) |
 6
6
Moving Generation to Market
110,594
142,400
42,003
5,295
13,897
26,300
0
50,000
100,000
150,000
200,000
2010
2011E
ComEd Swap
IL Auction
PECO Load
Actual Forward Hedges & Open Position
171,789
168,700
(1) Represents values as of December 31, 2010.
Transition to market at PECO provides additional channels to market for
Exelon Generation, including opportunities at Exelon Energy
Exelon Energy Electric Volumes
-
5
10
15
20
25
30
2008
2009
2010
2011E
2012E
2013E
MWh - Millions
COMED / Ameren
PECO/PPL
Other
Expected
Total
Sales
(GWh)
(1)
2011-2013 Sales as % of
Expected Generation
(1)
Exelon
Energy
6%
Standard
Product Sales
29%
Open
Generation
36%
Options
5%
Utility
Procurements
24% |
 7
7
Pursuing Transmission Investment
Moving forward on project planning
with partner ETA
Total Investment ~$1.6 billion
ComEd/Exelon ~$1.1 billion
FERC incentive rate joint filing
expected late 1Q or early 2Q 2011
Exelon companies are investing in projects that ensure reliability and support
further clean energy development
Note: Electric Transmission America (ETA) is an American Electric Power &
MidAmerican Energy Holdings joint venture company. RITE Line
Ensures reliable service to the
Chicago central business district
Estimated cost of ~$170 million
recoverable under ComEd’s FERC
formula rate
Expected in-service December 2011
West Loop Phase II |
 8
Driving Financial Discipline
Going to market to refinance 2012 maturities in the first half of this year
(in millions)
Generation
PECO
Corporate
ComEd
Total
Unsecured Revolving Credit
Facilities
(4)
$4,834
$574
$957
$1,000
$7,365
Expiration date
Oct 2012
Oct 2012
Oct 2012
March 2013
Maintaining a strong balance sheet and liquidity position
$2.1B Pension Contribution in 2011
Credit Facilities
Continued Strong Balance Sheet
FFO / Debt
(1)(2)
Pension Contributions
615
2,100
765
110
175
160
195
780
790
170
485
2010
2011
2012
2013
2014
2015
With $2.1B
Original Plan*
($ millions)
*
Original
Plan
reflects
preliminary
2010
underlying
assumptions
(including
discount rate and asset returns).
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
2009A
2010A
2011E
2012E
2013E
ExGen/Corp
ComEd
PECO
(3)
S&P Target Range
S&P Target Range
(1)
Reflects FFO / Debt as calculated by S&P.
(2)
Dashed lines represent S&P Target Ranges (30-35% for ExGen/Corp and 15-18% for ComEd and
PECO). See slide 24 for reconciliations to GAAP. (3)
FFO/Debt Target Range reflects ExGen FFO/Debt in addition to the debt obligations of Exelon
Corp. (4)
Excludes $94 million of credit facility agreements arranged with minority and community banks on
10/22/10 that are utilized solely to issue letters of credit. |
 9
9
Factors Influencing PJM RPM Capacity Auction
(Comparison of PY 14/15 and PY 13/14 Price Drivers)
Exelon
Price Impact
Cost of Environmental Upgrades
(1)
Higher Net CONE
(2)
Higher Net ACRs
For Coal Units
(3)
Import Transmission Limits And Objectives
(muted impact on portfolio revenues due to regional diversification)
NJ CCGT Proposal / PJM Minimum Offer Price Rules
Peak Load
(4)
Demand Response Growth
2014/15 PJM Capacity Auction: Expected
Changes Since Planning Year 2013/14
Exelon’s capacity position, split almost evenly between the west and the east,
dampens the volatility to portfolio revenues from changes to transmission
limits while retaining upside across the fleet from upcoming EPA
regulations (1) We expect generators to reflect cost of capital
expenditures into their cost based offers at the upcoming auction. (2)
Cost
of
new
entry
(CONE)
increased
by
7.6%
(for
RTO)
and
5.3%
to
6.5%
(within
Locational
Deliverability
Areas
(LDAs)).
(3) Replacing
2007
net
revenues
with
significantly
lower
2010
revenues
in
the
Net
ACR
(avoidable
cost
rate)
calculations
for
coal
generators
may
increase
offer
caps
for
certain coal generators in the next auction. However, some coal units may not be
affecteddue to high net revenues compared to avoidable costs. (4) Peak
load reduced by approx. 1% in RTO (excluding the impact from Duke Ohio integration).
Note: RPM = Reliability Pricing Model; CCGT = combined cycle gas
turbine |
 10
EPA Regulations Will Move Forward in 2011
Note: 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/). |
  11
Q&A |
  12
Appendix |
 13
2011 Events of Interest
Q1
Q2
Q3
Q4
RPM Auction results
(5/13)
Illinois Power Agency
RFP (April)
ALJ Proposed Order
–
DST Rate Case
(3/31)
Procurement RFP
(bids due 5/23;
results by 6/23)
DST Rate Case Final
Order (by 5/31)
EPA Final HAP
Rule (November)
Retirement of Cromby
1 & Eddystone 1 units
(5/31)
Proposed HAP EPA
Regulation (by 3/16)
Procurement RFP
(bids due 9/19;
results by 10/19)
Retirement of
Cromby 2 unit
(12/31)
Proposed 316(b) EPA
Regulation (by 3/14)
For
definition
of
the
EPA
regulations
referred
to
on
this
slide,
please
see
the
EPA’s
Terms
of
Environment
(http://www.epa.gov/OCEPAterms/).
Note: ALJ = administrative law judge; DST = delivery service tariff
EPA Final Transport
Rule (June) |
 14
2011 Operating Earnings Guidance
2011E
(2)
2010A
$0.54
$2.91
$4.06
(1)
ComEd
PECO
Exelon
Generation
ComEd
PECO
Exelon
Generation
Holdco
Holdco
Exelon
$0.68
Exelon
$3.90 -
$4.20
(1)
$0.55 -
$0.65
$0.50 -
$0.55
$2.85 -
$3.05
(1)
Refer to 1/26/11 Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(2)
Earnings guidance for OpCos may not add up to consolidated EPS guidance.
Key
Drivers
of
FY
Guidance
+
Generation margins driven by PECO
PPA roll-off, partially offset by lower
capacity revenues
+
Higher PECO gross margin driven by
new distribution rates effective 1/1/11
-
Higher O&M expense
-
Higher depreciation & amortization
expense
2011
operating
earnings
guidance
of
$3.90
–
$4.20/share
and
1Q
2011
guidance of $1.00 –
$1.10/share
(1) |
 15
$0.98
$0.68
$2.74
$2.91
$1.07
$0.71
2010A
2011E
PECO
ComEd
ExGen
Operating O&M Outlook
2010 to 2011 Drivers (per share)
Inflation $(0.08)
Full year of Exelon Wind $(0.05)
Two additional nuclear refueling
outages $(0.05)
ComEd uncollectibles $(0.04)
Estimated 2011 O&M represents a new “base”
level for operating O&M
$4.39B
$4.68B
2010 Operating O&M below 2008 levels for second consecutive year
One-time savings in 2010 included executive salary freezes and reduced
compensation benefits
Anticipate annual O&M growth rate of ~2% for 2011-2013
(1) Amounts
may
not
add
due
to
rounding.
Refer
to
slide
43
for
a
reconciliation
of
GAAP
O&M
to
Operating
O&M.
(1)
(1) |
 16
Exelon Generation 2011 EPS Contribution
(1)
Estimated contribution to Exelon’s operating earnings guidance.
RNF = revenue net fuel
$ / Share
$0.35
$(0.03)
RNF
O&M
Other
Depreciation &
Amortization
$(0.08)
Key Items:
Inflation
Exelon Wind
Nuclear Outages
2010A
2011E
(1)
$2.85 -
$3.05
$2.91
Key Items:
PECO
PPA
Exelon Wind
Capacity Market Prices
Nuclear Fuel
Market/portfolio conditions
and Exelon Energy
$(0.17)
$(0.03)
Interest
Expense
Note: Drivers add up to mid-point of 2011 EPS range.
$0.62
$0.08
$(0.29)
$(0.09)
$0.07
$(0.05)
$(0.05)
$(0.05) |
 17
ComEd 2011 EPS Contribution
2010A
Depreciation &
Amortization
Interest
Expense
$0.55 -
$0.65
$0.03
$(0.08)
$(0.03)
2011E
(3)
$ / Share
$(0.02)
$0.02
Other
RNF
(1)
O&M
(1)
Key Items:
Weather
Uncollectibles
Appellate Court ruling
Distribution revenue
(2)
Key Items:
Uncollectibles
Inflation
Note: Drivers add up to mid-point of 2011 EPS range.
$0.68
(1)
Excludes estimated impact of Rider EDA (Energy Efficiency and Demand Response Adjustment) of
+/-$0.05/share. 2010 net income includes a one-time benefit for collections of
under-recovered 2008 and 2009 bad debt costs, as provided by the uncollectible expense rider approved by the ICC in February 2010. Going forward,
the rider provides for full recovery of all bad debt costs.
(2)
Distribution rate case currently pending, new rates will be effective in June 2011. Earnings
guidance assumes mid-point of ComEd’s requested revenue increase. (3)
Estimated contribution to Exelon’s operating earnings guidance.
$(0.04)
$(0.02)
$(0.01)
$0.08
$(0.04)
$(0.02) |
 18
PECO 2011 EPS Contribution
$ / Share
RNF
(2)
$(0.03)
$0.54
(1)
CTC,net
2011E
(3)
Key Items:
Electric & Gas
Distribution Rate
$0.19
Weather
$(0.05) Key Items:
Inflation
$(0.01) Bad
Debt $(0.01)
$0.14
O&M
(2)
$0.50 -
$0.55
(1)
$(0.04)
2010A
(1)
Excludes preferred dividends.
(2)
Excludes items that are income statement neutral and estimated impact of energy
efficiency and smart meter costs recoverable under a rider of $0.10/share.
(3)
Estimated contribution to Exelon’s operating earnings guidance.
CTC = competitive transition charge
Note: Drivers add up to mid-point of 2011 EPS range.
$(0.03)
Depreciation
$(0.05)
Income Taxes
Key Items:
Revenue net $(0.06)
of amortization
Interest on PECO
transition bonds $0.02 |
 19
Key Assumptions
38.0
31.1
29.5
PECO
40.8
39.7
37.9
ComEd
37.1
37.5
38.3
Exelon Generation
38.1
36.7
37.2
Effective Tax Rate -
Operating (%)
136.59
144.40
106.13
RTO Capacity Price ($/MW-day)
2009 Actual
2010 Actual
2011 Est.
(3)
Nuclear Capacity Factor (%)
(1)
93.6
93.9
93.0
Total Generation Sales Excluding Trading (GWh)
173,065
171,789
168,700
Henry Hub Gas Price ($/mmBtu)
3.92
4.37
4.56
PJM West Hub ATC Price ($/MWh)
38.30
45.93
45.45
Tetco M3 Gas Price ($/mmBtu)
4.64
5.10
5.32
PJM West Hub Implied ATC Heat Rate (mmbtu/MWh)
8.25
9.01
8.54
NI Hub ATC Price ($/MWh)
28.85
33.09
30.69
Chicago City Gate Gas Price ($/mmBtu)
3.92
4.46
4.61
NI Hub Implied ATC Heat Rate (mmbtu/MWh)
7.36
7.42
6.66
MAAC Capacity Price ($/MW-day)
158.48
181.34
136.59
EMAAC Capacity Price ($/MW-day)
173.73
181.34
136.59
Electric Delivery Growth (%)
(2)
PECO
0.6
0.1
0.0
ComEd
(0.1)
0.2
0.0
(1)
Excludes Salem.
.
(2)
Weather-normalized retail load growth.
(3)
Reflects forward market prices as of December 31, 2010.
Note: The estimates of planned generation do not represent guidance or a forecast of future
results as Exelon has not completed its planning or optimization processes. |
 20
Pension and OPEB Expense and
Contributions –
As of 12/31/10
$190
$240
Pre-tax
expense
$205
$1,655
$3,875
$2,220
$765
$8,860
$12,525
$3,665
Actual
contribution
$210
$2,140
$225
$185
$2,180
$210
5.83% in 2010
5.30% in 2011
5.52% in 2012
11.6% in 2010
7.08% in 2011
7.08% in 2012
OPEB
Assets
Obligations
Unfunded balance –
end of year
$110
$1,015
$240
$2,100
$1,305
$200
5.83% in 2010
5.26% in 2011
5.48% in 2012
11.9% in 2010
8.0% in 2011
7.5% in 2012
Pension
Assets
Obligations
Unfunded balance –
end of year
Expected
contribution
Pre-tax
expense
Expected
contribution
Pre-tax
expense
Discount Rate
(used for
expense)
Asset Returns
(actual for 2010 and
expected for
2011 and 2012)
($ in millions)
Assumptions
2011
2012
2010
The decrease in pension expense in 2011 is primarily due to the $2.1 billion pension
contribution,
partially
offset
by
the
effects
of
lower
discount
rates
and
a
decrease
in
EROA
(1)
Pension expense amounts exclude settlement charges.
(2)
Management considers various factors when making pension funding decisions, including actuarially
determined minimum contribution requirements under ERISA, contributions required to avoid
benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory
implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions
(such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk
status (which triggers higher minimum contribution requirements and participant notification).
Note: Slide provided for illustrative purposes and not intended to represent a forecast of future
outcomes. Assumes an ~25% capitalization of pension and OPEB costs. EROA = earned
return on assets The decrease in pension expense in 2011 is primarily due to the $2.1 billion pension
contribution, partially offset by the effects of lower discount rates and a decrease in EROA
|
 21
2011 Pension Contribution
$2.1 billion contribution to pension in 2011
•
Timing:
~$850
million
funded
by
the
accelerated cash benefits generated as a
result of bonus depreciation
•
Tax
efficient:
Income
tax
deduction
of
pension contribution creates $750 million
of cash benefit
•
Economic:
Reduces
estimated
future
pension expense, lowers future minimum
funding requirements and reduces volatility
Improves financial flexibility
•
Creates debt capacity for future growth
•
Improves ability to weather commodity
cycle in 2012 and 2013 and maintain the
dividend
Contributes to improved pension funded
status of 71% at 12/31/10, projected to be
89% at 12/31/11
Pension Contributions
615
2,100
765
110
175
160
195
780
790
170
485
2010
2011
2012
2013
2014
2015
With $2.1B
Original Plan*
(1) Assumes an ~25% capitalization rate.
$ millions
$ millions
* Original
Plan
reflects
preliminary
2010
underlying
assumptions
(including
discount
rate
and
asset
returns)
Pre-Tax
Pension
Expense
(1)
240
300
265
200
240
2010
2011
2012 |
 22
2011 Projected Sources and Uses of Cash
(1)
Excludes counterparty collateral activity.
(2)
Cash Flow from Operations primarily includes net cash flows provided by operating
activities and net cash flows used in investing activities other than capital expenditures.
(3)
Assumes 2011 dividend of $2.10/share. Dividends are subject to declaration by
the Board of Directors. (4)
Includes $475 million in Nuclear Uprates and $225 million for Exelon Wind.
(5)
Represents new business, smart grid/smart meter investment and transmission growth
projects. (6)
Excludes ComEd’s $191 million of tax-exempt bonds that are backed by
letters of credit (LOCs). Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo.
PECO’s A/R Agreement was extended in accordance with its terms through
September 6, 2011. (7)
“Other”
includes proceeds from options and expected changes in short-term debt.
(8) Includes cash flow activity from Holding Company, eliminations, and
other corporate entities. ($ millions)
Exelon
(8)
Beginning Cash Balance
(1)
$800
Cash Flow from Operations
(2)
425
775
3,150
4,325
CapEx
(excluding Nuclear Fuel, Nuclear
Uprates, Exelon Wind, Utility Growth CapEx)
(700)
(325)
(850)
(1,875)
Nuclear Fuel
n/a
n/a
(1,025)
(1,025)
Dividend
(3)
(1,400)
Nuclear Uprates
and Exelon Wind
(4)
n/a
n/a
(700)
(700)
Utility Growth CapEx
(5)
(325)
(125)
n/a
(450)
Net Financing (excluding Dividend):
Planned Debt Issuances
(6)
1,000
--
--
1,000
Planned Debt Retirements
(350)
(250)
--
(600)
Other
(7)
250
--
--
300
Ending Cash Balance
(1)
$375 |
 23
Key Credit Metrics
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
2009A
2010A
2011E
ExGen/Corp
ComEd
PECO
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
2009A
2010A
2011E
ExGen/Corp
ComEd
PECO
FFO / Debt
(1)
(1)
Reflects FFO / Debt, Interest Coverage and Debt / Cap ratios as calculated by
S&P. (2)
Reflects S&P Target Range. See slide 24 for reconciliations to
GAAP. (3)
FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt
obligations of Exelon Corp. (4)
Current senior unsecured ratings for Exelon and Exelon Generation and senior
secured ratings for ComEd and PECO as of January 31, 2011. 30-35%
(3)
15-18%
15-18%
FFO / Debt
Target
Range
(2)
BBB+
A
BBB+
BBB+
Fitch
Credit
Ratings
(4)
BBB
A-
A-
BBB-
S&P
Credit
Ratings
(4)
A3
A1
Baa1
Baa1
Moody’s
Credit
Ratings
(4)
ComEd:
PECO:
Generation:
Exelon:
Interest Coverage
(1)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2009A
2010A
2011E
ExGen/Corp
ComEd
PECO
Debt / Cap
(1) |
 24
Metric Calculations and Ratios
+ Other
Non-Cash
items
(1)
-
AFUDC/Cap. Interest
-
Decommissioning activity
+/-
Change in Working Capital
FFO Calculation:
= FFO
-
PECO Transition Bond Principal Paydown
Net Cash Flows provided by Operating Activities
Adjusted Interest:
Net Interest Expense
Adjusted Interest
FFO + Adjusted Interest
= Adjusted Interest
+ AFUDC & Capitalized interest
+ Interest on Present Value (PV) of Operating Leases
+ Interest on Imputed Debt Related to PV of Power Purchase Agreements (PPA)
-
PECO Transition Bond Interest Expense
Interest Coverage:
FFO
= Adjusted Debt
+ Off-balance
sheet
debt
equivalents
(3)
-
PECO Transition Bond Principal Balance
+ STD
LTD
Adjusted Debt:
Adjusted Debt
(2)
FFO / Debt:
+ Adjusted Debt
(3)
Debt / Cap:
= Adjusted Capitalization
Adjusted Debt
(2)
Adjusted Capitalization
Adjusted Capitalization:
Total shareholder’s equity
+ Preferred Securities of Subsidiaries
(1)
Reflects depreciation adjustment for PPAs and operating leases and pension/OPEB contribution
normalization. (2)
Uses current year-end adjusted debt balance.
(3)
Metrics are calculated in presentation adjusted for debt equivalents for PV of Operating Leases,
PPAs, unfunded Pension and OPEB obligations (after-tax) and other minor debt
equivalents. |
 25
ComEd 2010 Rate Case Update
ComEd Surrebuttal (1/3/11)
$326M increase requested
11.50% ROE / 47.28% equity ratio
Rate base $7,349M
2009 test year with pro forma plant
additions through 6/30/11
ICC Staff Position
$116M increase proposed in Dec 2010
rebuttal testimony
10.00% ROE / 47.11% equity ratio
Rate base $6,602M
Pro forma plant additions and
depreciation reserve through 12/31/10
(ICC Docket No. 10-0467)
$ millions
ComEd Original Request (6/30/10)
396
$
Adjustments:
Bonus Depreciation
(14)
Pro forma plant adds/O&M update
(4)
Errata in Initial Filing
(12)
Reduction to Reg Asset Amortization
(8)
Other Items
(4)
ComEd Rebuttal (11/22/10)
354
$
Adjustments:
New Bonus Depreciation
(22)
Pro forma plant adds/O&M update
(4)
Reduction to AMI/Other
(2)
ComEd Surrebuttal (1/3/2011)
326
$
Note: See slide 13 for ComEd rate case key dates.
* ComEd request does not reflect Appellate Court decision relating to
depreciation reserve, which we estimate would have a $85M reduction
to revenue requirement.
*
Reconciliation of ComEd
Request to ComEd
Surrebuttal |
 26
26
ComEd Load Trends
Chicago
U.S.
Unemployment rate
(1)
9.3%
9.4%
2010 annualized growth in
gross domestic/metro product
(2)
1.6%
2.8% Note: C&I = Commercial &
Industrial Weather-Normalized Load Year-over-Year
4Q10
2010 2011E
Average Customer Growth
0.4%
0.2%
0.5%
Average Use-Per-Customer
(4.5)%
(1.4)%
0.0%
Total Residential
(4.1)%
(1.2)% 0.5%
Small C&I
(1.5)%
(0.6)% (0.3)%
Large C&I
1.9%
2.6% (0.2)%
All Customer Classes
(1.2)%
0.2% 0.0%
(1)
Source: U.S. Dept. of Labor (December 2010) and Illinois
Department of Security (December 2010)
(2) Source: Global Insight December 2010
-6.0%
-3.0%
0.0%
3.0%
6.0%
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
-6.0%
-3.0%
0.0%
3.0%
6.0%
All Customer Classes
Large C&I
Residential
Gross Metro Product
Key Economic Indicators
Weather-Normalized Load |
 27
PECO Load Trends
Philadelphia
U.S.
Unemployment rate
(1)
8.4%
9.4% 2010 annualized growth in
gross domestic/metro product
(2)
2.8%
2.8% Note: C&I = Commercial & Industrial
4Q10
2010 2011E
Average Customer Growth
0.5%
0.3%
0.4%
Average Use-Per-Customer
(1.2)%
0.3%
(0.3)%
Total Residential
(0.7)%
0.5% 0.1%
Small C&I
(2.0)%
(1.9)% (0.5)%
Large C&I
1.5%
0.8% 0.1%
All Customer Classes
0.0%
0.1% 0.0%
(1)
Source:
U.S
Dept.
of
Labor
(PHL
–
November
2010
preliminary
data,
US
-
December 2010)
(2)
Source: Global Insight December 2010
-5.0%
-2.5%
0.0%
2.5%
5.0%
1Q10
2Q10
3Q10
4Q10
1Q11E
2Q11E
3Q11E
4Q11E
-5.0%
-2.5%
0.0%
2.5%
5.0%
All Customer Classes
Large C&I
Residential
Gross Metro Product
Weather-Normalized Load Year-over-Year
Key Economic Indicators
Weather-Normalized Load |
 28
Refueling Outage Schedule
All Exelon owned units on a 24-month
cycle except for Braidwood U1/U2,
Byron U1/U2 and Salem U1/U2,
which are on 18-month cycles
Average outage duration (2009-10):
~29 days
(1)
Nuclear Refueling Cycle
12 planned refueling outages,
including 2 at Salem; Clinton outage
was moved from 2012 to 2011
6 refueling outages planned for the
spring and 6 refueling outages
planned for the fall
2011 Refueling Outage Impact
(1) Excludes Salem.
125
127
129
131
133
135
137
139
141
143
145
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
7
8
9
10
11
12
13
Nuclear Output
Actual
Plan
# of Outages
Note: Data includes Salem. Net nuclear generation data based on ownership interest. The
estimates of planned generation do not represent guidance or a forecast of future results as
Exelon has not completed its planning or optimization processes. |
 29
29
Total Portfolio Characteristics
110,594
142,400
42,003
5,295
13,897
26,300
0
50,000
100,000
150,000
200,000
2010
2011E
ComEd Swap
IL Auction
PECO Load
Actual Forward Hedges & Open Position
92,493
91,300
47,517
48,100
27,090
26,500
4,689
2,800
0
50,000
100,000
150,000
200,000
2010
2011E
Forward / Spot Purchases
Fossil and Renewables
Mid-Atlantic Nuclear
Midwest Nuclear
171,789
171,789
168,700
168,700
Expected Total Supply (GWh)
Expected Total Sales (GWh)
Notes: Represents values as of December 31, 2010. The estimates of planned generation do not
represent guidance or a forecast of future results as Exelon has not completed its planning or
optimization processes. |
  30
Exelon Generation Hedging Disclosures
(as of December 31, 2010) |
 31
31
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 December 31, 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. |
 32
32
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 |
 33
33
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 |
 34
34
2011
2012
2013
Estimated
Open
Gross
Margin
($
millions)
(1)(2)(3)
$5,200
$5,050
$5,700
Open gross margin assumes all expected generation is sold
at the Reference Prices listed below
Reference Prices
(1)
Henry Hub Natural Gas ($/MMBtu)
NI-Hub ATC Energy Price ($/MWh)
PJM-W ATC Energy Price ($/MWh)
ERCOT
North
ATC
Spark
Spread
($/MWh)
(4)
$4.56
$30.69
$45.45
$1.12
$5.08
$32.38
$46.41
$0.82
$5.33
$35.09
$48.25
$1.84
Exelon Generation Open Gross Margin and
Reference Prices
(1)
Based on December 31, 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)
As of December 31, 2010 disclosure, Exelon Wind included. Assets in IL,
MI and MN are in Midwest region and assets in ID, KS, MO, OR and TX are in South and West region.
(4)
ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50
variable O&M. |
 35
35
2011
2012
2013
Expected Generation
(GWh)
(1)
165,900
165,800
163,300
Midwest
99,600
98,500
96,200
Mid-Atlantic
56,800
57,200
56,500
South & West
9,500
10,100
10,600
Percentage of Expected Generation Hedged
(2)
90-93%
67-70%
32-35%
Midwest
91-94
69-72
31-34
Mid-Atlantic
93-96
67-70
36-39
South & West
70-73
51-54
39-42
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$43.00
$41.50
$43.50
Mid-Atlantic
$57.00
$50.50
$51.50
South & West
$2.50
$(1.00)
$(3.50)
Generation Profile
(1)
Expected generation represents the amount of energy estimated to be
generated or purchased through owned or contracted for capacity. Expected generation is based upon a simulated dispatch model that
makes assumptions regarding future market conditions, which are
calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 12 refueling outages in
2011 and 10 refueling outages in 2012 and 2013 at Exelon-operated
nuclear plants and Salem. Expected generation assumes capacity factors of 93.0%, 93.6% and 93.1% in 2011, 2012 and 2013 at Exelon-
operated nuclear plants. These estimates of expected generation in 2012
and 2013 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes
for those years.
(2)
Percent of expected generation hedged is the amount of equivalent sales
divided by the expected generation. Includes all hedging products, such as wholesale and retail sales of power, options, and swaps.
Uses expected value on options. Reflects decision to permanently retire
Cromby Station and Eddystone Units 1&2 as of May 31, 2011.
(3)
Effective realized energy price is representative of an all-in
hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs
associated with our hedges and by considering the fossil fuel that has
been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market value of
capacity contracted at prices other than RPM clearing prices including
our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-
to-market value of Exelon Generation's energy hedges.
|
 36
36
Gross Margin Sensitivities with Existing Hedges ($ millions)
(1)
Henry Hub Natural Gas
+ $1/MMBtu
-
$1/MMBtu
NI-Hub ATC Energy Price
+$5/MWH
-$5/MWH
PJM-W ATC Energy Price
+$5/MWH
-$5/MWH
Nuclear Capacity Factor
+1% / -1%
2011
$5
$(5)
$30
$(20)
$15
$(10)
+/-
$40
2012
$175
$(95)
$185
$(165)
$115
$(110)
+/-
$45
2013
$495
$(445)
$340
$(335)
$200
$(195)
+/-
$50
Exelon Generation Gross Margin Sensitivities
(with Existing Hedges)
(1)
Based on December 31, 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. |
 37
37
95% case
5% case
$5,400
$7,100
$6,800
$6,300
Exelon Generation Gross Margin Upside / Risk
(with Existing Hedges)
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
2011
2012
$7,200
$5,000
2013
(1)
Represents an approximate range of expected gross margin, taking into account hedges in place, between
the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot
market. Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market
inputs, future transactions and potential modeling changes. These ranges of approximate gross margin
in 2012 and 2013 do not represent earnings guidance or a forecast of future results as Exelon
has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market
quotes for power, fuel, load following products, and options as of December 31, 2010.
|
 38
38
Midwest
Mid-Atlantic
South & West
Step 1
Start
with
fleetwide
open
gross
margin
$5.20 billion
Step 2
Determine
the
mark-to-market
value
of energy hedges
99,600GWh * 92% *
($43.00/MWh-$30.69MWh)
= $1.13 billion
56,800GWh * 94% *
($57.00/MWh-$45.45MWh)
= $0.62 billion
9,500GWh * 71% *
($2.50/MWh-$1.12/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: $5.20 billion
MTM value of energy
hedges: $1.13billion
+
$0.62billion
+
$0.01
billion
Estimated hedged gross margin:
$6.96 billion
Illustrative Example
of Modeling Exelon Generation 2011 Gross Margin
(with Existing Hedges) |
  39
35
40
45
50
55
60
65
70
75
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
50
55
60
65
70
75
80
85
90
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
Market Price Snapshot
Forward NYMEX Natural Gas
PJM-West and Ni-Hub On-Peak Forward Prices
PJM-West and Ni-Hub Wrap Forward Prices
2012
$5.49
2013 $5.74
Rolling
12
months,
as
of
February
2
2011.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
Forward NYMEX Coal
2012
$75.91
2013
$79.79
2012 Ni-Hub $41.18
2013 Ni-Hub
$43.29
2013 PJM-West $54.85
2012 PJM-West
$52.84
2012 Ni-Hub
$25.68
2013 Ni-Hub
$27.95
2013 PJM-West
$40.70
2012 PJM-West
$38.77
20
25
30
35
40
45
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
nd |
  40
8.0
8.2
8.4
8.6
8.8
9.0
9.2
9.4
9.6
9.8
10.0
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
35
40
45
50
55
60
65
70
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
Market Price Snapshot
2013
9.30
2012
9.11
2012
$48.99
2013
$52.31
2012
$5.37
2013
$5.62
Houston Ship Channel Natural Gas
Forward Prices
ERCOT North On-Peak Forward Prices
ERCOT North On-Peak v. Houston Ship Channel
Implied Heat Rate
2012
$7.68
2013
$9.10
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
4.5
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
2/11
Rolling
12
months,
as
of
February
2
2011.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
nd |
 41
4Q GAAP EPS Reconciliation
(0.01)
-
-
-
(0.01)
2007 Illinois electric rate settlement
(0.01)
-
-
-
(0.01)
John Deere Renewables acquisition costs
0.01
-
-
0.01
-
Asset Retirement Obligation reduction
(0.03)
-
-
-
(0.03)
Retirements of fossil generation units / plant retirements
(0.17)
-
-
-
(0.17)
Mark-to-market adjustments from economic hedging activities
$0.79
$(0.01)
$0.03
$0.14
$0.63
4Q 2010 GAAP Earnings (Loss) Per Share
$0.96
$(0.01)
$0.03
$0.13
$0.81
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
0.04
-
-
-
0.04
Unrealized gains related to nuclear decommissioning trust funds
Exelon
Other
PECO
ComEd
ExGen
Three Months Ended December 31, 2010
NOTE: All amounts shown are per Exelon share and represent contributions to
Exelon's EPS. Amounts may not add due to rounding. 0.04
-
-
-
0.04
Mark-to-market adjustments from economic hedging activities
(0.01)
-
-
(0.01)
-
City of Chicago settlement with ComEd
(0.02)
(0.01)
-
-
(0.01)
Costs associated with early debt retirements
(0.02)
-
-
-
(0.02)
2007 Illinois electric rate settlement
(0.05)
-
-
-
(0.05)
Retirement of fossil generating units
0.02
-
-
-
0.02
Unrealized gains related to nuclear decommissioning trust funds
$0.88
$(0.03)
$0.12
$0.15
$0.64
4Q 2009 GAAP Earnings (Loss) Per Share
$0.92
$(0.02)
$0.12
$0.16
$0.66
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Three Months Ended December 31, 2009 |
 42
Full Year 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. (0.01)
-
-
-
(0.01)
John Deere Renewables acquisition costs
0.01
-
-
0.01
-
Asset Retirement Obligation reduction
(0.10)
(0.01)
(0.03)
(0.16)
0.10
Non-cash remeasurement of income tax uncertainties
(0.10)
(0.02)
(0.02)
(0.02)
(0.04)
Non-cash charge resulting from health care legislation
(0.05)
-
-
-
(0.05)
Impact of certain emission allowances
0.08
-
-
-
0.08
Mark-to-market adjustments from economic hedging activities
(0.08)
-
-
-
(0.08)
Retirement of fossil generating units
$3.87
$(0.10)
$0.49
$0.51
$2.97
FY 2010 GAAP Earnings (Loss) Per Share
$4.06
$(0.07)
$0.54
$0.68
$2.91
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
(0.02)
-
-
-
(0.02)
2007 Illinois electric rate settlement
0.08
-
-
-
0.08
Unrealized gains related to nuclear decommissioning trust funds
Exelon
Other
PECO
ComEd
ExGen
Twelve Months Ended December 31, 2010
0.16
-
-
-
0.16
Mark-to-market adjustments from economic hedging activities
(0.05)
-
-
-
(0.05)
Retirement of fossil generating units
(0.01)
-
-
(0.01)
-
City of Chicago settlement with ComEd
(0.10)
-
-
(0.01)
(0.09)
2007 Illinois electric rate settlement
(0.11)
(0.04)
-
-
(0.07)
Costs associated with early debt retirements
(0.20)
-
-
-
(0.20)
Impairment of certain generating assets
(0.03)
-
(0.00)
(0.02)
(0.01)
2009 severance charges
0.05
-
-
-
0.05
Nuclear decommissioning obligation reduction
(0.03)
(0.03)
-
-
-
NRG acquisition costs
0.19
-
-
-
0.19
Unrealized gains related to nuclear decommissioning trust funds
0.10
(0.02)
-
0.06
0.06
Non-cash remeasurement of income tax uncertainties and reassessment of state
deferred income taxes
$4.09
$(0.21)
$0.53
$0.56
$3.21
FY 2009 GAAP Earnings (Loss) Per Share
$4.12
$(0.12)
$0.54
$0.54
$3.16
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Twelve Months Ended December 31, 2009 |
 43
GAAP to Operating Adjustments
Exelon’s 2011 adjusted (non-GAAP) operating earnings outlook excludes the
earnings effects of the following:
•
Mark-to-market adjustments from economic hedging activities
•
Unrealized gains and losses from nuclear decommissioning trust fund investments to
the extent not offset by contractual accounting as described in the notes
to the consolidated financial statements •
Significant impairments of assets, including goodwill
•
Changes in decommissioning obligation estimates
•
Costs associated with ComEd’s 2007 settlement with the City of Chicago
•
Financial impacts associated with the planned retirement of fossil generating
units •
Other unusual items
•
Significant changes to GAAP
Operating earnings guidance assumes normal weather for full year
O&M reconciliation:
2010
2011
ExGen
ComEd
PECO
Other
Exelon
ExGen
ComEd
PECO
Other
Exelon
Operating and maintenance (GAAP)
2,812
1,069
733
(14)
4,600
3,010
1,220
820
(10)
5,040
JDR acquisition costs
(11)
-
-
-
(11)
-
-
-
-
-
Retirement of fossil generating units
(3)
-
-
-
(3)
(30)
-
-
-
(30)
Non-cash charge resulting from health care legislation
(4)
(3)
(2)
8
(1)
-
-
-
-
-
Asset retirement obligation reduction
-
10
1
-
11
-
-
-
-
-
Adjusted Non-GAAP O&M
2,794
1,076
732
(6)
4,596
2,980
1,220
820
(10)
5,010
Decommissioning accretion
(57)
-
-
-
(57)
(70)
-
-
-
(70)
Regulatory required programs
-
(94)
(53)
-
(147)
-
(150)
(110)
-
(260)
Operating O&M (as shown on slide 15)
2,737
982
679
(6)
4,392
2,910
1,070
710
(10)
4,680
($ millions) |