Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - EXELON GENERATION CO LLC | d8k.htm |
| EX-99.1 - PRESS RELEASE AND EARNINGS RELEASE ATTACHMENTS - EXELON GENERATION CO LLC | dex991.htm |
 Earnings Conference Call
4
th
Quarter 2010
January 26, 2011
Exhibit 99.2 |
 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
of
non-GAAP cash flows to GAAP cash flows. |
 3
2010: Another Strong Year for Exelon
Exemplary year of 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
Continuing to position Exelon
for cleaner energy future
Strong reliability scores despite significant storm
activity
Highest customer satisfaction scores in > 5 yrs
Completed electric and gas distribution rate cases
Best
customer
satisfaction
scores
in
PECO
history
Eighth consecutive year with nuclear capacity
factor above 93%
59 MW added through nuclear uprate program
Acquired John Deere Renewables
Announced early retirement of Oyster Creek
RITE line project announced
(1)
Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation
of adjusted (non-GAAP) operating EPS to GAAP EPS. (2)
2010 Cash from operations excludes counterparty collateral and includes net cash from investing
activities other than capital expenditures, acquisition of Exelon Wind and change in restricted
cash. |
 4
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
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
Introducing
2011
operating
earnings
guidance
of
$3.90
–
$4.20/share
and
1Q
2011
guidance
of
$1.00
–
$1.10/share
(1)
(1)
Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation
of adjusted (non-GAAP) operating EPS to GAAP EPS. (2)
Earnings guidance for OpCos may not add up to consolidated EPS guidance.
|
 5
2017/
2018
2016/
2017
2015/
2016
2014/
2015
PJM RPM Auctions
Delivery Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
EPA Regulations Will Move Forward in 2011
Notes: RPM auctions take place annually in May.
For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of
Environment (http://www.epa.gov/OCEPAterms/). |
 6
Key Financial Messages
2010
operating
earnings
of
$4.06/share
(1)
in
line
with
expectations
•
Higher capacity and energy (PECO PPA) revenues at ExGen
•
Higher earnings (vs. 2009) at ComEd
2011
earnings
guidance
of
$3.90
-
$4.20/share
(1)
•
Expiration
of
PECO
PPA
allows
ExGen
to
sell
additional
energy
at
market
prices,
offset by lower RPM capacity prices and higher costs
•
New distribution rates effective 1/1/11 at PECO
Strong cash flows in 2011
•
Expect to generate $4.3 billion cash from operations in 2011
•
Increasing investment in growth projects at ExGen and Utilities
Efficient use of cash benefits from bonus depreciation
•
$2.1 billion pension contribution proactively reduces pension costs and future
contributions while improving pension funding status
(1) Refer to Earnings Release Attachments for additional details
and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. |
 7
Exelon Generation
Operating EPS Contribution
2010
2009
(1) Refer to the Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(2) Outage days exclude Salem.
97
136
Refueling
18
23
Non-refueling
4Q10
4Q09
Outage Days
(2)
4Q
YTD
$0.66
$3.16
$0.81
$2.91
Note: PPA = Power Purchase Agreement
Key Drivers –
4Q10 vs. 4Q09
(1)
Higher energy prices under the PECO
PPA, offset at PECO: $0.10
Favorable RPM capacity pricing: $0.07
Higher nuclear volume: $0.04
Higher nuclear fuel costs: $(0.02)
Higher depreciation expense: $(0.03) |
 8
0%
10%
20%
30%
40%
50%
60%
70%
80%
Q1 2010
Q2 2010
Q3 2010
Q4 2010
Underlying
Options
Ratable
Power Fundamentals & Hedging Update
Using our perspective on the markets to time
sales, thereby adding value
•
PJMW energy prices increased in 4Q 2010, driven by
higher eastern coal prices
•
NiHub energy prices and Henry Hub natural gas prices
remained relatively stable in 4Q 2010
•
Slowed down pace of hedging in Q3 & Q4 to recognize
future upside from environmental regulations and
economic recovery
Normal practice is to hedge commodity risk
on a ratable basis over three years
•
Maintain flexibility from quarter to quarter
•
Use gas and power put options to capture potential
upside while providing downside price protection
Exelon’s ratable hedging program provides flexibility to time sales based
on fundamental view of the market
2012 Historical Energy & Gas Prices
31.00
33.00
35.00
37.00
39.00
41.00
43.00
45.00
47.00
49.00
51.00
1/4/10
2/3/10
3/5/10
4/4/10
5/4/10
6/3/10
7/3/10
8/2/10
9/1/10
10/1/10
10/31/10
11/30/10
12/30/10
4.80
5.00
5.20
5.40
5.60
5.80
6.00
6.20
6.40
6.60
6.80
PJMWHub
NiHub
Henry Hub Nat Gas
2012 Quarterly Hedge Level vs. Ratable Plan
Note: % values represent amount
above ratable plan
10%
8%
11%
5% |
 9
Key Drivers –
4Q10 vs. 4Q09
(1)
Appellate Court ruling: $(0.02)
Higher O&M expense: $(0.01)
ComEd Operating EPS Contribution
(1) Refer to the Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
2010
2009
4Q
YTD
$0.16
$0.54
4Q10
Actual
Normal
% Change
Heating Degree-Days
2,292 2,278 0.6%
Cooling Degree-Days 15
7 114%
$0.13
$0.68 |
 10
10
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
Key Economic Indicators
Weather-Normalized Load
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 |
 11
PECO Operating EPS Contribution
Key Drivers –
4Q10 vs. 4Q09
(1)
Decreased CTC revenue resulting
in higher energy prices paid to
Generation under the PPA, offset
at Generation: $(0.10)
Weather: $0.01
CTC amortization $0.02
2010
2009
(1) Refer to the Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. 4Q
YTD
$0.12
$0.54
4Q10
$0.03
$0.54
Actual
Normal
% Change
Heating Degree-Days
1,686 1,634 3.2%
Cooling Degree-Days
19 21 (9.5)%
Note: CTC = Competitive Transition Charge |
 12
(1)
Source: U.S Dept. of Labor (PHL – November 2010 preliminary data,
US – December 2010)
(2)
Source: Global Insight December 2010
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
Weather-Normalized Load Year-over-Year
Key Economic Indicators
Weather-Normalized Load
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%
-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 |
 $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)
(1)
13
(1) Amounts may not add due to rounding. Refer to slide 44 for a reconciliation of GAAP O&M to
Operating O&M. |
 14
Pension and OPEB Expense and
Contributions –
As of 12/31/10
(1)
Pension expense amounts exclude settlement charges.
(2)
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.
$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 impacts of lower discount rates and a
decrease in EROA 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). |
 15
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*
Pre-Tax Pension Expense
(1)
240
300
265
200
240
2010
2011
2012
(1) Assumes an ~25% capitalization rate.
$ millions
$ millions
*
Original Plan reflects preliminary 2010 underlying assumptions (including
discount rate and asset returns) |
 16
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 spend.
(5)
Represents new business, smart grid/smart meter investment and transmission growth
projects. (6)
Excludes ComEd’s $191 million of tax-exempt bonds that are backed by
letters of credit (LOCs). Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo.
PECO’s A/R Agreement was extended in accordance with its terms through
September 6, 2011. (7)
“Other”
includes proceeds from options and expected changes in short-term debt.
(8) Includes cash flow activity from Holding Company, eliminations, and
other corporate entities. ($ 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 |
 17
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)
EPA Final Transport
Rule (June)
For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of
Environment (http://www.epa.gov/OCEPAterms/). |
 18
Exelon Generation Hedging Disclosures
(as of December 31, 2010)
*********** |
 19
19
Important Information
The
following
slides
are
intended
to
provide
additional
information
regarding
the
hedging
program
at
Exelon
Generation
and
to
serve
as
an
aid
for
the
purposes
of
modeling
Exelon
Generation’s
gross
margin
(operating
revenues
less
purchased
power
and
fuel
expense).
The
information
on
the
following
slides
is
not
intended
to
represent
earnings
guidance
or
a
forecast
of
future
events.
In
fact,
many
of
the
factors
that
ultimately
will
determine
Exelon
Generation’s
actual
gross
margin
are
based
upon
highly
variable
market
factors
outside
of
our
control.
The
information
on
the
following
slides
is
as
of
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. |
      20
20
Portfolio Management Objective
Align Hedging Activities with Financial Commitments
Power Team utilizes several product types
and channels to market
•
Wholesale and retail sales
•
Block products
•
Load-following products
and load auctions
•
Put/call options
Exelon’s hedging program is designed to
protect the long-term value of our
generating fleet and maintain an
investment-grade balance sheet
•
Hedge enough commodity risk to meet future cash
requirements if prices drop
•
Consider: financing policy (credit rating objectives,
capital structure, liquidity); spending (capital and
O&M); shareholder value return policy
Consider market, credit, operational risk
Approach to managing volatility
•
Increase hedging as delivery approaches
•
Have enough supply to meet peak load
•
Purchase fossil fuels as power is sold
•
Choose hedging products based on generation
portfolio –
sell what we own
•
Heat rate options
•
Fuel products
•
Capacity
•
Renewable credits
% Hedged
High End of Profit
Low End of Profit
Open Generation
with LT Contracts
Portfolio
Optimization
Portfolio
Management
Portfolio Management Over Time |
 21
21
Percentage of Expected
Generation Hedged
•
How many equivalent MW have been
hedged at forward market prices; all hedge
products used are converted to an
equivalent average MW volume
•
Takes ALL
hedges into account whether
they are power sales or financial products
Equivalent MWs Sold
Expected Generation
=
Our normal practice is to hedge commodity risk on a ratable basis
over the three years leading to the spot market
•
Carry operational length into spot market to manage forced outage and
load-following risks
•
By
using
the
appropriate
product
mix,
expected
generation
hedged
approaches
the
mid-90s percentile as the delivery period approaches
•
Participation in larger procurement events, such as utility auctions, and some
flexibility in the timing of hedging may mean the hedge program is not
strictly ratable from quarter to quarter
Exelon Generation Hedging Program |
 22
22
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, $2.50
variable O&M. |
 23
23
2011
2012
2013
Expected Generation
(GWh)
(1)
165,900
165,800
163,300
Midwest
99,600
98,500
96,200
Mid-Atlantic
56,800
57,200
56,500
South & West
9,500
10,100
10,600
Percentage
of
Expected
Generation
Hedged
(2)
90-93%
67-70%
32-35%
Midwest
91-94
69-72
31-34
Mid-Atlantic
93-96
67-70
36-39
South & West
70-73
51-54
39-42
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$43.00
$41.50
$43.50
Mid-Atlantic
$57.00
$50.50
$51.50
South & West
$2.50
$(1.00)
$(3.50)
Generation Profile
(1)
Expected
generation
represents
the
amount
of
energy
estimated
to
be
generated
or
purchased
through
owned
or
contracted
for
capacity.
Expected
generation
is
based
upon
a
simulated
dispatch
model
that
makes
assumptions
regarding
future
market
conditions,which
are
calibrated
to
market
quotes
for
power,
fuel,
load
following
products,
and
options.
Expected
generation
assumes
12
refueling
outages
in
2011
and
10
refueling
outages
in
2012
and
2013
at
Exelon-operated
nuclear
plants
and
Salem.
Expected
generation
assumes
capacity
factors
of
93.0%,
93.6%
and
93.1%
in
2011,
2012
and
2013
at
Exelon-operated
nuclear
plants.
These
estimates
of
expected
generation
in
2012
and
2013
do
not
represent guidance or a
forecast of future results as Exelon has not completed its planning or optimization
processes for those years. (2)
Percent of expected generation hedged is the amount of equivalent sales divided by
the expected generation. Includes all hedging products, such as wholesale and retail sales of power,
options, and swaps. Uses expected value on options. Reflects decision to
permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.
(3)
Effective realized energy price is representative of an all-in hedged price, on
a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy
revenues
and
costs
associated
with
our
hedges
and
by
considering
the
fossil
fuel
that
has
been
purchased
to
lock
in
margin.
It
excludes
uranium
costs
and
RPM
capacity
revenue,
but
includes
the
mark-to-market
value
of
capacity
contracted
at
prices
other
than
RPM
clearing
prices
including
our
load
obligations.
It
can
be
compared
with
the
reference
prices
used
to
calculate open gross margin in order to determine the mark-to-market value
of Exelon Generation's energy hedges. |
 24
24
Gross Margin Sensitivities with Existing Hedges ($ millions)
(1)
Henry Hub Natural Gas
+ $1/MMBtu
-
$1/MMBtu
NI-Hub ATC Energy Price
+$5/MWH
-$5/MWH
PJM-W ATC Energy Price
+$5/MWH
-$5/MWH
Nuclear Capacity Factor
+1% / -1%
2011
$5
$(5)
$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. |
 25
25
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
(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.
$7,200
$5,000
2013 |
 26
26
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) |
 27
35
40
45
50
55
60
65
70
75
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
27
27
20
25
30
35
40
45
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
50
55
60
65
70
75
80
85
90
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
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
$5.54
2013 $5.79
Rolling
12
months,
as
of
January
20
,
2011.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
Forward NYMEX Coal
2012
$75.61
2013
$79.57
2012 Ni-Hub $41.35
2013 Ni-Hub
$43.48
2013 PJM-West $55.12
2012 PJM-West
$53.08
2012 Ni-Hub
$25.78
2013 Ni-Hub
$28.06
2013 PJM-West
$40.79
2012 PJM-West
$38.84
th |
 28
28
28
4.5
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
8.0
8.2
8.4
8.6
8.8
9.0
9.2
9.4
9.6
9.8
10.0
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
35
40
45
50
55
60
65
70
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
Market Price Snapshot
2013
9.29
2012
9.10
2012
$49.40
2013
$52.75
2012
$5.43
2013
$5.67
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
$7.72
2013
$9.30
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
Rolling
12
months,
as
of
January
20
,
2011.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
th |
 29
Appendix
************************* |
 30
Exelon Generation 2011 EPS Contribution
(1)
Estimated contribution to Exelon’s operating earnings guidance.
$ / 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
CTC $0.62
Exelon Wind
$0.08
Capacity Market Prices
$(0.29) Nuclear Fuel
$(0.09)
Market/portfolio conditions
and Exelon
Energy $0.07
$(0.17)
$(0.03)
Interest
Expense
Note: Drivers add up to mid-point of 2011 EPS range.
$(0.05)
$(0.05)
$(0.05) |
 31
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
$(0.04)
Inflation
$(0.02) Note: Drivers add up to mid-point of 2011 EPS range.
$0.68
1
$(0.04)
$(0.02)
$(0.01)
$0.08
(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. |
 32
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.
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 $0.02 |
 33
Key Assumptions
38.0
31.1
29.5
PECO
40.8
39.7
37.9
ComEd
37.1
37.5
38.3
Exelon Generation
38.1
36.7
37.2
Effective Tax Rate -
Operating (%)
136.59
144.40
106.13
RTO Capacity Price ($/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. |
 34
34
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
Expected Total Supply (GWh)
Expected Total Sales
(GWh)
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
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. |
 35
Refueling Outage Schedule
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. 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 spring 2012 to fall
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 |
 36
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
$
Reconciliation of ComEd Request to ComEd Surrebuttal
Note: See slide 17 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
* |
 37
ComEd Customer Usage Breakdown
Other
2%
Residential
31%
Small C&I
36%
380 Large
C&I
18%
Other Large
C&I
13%
3%
Leisure & Hospitality
9%
Trade, Transportation & Utilities
11%
Finance, Professional &
Business Services
12%
Health & Educational Services
13%
Government
52%
Manufacturing
Customer Usage by Revenue Class
Top 380 Customer Usage by Segment
Limited survey of select Large C&I customers has indicated an increase in
production via longer production runs and additional shifts due to improved
economic conditions for manufacturing-based customers, especially in the
steel and transportation sectors, along with data center expansions.
|
 38
PECO Customer Usage Breakdown
Other
3%
Other Large
C&I
24%
150 Large
C&I
17%
Small C&I
22%
Residential
34%
7%
Other
13%
Transportation, Communication &
Utilities
18%
Health & Educational Services
18%
Manufacturing
22%
Petroleum
2%
Retail Trade
9%
Finance, Insurance & Real Estate
12%
Pharmaceuticals
Customer Usage by Revenue Class
Top 150 Customer Usage by Segment
PECO’s load is relatively diversified by customer class and industry
|
 39
Sufficient Liquidity
--
--
--
--
Outstanding Facility Draws
(338)
(134)
(1)
(196)
Outstanding Letters of Credit
$7,365
$4,834
$574
$1,000
Aggregate Bank Commitments
(1)
7,027
4,700
573
804
Available Capacity Under Facilities
(2)
--
--
--
--
Outstanding Commercial Paper
$7,027
$4,700
$573
$804
Available Capacity Less Outstanding
Commercial Paper
Exelon
(3)
($ millions)
Available Capacity Under Bank Facilities as of January 14, 2011
(1) Excludes previous commitment from Lehman Brothers Bank and commitments
from Exelon’s Community and Minority Bank Credit Facility. (2)
Available Capacity Under Facilities represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and facility draws. The
amount of commercial paper outstanding does not reduce the available capacity under
the credit agreements. (3) Includes other corporate entities.
Plan
to
extend/refinance
Exelon
Generation,
PECO
and
Exelon
Corp
credit
facilities in first half of 2011 |
 40
Key Credit Metrics
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
2009A
2010A
2011E
ExGen/Corp
ComEd
PECO
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 41 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 21, 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) |
 41
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:
(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.
+ Adjusted Debt
(3)
Debt / Cap:
= Adjusted Capitalization
Adjusted Debt
(2)
Adjusted Capitalization
Adjusted Capitalization:
Total shareholder’s equity
+ Preferred Securities of Subsidiaries |
 42
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 |
 43
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. (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
$3.16
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Twelve Months Ended December 31, 2009 |
 GAAP
to Operating Adjustments Exelon’s 2011 adjusted (non-GAAP) operating
earnings outlook excludes the earnings effects of the following:
•
Mark-to-market adjustments from economic hedging activities
•
Unrealized gains and losses from nuclear decommissioning trust fund investments to
the extent not offset by contractual accounting as described in the notes
to the consolidated financial statements •
Significant impairments of assets, including goodwill
•
Any changes in decommissioning obligation estimates
•
Costs associated with ComEd’s 2007 settlement with the City of Chicago
•
Financial impacts associated with the planned retirement of fossil generating
units •
Other unusual items
•
Significant changes to GAAP
Operating earnings guidance assumes normal weather for full year
O&M reconciliation:
2010
2011
ExGen
ComEd
PECO
Other
Exelon
ExGen
ComEd
PECO
Other
Exelon
Operating and maintenance (GAAP)
2,812
1,069
733
(14)
4,600
3,010
1,220
820
(10)
5,040
JDR acquisition costs
(11)
-
-
-
(11)
-
-
-
-
-
Retirement of Fossil Generating Units
(3)
-
-
-
(3)
(30)
-
-
-
(30)
Non-cash charge resulting from health care legislation
(4)
(3)
(2)
8
(1)
-
-
-
-
-
Asset Retirement Obligation reduction
-
10
1
-
11
-
-
-
-
-
Adjusted Non-GAAP O&M
2,794
1,076
732
(6)
4,596
2,980
1,220
820
(10)
5,010
Decommissioning accretion
(57)
-
-
-
(57)
(70)
-
-
-
(70)
Regulatory required programs
-
(94)
(53)
-
(147)
-
(150)
(110)
-
(260)
Operating O&M (as shown on slide 13)
2,737
982
679
(6)
4,392
2,910
1,070
710
(10)
4,680
($ millions)
44 |