Attached files
file | filename |
---|---|
8-K - FORM 8-K - EXELON GENERATION CO LLC | d387433d8k.htm |
EX-99.1 - PRESS RELEASE AND EARNINGS RELEASE ATTACHMENTS - EXELON GENERATION CO LLC | d387433dex991.htm |
Exhibit 99.2 |
Cautionary Statements Regarding
Forward-Looking Information
This presentation contains certain 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 the forward-looking statements made by
Exelon Corporation, Commonwealth Edison Company, PECO Energy Company,
Baltimore Gas and Electric Company and Exelon Generation Company, LLC
(Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelons 2011
Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7.
Managements Discussion and Analysis of Financial Condition and
Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data:
Note 18; (2) Constellation Energy Groups 2011 Annual Report on Form
10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8.
Financial Statements and Supplementary Data: Note 12; (3) the Registrants
First Quarter 2012 Quarterly Report on Form 10-Q in (a) Part II,
Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information,
ITEM 1. Financial Statements: Note 15; and (4) other factors discussed in
filings with the SEC by the Registrants. 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 Registrants undertakes any
obligation to publicly release any revision to its forward-looking
statements to reflect events or circumstances after the date of this presentation.
1
2012 2Q Earnings Release Slides
2012 2Q Earnings Release Slides |
2012 2Q Earnings Release Slides
2
Second Quarter Performance and Full Year Guidance
FY 2012
$2.55 -
$2.85
(2)
$1.75 -
$1.95
$0.30 -
$0.40
$0.40 -
$0.50
$0.05 -
$0.15
HoldCo
ExGen
ComEd
PECO
BGE
2012 Earnings Guidance
Another quarter of solid financial and operating
performance
-
Operating earnings in 2Q of $0.61/share
-
Nuclear capacity factor in 2Q of 93.4%
-
Load serving business on course to meet volume and
margin targets
Expect FY 2012 earnings of $2.55 -
$2.85/share
-
On track to achieve $170 million in merger related
synergies for 2012
(1)
-
On track to meet FY 2012 new business gross margin
targets for Power
and Non Power
categories
2012 synergy estimate is applicable for March 12 - December 31, 2012.
2012 guidance includes Constellation Energy and BGE earnings for March 12 -
December 31, 2012. Based on expected 2012 average outstanding shares of 819M. Earnings
guidance for OpCos may not add up to consolidated EPS guidance.
Maintaining FY 2012 operating earnings within $2.55 - $2.85/share
(1)
(2) |
2012 2Q Earnings Release Slides
3
Utility Regulatory Update
ComEd
ICC Rehearing of 2011 Rate Case
ICC decision to rehear key elements of ComEds rate case is a step in the
right direction ComEds positions are solidly supported by existing
legislation Expect
ICC
Order
by
September
19 ,
2012
with
hearings
on
August
3
rd
,
2012
Reversal of original ICC decision on the rehearing items could improve ComEd
earnings by ~$0.10/share in 2012
BGE
2012 Rate Case Filing
On July 27 , BGE filed an electric and gas rate case
Expect
order
from
Maryland
PSC
by
February
2013
with
hearings
in
late
4Q
2012
Reflects a $204M increase in revenue requirements for both electric and
gas New rates expected to be in effect in February / March 2013
BGE 2012 Rate Case Request
Electric
Gas
Total
Rate Base (reflects 13 month average)
$2.7 B
$1.0 B
$3.7 B
Rate of Return (10.5% ROE, 48.4% equity)
8.02%
8.02%
8.02%
Revenue Increase
$151 M
$53 M
$204M
th
th |
2012 2Q Earnings Release Slides
4
Key Financial Messages
Delivered non-GAAP operating earnings in 2Q of
$0.61/share in line with internal expectations
Continue to create value via our hedging program with
strategic decisions on timing, channels and location of
sales
Employing financing strategies to meet funding needs at
attractive interest rates
Expect 3Q 2012 operating earnings in the range of $0.65
-
$0.75/share
FY 2012
$0.61
$0.47
$0.05
$0.10
$0.02
HoldCo
ExGen
ComEd
PECO
BGE
2012 2Q Results
On track to deliver FY 2012 operating earnings within guidance range
owing to excellent operational performance |
2012 2Q Earnings Release Slides
5
ExGen Gross Margin Update
June 30, 2012
April 30, 2012
Gross Margin Category ($ MM)
(1)
2012
(2)
2013
2014
2012
(2)
2013
2014
Open Gross Margin
(2,3)
(including South, West, Canada hedged gross margin)
$4,450
$5,400
$5,850
$4,300
$5,800
$6,250
Mark-to-Market of Hedges
(5)
$3,100
$1,650
$600
$3,150
$1,400
$500
Power New Business / To Go
$100
$550
$850
$200
$550
$850
Non-Power Margins Executed
$250
$100
$100
$200
$100
$50
Non-Power New Business / To Go
$150
$500
$500
$200
$500
$550
Total Gross Margin
$8,050
$8,200
$7,900
$8,050
$8,350
$8,200
Key Highlights in 2Q 2012
Continue to ratably hedge entire portfolio, with strategic timing decisions in
specific regions: -
Midwest and Mid-Atlantic wholesale hedging was pared down in a low price
environment given higher level of hedging in previous quarters at more
favorable prices -
ERCOT wholesale hedges were significantly increased to capture attractive cash
and term spark spreads in early 2Q
-
New
England
wholesale
hedges
were
increased
as
spark
spreads widened
For 2012, achieved $150 million of our Power
and Non-Power
New Business / To-Go, which moved into
executed buckets
For
2013
and
2014,
we
expect
the
power
New
Business
/
To-Go
margins
to
start
moving
into
the
executed
category
as
we
enter
a
more
seasonally
active
sales
cycle
in
the
retail
and
wholesale
business
(1) Gross margin rounded to nearest $50M.
(2) Stub period calculated by excluding Jan 2012 thru mid-March 2012 for
Constellation only. (3) Excludes Maryland assets to be divested.
(4) Includes CENG Joint Venture.
(5) Mark to Market of Hedges assumes mid-point of hedge percentages.
|
2012 Projected Sources and Uses of Cash
(1)
Exelon beginning cash balance as of 12/31/11. Excludes counterparty
collateral activity. (2)
Includes $675 million of Constellation net collateral paid to counterparties
prior to merger completion. (3)
Cash Flow from Operations primarily includes net cash flows provided by
operating activities, estimated proceeds from Maryland clean coal fleet divestitures and net cash flows used in
investing activities other than capital expenditures.
(4)
Dividends are subject to declaration by the Board of Directors.
(5)
Excludes PECOs $225 million Accounts Receivable (A/R) Agreement with Bank
of Tokyo. PECOs A/R Agreement was extended in accordance with its terms through August 31, 2012.
(6)
Other
includes proceeds from options and expected changes in short-term
debt. (7)
Includes cash flow activity from Holding Company, eliminations, and other
corporate entities. Represents Constellation cash flows from merger close
through
December 31, 2012.
6
($ in Millions)
2012 2Q Earnings Release Slides
(7)
`
Beginning Cash Balance
(1)
$550
Cash acquired from Constellation
(2)
150
n/a
n/a
1,375
1,650
Cash Flow from Operations
(3)
250
975
800
3,450
5,375
CapEx (excluding other items below):
(475)
(1,200)
(350)
(1,000)
(3,075)
Nuclear Fuel
n/a
n/a
n/a
(1,175)
(1,175)
Dividend
(4)
(1,725)
Nuclear Uprates
n/a
n/a
n/a
(350)
(350)
Wind
n/a
n/a
n/a
(650)
(650)
Solar
n/a
n/a
n/a
(675)
(675)
Upstream
n/a
n/a
n/a
(75)
(75)
Utility Smart Grid/Smart Meter
(75)
(75)
(75)
n/a
(225)
Net Financing (excluding Dividend):
Planned Debt Issuances
(5)
250
375
350
775
1,750
Planned Debt Retirements
(175)
(450)
(375)
(75)
(1,075)
Project Finance/Federal Financing Bank
Loan
n/a
n/a
n/a
375
375
Other
(6)
25
250
25
(50)
75
Ending Cash Balance
(1)
$750 |
7
APPENDIX
2012 2Q Earnings Release Slides |
8
ExGen Disclosures
June 30, 2012
2012 2Q Earnings Release Slides |
9
Components of Gross Margin Categories
Margins move from new business to MtM of hedges over the
course of the year as sales are executed
Margins
move
from
Non
power
new
business
to
Non
power executed
over the course of the year
Gross margin linked to power production and sales
Gross margin from
other business activities
2012 2Q Earnings Release Slides
(1) Hedged gross margins for South, West & Canada region will be included
with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region.
Generation Gross
Margin at current
market prices,
including
capacity &
ancillary
revenues
Exploration and
Production
PPA Costs &
Revenues
Provided at a
consolidated
level for all
regions (includes
hedged gross
margin for South,
West &
Canada
(1)
)
MtM of power,
capacity and
ancillary hedges,
including cross
commodity, retail
and wholesale
load transactions
Provided directly
at a consolidated
level for five
major regions.
Provided
indirectly for
each of the five
major regions via
EREP, reference
price, hedge %,
expected
generation
Retail, Wholesale
planned electric
sales
Portfolio
Management
new business
Mid marketing
new business
Retail, Wholesale
executed gas
sales
Load Response
Energy Efficiency
BGE Home
Distributed Solar
Retail, Wholesale
planned gas
sales
Load Response
Energy Efficiency
BGE Home
Distributed Solar
Portfolio
Management /
origination fuels
new business
Proprietary
trading
(3)
Open Gross
Margin
MtM of
Hedges
(2)
Power
New
Business
Non Power
Executed
Non Power
New Business
(2) MtM of hedges provided directly for the five larger regions. MtM of hedges
is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh.
(3) Proprietary trading gross margins will remain within Non Power
New Business category and not move to Non power executed category.
|
10
ExGen Disclosures
Gross
Margin
Category
($
MM)
(1)
2012
(2)
2013
2014
Open Gross Margin
(including South, West & Canada hedged GM)
(3,4)
$4,450
$5,400
$5,850
Mark to Market of Hedges
(5)
$3,100
$1,650
$600
Power New Business / To Go
$100
$550
$850
Non-Power Margins Executed
$250
$100
$100
Non-Power New Business / To Go
$150
$500
$500
Total Gross Margin
$8,050
$8,200
$7,900
(1) Gross margin rounded to nearest $50M.
(2) Stub period calculated by excluding Jan 2012 thru mid-March 2012 for
Constellation only. (3) Excludes Maryland assets to be divested.
Reference
Prices
(6)
2012
2013
2014
Henry Hub Natural Gas ($/MMbtu)
$2.72
$3.58
$3.95
Midwest: NiHub ATC prices ($/MWh)
$27.17
$28.85
$30.57
Mid-Atlantic: PJM-W ATC prices ($/MWh)
$32.35
$36.25
$38.42
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$12.19
$7.44
$6.48
New York: NY Zone A ($/MWh)
$29.55
$31.45
$32.99
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$6.17
$4.93
$4.20
(4) Includes CENG Joint Venture.
(5) Mark to Market of Hedges assumes mid-point of hedge percentages.
(6) Based on June 29, 2012 market conditions.
2012 2Q Earnings Release Slides |
11
ExGen Disclosures
Generation and Hedges
2012
(1)
2013
2014
Exp. Gen (GWh)
(4)
219,600
216,900
209,200
Midwest
101,000
97,600
97,600
Mid-Atlantic
(2,3)
71,900
73,600
71,400
ERCOT
19,900
17,800
15,400
New York
(3)
13,400
13,600
10,700
New England
13,400
14,300
14,100
% of Expected Generation Hedged
(5)
99-102%
79-82%
46-49%
Midwest
98-101%
80-83%
47-50%
Mid-Atlantic
(2,3)
102-105%
78-81%
49-52%
ERCOT
96-99%
70-73%
39-42%
New York
(3)
101-104%
85-88%
38-41%
New England
96-99%
79-82%
41-44%
Effective Realized Energy Price ($/MWh)
(6)
Midwest
40.50
39.00
36.00
Mid-Atlantic
(2,3)
53.50
49.00
48.00
ERCOT
7
9.00
7.00
4.00
New York
(3)
45.00
37.00
37.50
New England
(7)
7.50
7.00
4.00
2012 2Q Earnings Release Slides
(1) Stub period calculated by excluding Jan 2012 thru
mid-March 2012 for Constellation only. (2) Excludes Maryland assets to be divested (3) Includes CENG Joint Venture. (4) Expected generation represents
the amount of energy estimated to be generated or purchased
through owned or contracted for capacity. Expected generation is based upon a simulated dispatch model that makes assumptions regarding
future market conditions, which are calibrated to market quotes for power,
fuel, load following products, and options. Expected generation assumes 10 refueling outages in 2012 and 2013 and 11 refueling
outages in 2014 at Exelon-operated nuclear plants and Salem but excludes
CENG. Expected generation assumes capacity factors of 93.1%, 93.3% and 93.8% in 2012, 2013 and 2014 at Exelon-operated
nuclear plants excluding Salem and CENG. These estimates of expected generation
in 2012, 2013 and 2014 do not represent guidance or a forecast of future results as Exelon has not completed its planning
or optimization processes for those years. (5) Percent of expected generation
hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and
retail sales of power, options and swaps. Uses expected value on options. (6)
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. (7) Spark spreads shown for ERCOT and New England.
|
12
ExGen Hedged Gross Margin Sensitivities
Gross
Margin
Sensitivities
(With
Existing
Hedges)
(1,4)
2012
2013
2014
Henry
Hub
Natural
Gas
($/MMbtu)
(2)
+ $1/Mmbtu
$(65)
$120
$490
-
$1/Mmbtu
$75
$(100)
$(430)
NiHub ATC Energy Price
+ $5/MWh
$5
$85
$280
-
$5/MWh
$(5)
$(85)
$(275)
PJM-W ATC Energy Price
(2)
+ $5/MWh
$(15)
$80
$190
-
$5/MWh
$15
$(80)
$(185)
NYPP Zone A ATC Energy Price
+ $5/MWh
$5
$10
$45
-
$5/MWh
$(5)
$(10)
$(45)
Nuclear Capacity Factor
(3)
+/-
1%
+/-
$15
+/-
$40
+/-
$40
2012 2Q Earnings Release Slides
(1) Based on June 29, 2012 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. (2) Excludes Maryland assets to be divested.
(3) Includes CENG Joint Venture (4) Sensitivities based on commodity exposure which includes open generation
and all committed transactions.
|
13
Exelon Generation Hedged Gross Margin Upside/Risk
6,000
6,500
7,000
7,500
8,000
8,500
9,000
9,500
10,000
2014
2013
2012
$8,200
$7,900
$8,700
$7,800
$9,300
$6,900
2012 2Q Earnings Release Slides
(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 2013 and 2014 do
not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or
optimization processes for those years. The price distributions that generate
this range are calibrated to market quotes for power, fuel, load following products, and options as of June 29, 2012
(2) Gross Margin Upside/Risk based on commodity exposure which includes open
generation and all committed transactions. (3) Excludes Maryland assets to be divested.
|
14
Illustrative Example of Modeling Exelon
Generation
2013 Gross Margin
Row
Item
Midwest
Mid-
Atlantic
ERCOT
New York
New
England
South,
West &
Canada
(A)
Start with fleet-wide open gross margin
$5.4 billion
(B)
Expected Generation (TWh)
97.6
73.6
17.8
13.6
14.3
(C)
Hedge % (assuming mid-point of range)
81.5%
79.5%
71.5%
86.5%
80.5%
(D=B*C)
Hedged Volume (TWh)
79.5
58.5
12.7
11.9
11.7
(E)
Effective Realized Energy Price ($/MWh)
$39.00
$49.00
$7.00
$37.00
$7.00
(F)
Reference Price ($/MWh)
$28.85
$36.25
$7.44
$31.45
$4.93
(G=E-F)
Difference ($/MWh)
$10.15
$12.75
($0.44)
$5.55
$2.07
(H=D*G)
$810 million
$745 million
($5) million
$65 million
$25 million
(I=A+H)
Hedged Gross Margin ($ million)
$7,050 million
(J)
Power New Business / To Go ($ million)
$550 million
(K)
Non-Power Margins Executed ($ million)
$100 million
(L)
Non-Power New Business / To Go ($ million)
$500 million
(N=I+J+K+L)
Total Gross Margin
$8,200 million
(1) Mark-to-market rounded to the nearest $5 million.
2012 2Q Earnings Release Slides
Mark-to-market
value
of
hedges
($
million)
(1) |
15
Additional 2012 ExGen Modeling
P&L Item
2012
Stub
(1)
Estimate
2012
Full-Year
(2)
Estimate
O&M
(3)
$4,000M
$4,250M
Taxes Other Than Income (TOTI)
$300M
$300M
Depreciation & Amortization
(4)
$650M
$700M
Interest Expense
$300M
$350M
2012 2Q Earnings Release Slides
Stub period represents estimates for March 12 December 31, 2012 and is
reflected as part of ExGens 2012 earnings guidance
Full-year estimates provided for modeling purposes.
ExGen O&M does not include CENG O&M of ~$350M in the stub
estimate. CENG O&M will be reflected under Equity earnings of unconsolidated affiliates in the Income Statement. In
addition, we have removed the impact from O&M related to entities
consolidated solely as a result of the application of FIN 46R. Our 2012 earnings guidance (prior or current) is not impacted
by this change to O&M since the application of FIN 46R does not impact net
income. ExGen D&A does not include
CENG D&A of ~$100M in the stub estimate. CENG D&A will be reflected under Equity earnings of unconsolidated affiliates in the Income Statement.
(1)
(2)
(3)
(4) |
ComEd Load Trends
4Q12
3Q12
2Q12
1Q12
4Q11
3Q11
2Q11
1Q11
Gross Metro Product
Residential
Large C&I
All Customer Classes
2011
2Q12 2012E
(3)
Average Customer Growth
0.4%
0.3%
0.3%
Average Use-Per-Customer
(1.7)%
(3.0)%
(1.7)%
Total Residential
(1.3)%
(2.7)% (1.4)%
Small C&I
(0.8)%
(1.8)%
(0.2)%
Large C&I
0.6%
0.4%
(0.4)%
All Customer Classes
(0.5)%
(1.3)%
(0.6)%
Weather-Normalized Electric Load Year-over-Year
Key Economic Indicators
Weather-Normalized Electric Load
(1)
Source: U.S. Dept. of Labor (June 2012) and Illinois
Department of Security (June 2012)
(2)
Source: Global Insight (May 2012)
(3)
Not adjusted for leap year
Chicago
U.S.
Unemployment
rate
(1)
8.6%
8.2%
2012 annualized growth in
gross
domestic/metro
product
(2)
1.7%
2.2% 16
2012 2Q Earnings Release Slides
-3%
-2%
-1%
0%
1%
2%
3%
Notes: C&I = Commercial & Industrial.
ComEd load activity impacts net income to the extent that it does not result in
an ROE outside of the collar, which ensures that the earned ROE is within 0.5% of the allowed ROE. |
17
PECO Load Trends
4Q12
3Q12
2Q12
1Q12
4Q11
3Q11
2Q11
1Q11
Large C&I
All Customer Classes
Gross Metro Product
Residential
Note: C&I = Commercial & Industrial
2011
2Q12 2012E
(3)
Average Customer Growth
0.3%
0.4%
0.5%
Average Use-Per-Customer
1.3%
(1.0)%
(2.1)%
Total Residential
1.7%
(0.7)% (1.7)%
Small C&I
(0.7)%
(1.9)%
(3.2)%
Large C&I
(3.3)%
(4.9)%
(1.8)%
All Customer Classes
(0.9)%
(2.7)%
(2.0)%
Weather-Normalized Electric Load Year-over-Year
Key Economic Indicators
Weather-Normalized Electric Load
(1)
Source:
U.S.
Dept.
of
Labor
(June
2012)
-
US
US
Dept
of
Labor
prelim.
data
(June
2012)
-
Philadelphia
(2)
Source: Global Insight (May 2012)
(3)
Not adjusted for leap year
Philadelphia
U.S.
Unemployment
rate
(1)
7.8%
8.2%
2012
annualized
growth
in
gross
domestic/metro
product
(2)
1.4%
2.2%
2012 2Q Earnings Release Slides
-8%
-6%
-4%
-2%
0%
2%
4% |
Sufficient Liquidity
(1)
Excludes commitments from Exelons Community and Minority Bank Credit
Facility. (2)
Available Capacity Under Facilities represents the unused commitments under the
borrowers credit agreements net of outstanding letters of credit and facility draws. The amount of commercial
paper outstanding does not reduce the available capacity under the credit
agreements. (3)
Includes Exelon Corporates $500M credit facility and legacy Constellation
credit facilities assumed as part of the merger, letters of credit and commercial paper outstanding. Exelon will be
unwinding the $4B in credit facilities assumed from legacy Constellation over
the remainder of the year. (3)
($ in Millions)
Available Capacity Under Bank Facilities as of July 27, 2012
Exelon Corp, ExGen, PECO and BGE facilities will be amended and extended to
to align maturities of Exelon facilities and secure liquidity and
pricing through 2017 18
2012 2Q Earnings Release Slides
Aggregate Bank Commitments
(1)
600
1,000
600
5,600
10,640
Outstanding Facility Draws
--
--
--
--
--
Outstanding Letters of Credit
(1)
(1)
(1)
(1,793)
(2,317)
Available Capacity Under Facilities
(2)
599
999
599
3,807
8,323
Outstanding Commercial Paper
(35)
(256)
--
--
(462)
Available Capacity Less Outstanding
Commercial Paper
564
743
599
3,807
7,861 |
19
ComEd Distribution Rate Case Update
2011 Formula Rate Filing (Docket # 11-0721 filed 11/8/11; rates eff. June
2012):
Based on 2010 calendar year costs and 2011 net plant additions
Supported $59M distribution revenue requirement reduction
10.05% ROE (2010 Treasury yield of 4.25% + 580 basis point risk premium)
ICC Final Order (issued 5/30/12):
$168M revenue requirement reduction; incremental reduction includes:
~$50M related to costs ICC determined should be recovered through
alternative
rate
recovery
tariffs
or
reflected
in
reconciliation
proceeding; primarily
delays timing of cash flows
~$35M reflects disallowance of return on pension asset
~$10M reflects incentive compensation related adjustments
~$15M reflects various adjustments for cash working capital, operating reserves
and other technical items
ComEd requested and the ICC granted expedited rehearing on the pension,
interest rate, and average rate base issues; Commission Final Order
expected by Sept. 19. 2012 Formula Rate Filing (Docket # 12-0321
filed 4/30/12, rates eff. Jan 2013)
2012 plan year based on 2011 actual costs and 2012 net plant additions
9.71% ROE (2011 Treasury yield of 3.91% + 580 basis point risk
premium)
Reconciled 2011 revenue requirements in effect to 2011 actual costs
incurred 9.81%
ROE
(3.91%
plus
590
basis
point
risk
premium)
(1)
Initial filing supported $106M distribution revenue requirement increase
relative to Dec. 2012 rates as ComEd initially proposed. When
factoring in 5/30/12 order for #11-0721, ComEd proposed a $34M
reduction
Received staff and intervener testimony on 7/17/12
Staff proposes an additional $35M reduction beyond ComEds filing
ICC order by year end; rates effective January 2013
Summary of Filings
2010
2011
2012
J
F
M
A
M
J
J
A
S
O
N
D
J
F
M
A
M
J
J
A
S
O
N
D
J
F
M
A
M
J
J
A
S
O
N
D
Costs used for filing
Plant additions used for filing
Formula rate filing
Rates in effect
2011
2012
2013
J
F
M
A
M
J
J
A
S
O
N
D
J
F
M
A
M
J
J
A
S
O
N
D
J
F
M
A
J
J
A
S
O
N
D
Costs used for filing
Plant additions used for filing
Formula rate filing
Rates in effect
(1) 590 basis point premium applies only to 2011 revenue reconciliation.
All subsequent revenue reconciliations will assume a 580 basis point premium.
2012 2Q Earnings Release Slides |
20
BGE Rate Case Overview
Rate Case Request
Electric
Gas
Docket #
9299
Test Year
October 2011
September 2012
Common Equity Ratio
48.4%
Requested Returns
ROE: 10.5%; ROR: 8.02%
Rate Base
$2.7B
$1B
Revenue Requirement Increase
$151M
$53M
Proposed Distribution Price
Increase as % of overall bill
4%
7%
2012
2013
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
New Rates Effective
Final Order Expected
Hearings
Filed
7/27/12
Timeline
2012 2Q Earnings Release Slides |
21
ComEd Operating EPS Contribution
Key
Drivers
2Q12
vs.
2Q11
(1)
Impacts of the 2012 distribution formula
rate order under the Energy Infrastructure
Modernization Act: $(0.07)
Share differential: $(0.04)
One-time impacts of the 2011 distribution
rate case order: $(0.03)
Weather: $0.01
2Q12
Actual
Actual
Normal
Heating Degree-Days 823
544 765
Cooling Degree-Days 237
423
218 2Q11
$0.26
$0.15
$0.17
$0.05
YTD
2Q
2012
2011
2012 2Q Earnings Release Slides
(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.
|
22
PECO Operating EPS Contribution
Key
Drivers
2Q12
vs.
2Q11
(1)
Share
differential:
$(0.03)
2Q12
Actual
Actual
Normal
Heating Degree-Days
331 337 463
Cooling Degree-Days 494
430
348 2Q11
$0.32
$0.13
$0.23
$0.10
YTD
2Q
2011
2012
2012 2Q Earnings Release Slides
(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.
|
23
2Q GAAP EPS Reconciliation
Three Months Ended June 30, 2012
ExGen
ComEd
PECO
BGE
Other
Exelon
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.47
$0.05
$0.10
$0.02
$(0.02)
$0.61
Mark-to-market impact of economic hedging activities
0.14
-
-
-
0.00
0.15
Unrealized losses related to nuclear decommissioning trust funds
(0.02)
-
-
-
-
(0.02)
Plant retirements and divestitures
0.00
-
-
-
-
0.00
Constellation merger and integration costs
(0.07)
-
(0.00)
(0.00)
(0.01)
(0.08)
Amortization of commodity contract intangibles
(0.33)
-
-
-
-
(0.33)
Amortization of the fair value of certain debt
0.00
-
-
-
-
0.00
Reassessment of state deferred income taxes
-
-
-
-
0.00
0.00
2Q 2012 GAAP Earnings (Loss) Per Share
$0.19
$0.05
$0.09
$0.01
$(0.02)
$0.33
NOTE: All amounts shown are per Exelon share and represent contributions
to Exelon's EPS. Amounts may not add due to rounding. Three Months Ended
June 30, 2011 ExGen
ComEd
PECO
Other
Exelon
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.79
$0.15
$0.13
$(0.01)
$1.05
Mark-to-market impact of economic hedging activities
(0.12)
-
-
-
(0.12)
Unrealized gains related to nuclear decommissioning trust funds
0.01
-
-
-
0.01
Plant retirements and divestitures
(0.02)
-
-
-
(0.02)
Recovery of costs pursuant to the 2011 distribution rate case order
-
0.03
-
-
0.03
Constellation merger and integration costs
-
-
-
(0.02)
(0.02)
2Q 2011 GAAP Earnings (Loss) Per Share
$0.67
$0.17
$0.03
$(0.03)
$0.93
2012 2Q Earnings Release Slides |
24
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. Six Months Ended
June 30, 2012 ExGen
ComEd
PECO
BGE
Other
Exelon
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.03
$0.17
$0.23
$0.04
$(0.03)
$1.44
Mark-to-market impact of economic hedging activities
0.20
-
-
-
0.01
0.21
Unrealized gains related to nuclear decommissioning trust funds
0.02
-
-
-
-
0.02
Plant retirements and divestitures
(0.01)
-
-
-
-
(0.01)
Constellation merger and integration costs
(0.13)
(0.00)
(0.01)
(0.00)
(0.09)
(0.23)
Maryland commitments
(0.03)
-
-
(0.11)
(0.16)
(0.29)
Amortization of commodity contract intangibles
(0.46)
-
-
-
-
(0.46)
FERC settlement
(0.22)
-
-
-
-
(0.22)
Reassessment of state deferred income taxes
0.02
-
-
-
0.14
0.16
Amortization of the fair value of certain debt
0.00
-
-
-
-
0.00
Other acquisition costs
(0.00)
-
-
-
(0.00)
YTD 2012 GAAP Earnings (Loss) Per Share
$0.43
$0.17
$0.22
$(0.07)
$(0.13)
$0.62
Six Months Ended June 30, 2011
ExGen
ComEd
PECO
Other
Exelon
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.69
$0.26
$0.32
$(0.04)
$2.22
Mark-to-market impact of economic hedging activities
(0.25)
-
-
-
(0.25)
Unrealized gains related to nuclear decommissioning trust funds
0.04
-
-
-
0.04
Plant retirements and divestitures
(0.04)
-
-
-
(0.04)
Non-cash charge resulting from health care legislation
(0.03)
(0.01)
-
-
(0.04)
Recovery of costs pursuant to the 2011 distribution rate case order
-
0.03
-
-
0.03
Constellation merger and integration costs
-
-
-
(0.02)
(0.02)
YTD 2011 GAAP Earnings (Loss) Per Share
$1.41
$0.28
$0.26
$(0.07)
$1.94
2012 2Q Earnings Release Slides |
GAAP to Operating Adjustments
25
Exelons 2012 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 Financial impacts
associated with the planned retirement of fossil generating units
Certain costs related to the Constellation merger and integration
initiatives Costs incurred as part of Maryland commitments in connection
with the merger Non-cash amortization of intangible assets, net,
related to commodity contracts recorded at fair value at the merger
date Costs incurred as part of a March 2012 settlement with the Federal
Energy Regulatory Commission (FERC) related to Constellations
prior period hedging and risk management transactions Revenues and
operating expenses related to three generation facilities required to be sold within 180
days of the merger
Non-cash benefit associated with a change in state deferred tax rates
resulting from a reassessment of anticipated apportionment of
Exelons deferred taxes as a result of the merger Non-cash
amortization of certain debt recorded at fair value at the merger date expected to be retired in
2013
Certain costs incurred associated with other acquisitions
Significant impairments of assets, including goodwill
Other unusual items
Significant changes to GAAP
Operating
earnings
guidance
assumes
normal
weather
for
remainder
of
the
year
2012 2Q Earnings Release Slides |