Attached files
| file | filename |
|---|---|
| EX-99.3 - EARNINGS CONFERENCE CALL PREPARED REMARKS - EXELON CORP | d714414dex993.htm |
| EX-99.1 - PRESS RELEASE AND EARNINGS RELEASE ATTACHMENTS - EXELON CORP | d714414dex991.htm |
| 8-K - FORM 8-K - EXELON CORP | d714414d8k.htm |
 Earnings Conference Call
1
st
Quarter
2014
April 30, 2014
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) Exelon’s 2013 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 22; (2) Exelon’s First Quarter 2014 Quarterly
Report on Form 10-Q (to be filed on April 30, 2014) 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 15; and (3) 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 |
 Q1 2014 In Review
2014 1Q Earnings Release Slides
2
Q1 Highlights
Adjusted Operating EPS Results
(1,2)
•
Signs of Power Market Recovery
•
Winter Storms
•
Nuclear capacity factor: 94.1%
•
CENG License Transfer
•
ProLiance Acquisition
Regulatory Advocacy
•
PJM Capacity Market Reforms
o
Imports
o
Demand Response
o
Speculation
•
Educating Stakeholders on Nuclear
Economics
ExGen
BGE
ComEd
PECO
Q1 2014
$0.62
$0.30
$0.11
$0.10
$0.10
(1)
(2)
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.
Amounts may not add due to rounding. |
 Spot and Forward Market Volatility
2014 1Q Earnings Release Slides
3
Q1 2014 Saw Increased Volatility
Forward Markets Reacted To Spot Prices
•
Forward markets have a tendency to reflect spot market
activity
•
While forward hub natural gas prices stayed relatively flat
during the quarter, we saw a significant increase in power
prices and therefore heat rates in 2015 and 2016
•
This was especially true for PJM West Hub and the largest
impacts were due to the pricing of forward winter months
•
The spot market so far in 2014 has been very volatile
•
Polar vortex resulted in extreme conditions:
•
The spot prices in PJM started to reflect the changing nature of
the grid and new reliance on different resources such as
natural gas supply, demand response, and oil peakers
•
Even if extreme days are taken out, 2014 saw higher prices at
NiHub than previous years
$100
$90
$80
$70
$60
$50
$40
$30
$0
Daily Heating Degree Days
2014
2013
2012
NiHub LMP per Daily HDD
(Days below $100/MWh)
7/1/2013
12.0
11.5
11.0
10.5
10.0
9.5
9.0
0.0
4/1/2014
1/1/2014
4/1/2013
10/1/2013
NiHub On Peak HR -
2016
NiHub On Peak HR -
2015
Whub On Peak HR -
2016
Whub On Peak HR -
2015
0
5
10
15
20
25
30
35
40
45
50
55
60
65
70 |
 Capacity Market Developments
2014 1Q Earnings Release Slides
4
New England
During
first
quarter,
Forward
Capacity
Auction
(FCA)
#8
for
planning
year
17/18
cleared
significantly
higher
than
last
auction.
Rest
of
Pool
cleared $7.025/kw-month and NEMA cleared $15.00/kw-month
Clearing results are indicative of a tighter supply/demand situation after the
announcement of unit retirements FCA #9 will feature a sloped demand
curve for Rest of Pool resulting in a more stable market design A
vertical demand curve for constrained zones (i.e., NEMA) remains in place until FCA #10
FERC is expected to rule on the ISO’s proposed Performance Incentives
Forward Capacity Market redesign by mid-May New York ISO
NYISO’s Summer Strip Auction cleared higher year-over-year for
both Rest of State (ROS) and NYC Beginning in May 2014 Lower Hudson
Valley (LHV) has been broken out from ROS as a separate capacity zone to enhance reliability
MISO
MISO’s 2 annual capacity auction cleared higher
year-over-year but is still lower than recent results in neighboring PJM RTO
We are evaluating recent reports and studies that are showing a tighter
supply/demand picture in several MISO zones as plants retire PJM
– RPM rule/market design changes
Change in DR clearing mechanism which limits total volume of Limited DR and
aggregate Sub-Annual products consistent with reliability limits
Standardization of demand response capacity sales plans that require Officer
Certification of intent to deliver Steam units required to apply
temperature correction to establish Installed Capacity (ICAP) ratings
Limits on imports into RTO subject to a “pseudo-tie exemption” FERC is expected to rule on PJM’s proposed
speculation reforms before the auction opens nd
|
 Hedging Activity and Market Fundamentals
5
Fundamental
View
vs.
Market
-
2015
2015: Rotating into a Large Heat Rate Strategy
(1)
Mid-point of disclosed total portfolio hedge % range was used
2015-Actual (excl NG hedges)
2015-Ratable
2015-Actual
•
We align our hedging strategies with our fundamental
views by leaving portfolio exposure to power price upside
•
As forward heat rates have moved, we have shifted
between our two strategies of falling behind ratable and
hedging with Natural Gas
•
When considering our behind ratable and cross commodity
strategies, we have left a significant amount of our portfolio
open to moves in the power market:
•
Approximately 45% open in 2015
•
Approximately 70% open in 2016
We are deploying a behind ratable strategy and a cross-commodity position
in order to leave exposure to power upside
4Q12
3Q12
1Q14
4Q13
3Q13
2Q13
1Q13
•
Structural changes in the stack and weather drove higher
prices and volatility in the spot energy market during Q1
•
The forward market has incorporated some of the upside
especially for PJM West Hub and more so in winter
months
•
We expect further upside in NiHub forward heat rates
based on our fundamental forecast given current natural
gas prices, expected retirements, new generation
resources, and load assumptions
$60
$55
$50
$45
$40
$35
$15
1Q14
4Q13
3Q13
2Q13
1Q13
4Q12
3Q12
2Q12
1Q12
4Q11
3Q11
2Q11
1Q11
Market PJMW
Fundamental View PJMW
Market NiHub
Fundamental View NiHub
2014 1Q Earnings Release Slides
10%
20%
30%
40%
50%
60%
70%
80% |
 Exelon Generation: Gross Margin Update
March 31, 2014
Change from Dec 31, 2013
Gross Margin Category ($M)
(1)
2014
2015
2016
2014
2015
2016
Open Gross Margin
(3)
(including South, West, Canada hedged gross
margin)
7,350
6,350
6,250
1,500
650
600
Mark-to-Market of Hedges
(3,4)
(700)
100
100
(1,450)
(400)
(150)
Power New Business / To Go
250
600
650
(100)
(50)
(50)
Non-Power Margins Executed
250
100
50
150
50
-
Non-Power New Business / To Go
150
300
350
(150)
(50)
-
7,300
7,450
7,400
(50)
200
400
2014 1Q Earnings Release Slides
•
Severe weather in our load serving regions led to significant power and gas
volatility, which allowed
us
to
execute
on
a
significant
piece
of
our
new
business
targets
•
Our balanced generation to load strategy, as well as our geographic and
commodity diversity, allowed us to navigate through several offsetting
issues •
The return of volatility to the markets may lead to more appropriate pricing of
risk premiums Recent Developments
6
1)
Gross margin categories rounded to nearest $50M.
2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less
purchased power and fuel expense, excluding revenue related to
decommissioning, gross receipts tax, Exelon Nuclear Partners and
variable interest entities. Total Gross Margin is also net of direct cost of sales for
certain Constellation businesses. See Slide 25 for a Non-GAAP to GAAP
reconciliation of Total Gross Margin.
3)
Includes Exelon’s proportionate ownership share of the CENG Joint
Venture.
4)
Mark to Market of Hedges assumes mid-point of hedge percentages. |
 Key Financial Messages
•
Delivered adjusted (non-GAAP)
operating earnings in Q1 of
$0.62/share within guidance range
provided of $0.60-$0.70/share
Q1 2014 vs. Q1 2013:
•
Utilities
–
Increased distribution revenue
–
Increased storm costs
•
ExGen
–
Lower realized gross margin
–
Increased capacity pricing
2014 1Q Earnings Release Slides
7
Expect
Q2
2014
earnings
of
$0.40
-
$0.50/share
and
re-affirm
full-year
guidance
range
of $2.25
-
$2.55/share
(2)
HoldCo
ExGen
ComEd
PECO
BGE
Q1 2013
$0.70
Q1 2014
$0.62
-$0.02
$0.39
$0.10
$0.14
$0.09
$0.30
$0.11
$0.10
$0.10
Adjusted Operating EPS Results
(1,3)
(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)
2014 earnings guidance based on expected average outstanding shares of
~860M. Refer to Appendix for a reconciliation of adjusted (non-GAAP operating EPS guidance to GAAP EPS )
(3)
Amounts may not add due to rounding.
2014 1Q Earnings Release Slides |
 Exelon Utilities Adjusted Operating EPS Contribution
(1)
BGE
(+0.01):
•
Increased distribution revenue due to rate cases: $0.03
•
Increased storm costs: $(0.01)
PECO
(-0.04):
•
Increased storm costs, primarily due to the February 5,
2014 ice storm: $(0.05)
•
Weather: $0.02
ComEd
(+0.01):
•
Weather
(2)
: $0.01
•
Increased distribution revenue due to increased capital
investment
and
higher
allowed
ROE
(2)
:
$0.01
•
Tax interest related to 1999-2001 IRS tax settlement
adjustment recorded in the first quarter of 2013: ($0.01)
2014 1Q Earnings Release Slides
$0.33
$0.09
$0.14
$0.10
Q1 2014
$0.31
$0.10
$0.10
$0.11
Q1 2013
ComEd
PECO
BGE
8
Numbers may not add due to rounding.
(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)
Due to the distribution formula rate, changes in ComEd’s earnings are
driven primarily by changes in 30-year U.S. Treasury rates (allowed ROE), rate base and capital structure in addition to
weather, load and changes in customer mix.
Key Drivers –
Q1 2014 vs. Q1 2013: |
 ExGen Adjusted Operating EPS Contribution
(1)
2014 1Q Earnings Release Slides
Q1 2014
2014
2013
(excludes Salem and CENG)
Q1 2013
Actual
Q1 2014
Actual
Planned Refueling Outage Days
49
52
Non-refueling Outage Days
6
20
Nuclear Capacity Factor
96.4%
94.1%
•
Lower realized energy prices and higher
procurement costs for replacement power $(0.09)
•
Decrease in nuclear and fossil output in 2014,
primarily due to outage days $(0.05)
•
Higher nuclear fuel amortization and fossil fuel
costs $(0.04)
•
Partially offset by increased capacity pricing $0.08
9
(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.
Key Drivers –
Q1 2014 vs. Q1 2013 |
 2014 Projected Sources and Uses of Cash
Key
Messages
•
Cash from Operations is projected to be $6,200M vs Plan of
$6,100M for a $100M variance. This variance is driven by:
$150M Reclassification of CENG capital expenditure at EXC
ownership
($50M) Lower Constellation gross margin due to plant
underperformance
•
Cash from Financing activities is projected to be equal to Plan
of ($825M)
•
Cash from Investing activities is projected to be ($5,375M) vs
Plan of ($5,475M) for a $100M variance. This variance is driven
by:
$325M early lease termination fee received at Corporate from the
City of San Antonio Public Service (“CPS”)
($150M) Reclassification of CENG Capital Expenditure at EXC
ownership
($50M) Higher PECO CapEx primarily due to January Ice Storm
($25M) ExGen:
additional turbine purchases at Fourmile wind, CENG
capital at ownership, and gas and hydro.
Projected
Sources
&
Uses
(1)
Excludes counterparty collateral of $134 million at 12/31/2013. In addition, the
12/31/2014 ending cash balance does not include collateral.
(2)
Adjusted Cash Flow from Operations (non-GAAP) primarily includes net cash
flow from operating activities and net cash flows
from investing activities excluding capital expenditures of $5.4B for 2014. For
March 31, 2014, includes EDF’s proportionate ownership share of CENG
Joint Venture CapEx and Nuclear Fuel. For December 31, 2013, includes 100% of CENG Joint
Venture CapEx and Nuclear Fuel.
(3)
For March 31, 2014, excludes EDF’s proportionate ownership share of CENG
Joint Venture CapEx and Nuclear Fuel. For December 31, 2013,
excludes 100% of CENG Joint Venture CapEx and Nuclear Fuel.
(4)
Dividends are subject to declaration by the Board of Directors.
(5)
“Other”
includes
CENG
distribution
to
EDF,
proceeds
from
stock
options,
and
expected
changes in short-term debt.
(6)
Includes cash flow activity from Holding Company, eliminations, and other
corporate entities. CapEx for Exelon is shown net of $325M CPS early
lease termination fee. (7)
All amounts rounded to the nearest $25M.
(8)
Net 2014 sources and uses for each operating company are expected to be $0M,
$325M, $100M and $600M for BGE, ComEd, PECO and ExGen, respectively
2014 1Q Earnings Release Slides
10
($ in millions)
BGE
ComEd
PECO
ExGen
Exelon
(6)
As of 4Q13
Variance
1,475
1,475
675
1,425
600
3,475
6,200
6,100
100
(525)
(1,575)
(500)
(1,175)
(3,475)
(3,675)
200
n/a
n/a
n/a
(975)
(975)
(900)
(75)
(1,075)
(1,075)
n/a
n/a
n/a
(150)
(150)
(150)
n/a
n/a
n/a
(75)
(75)
(75)
n/a
n/a
n/a
(200)
(200)
(200)
n/a
n/a
n/a
(50)
(50)
(25)
(25)
(75)
(200)
(175)
n/a
(450)
(450)
950
300
1,250
1,200
50
(625)
(250)
(525)
(1,375)
(1,375)
n/a
n/a
n/a
675
675
675
Adjusted Cash Flow from
Operations
(3)
CapEx (excluding other items below):
(3)
Nuclear Fuel
Dividend
(4)
Nuclear Uprates
Wind
Solar
Upstream
Utility Smart Grid/Smart Meter
Net Financing (excluding Dividend):
Debt Issuances
Debt Retirements
Project Finance/Federal Financing
Bank Loan
Other
(5)
(75)
350
125
(400)
(300)
(250)
(50)
1,475
1,275
200
(7)
(7,8)
(2) |
 Exelon Generation Disclosures
March 31, 2014
2014 1Q Earnings Release Slides
11
2014 1Q Earnings Release Slides |
 Portfolio Management Strategy
Protect Balance Sheet
Ensure Earnings Stability
Create Value
Exercising Market Views
Purely ratable
Actual hedge %
Market views on timing, product
allocation and regional spreads
reflected in actual hedge %
High End of Profit
Low End of Profit
% Hedged
Open Generation
with LT Contracts
Portfolio Management &
Optimization
Portfolio Management Over Time
Align Hedging & Financials
Establishing Minimum Hedge Targets
2014 1Q Earnings Release Slides
12
Credit Rating
Capital &
Operating
Expenditure
Dividend
Capital
Structure
•
Aligns hedging program with
financial policies and financial
outlook
•
Establish minimum hedge
targets to meet financial
objectives of the company
(dividend, credit rating)
•
Hedge enough commodity risk to
meet future cash requirements
under a stress scenario
•
Ensure stability in near-term cash
flows and earnings
•
Disciplined approach to hedging
•
Tenor aligns with customer
preferences and market liquidity
•
Multiple channels to market that
allow us to maximize margins
•
Large open position in outer
years to benefit from price upside
•
Ability to exercise fundamental
market views to create value within
the ratable framework
•
Modified timing of hedges
versus purely ratable
•
Cross-commodity hedging (heat
rate positions, options, etc.)
•
Delivery locations, regional and
zonal spread relationships
Strategic Policy Alignment
Three-Year Ratable Hedging
Bull / Bear Program |
 Components of Gross Margin Categories
2014 1Q Earnings Release Slides
13
Gross margin linked to power production and sales
Gross margin from
other business activities
Open Gross
Margin
MtM of
Hedges
(2)
“Power”
New
Business
“Non Power”
Executed
“Non Power”
New Business
Margins move from new business to MtM of hedges over
the course of the year as sales are executed
(5)
Margins move from “Non power new business”
to
“Non power executed”
over the course of the year
Load Response
Energy Efficiency
(4)
BGE Home
(4)
Distributed Solar
Portfolio
Management /
origination fuels
new business
Proprietary
Trading
(3)
Retail, Wholesale
executed gas sales
Load Response
Energy Efficiency
(4)
BGE Home
(4)
Distributed Solar
Retail, Wholesale
planned electric
sales
Portfolio
Management new
business
Mid marketing new
business
Mark to Market
(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
Effective Realized
Energy Price
(EREP), reference
price, hedge %,
expected
generation
Generation Gross
Margin at current
market prices,
including capacity
and ancillary
revenues, nuclear
fuel amortization
and fossils fuels
expense
Exploration and
Production
(4)
Power Purchase
Agreement (PPA)
Costs and
Revenues
Provided at a
consolidated level
for all regions
(includes hedged
gross margin for
South, West and
Canada
(1)
)
(1) Hedged
gross
margins
for
South,
West
and
Canada
region
will
be
included
with
Open
Gross
Margin,
and
no
expected
generation,
hedge
%,
EREP
or
reference
prices
provided
for
this
region.
(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.
(4)
Gross
margin
for
these
businesses
are
net
of
direct
“cost
of
sales”.
(5)
Margins
for
South,
West
&
Canada
regions
and
optimization
of
fuel
and
PPA
activities
captured
in
Open
Gross
Margin.
Retail, Wholesale
planned gas sales |
 ExGen Disclosures
Gross Margin Category ($M)
(1)
2014
2015
2016
Open Gross Margin
(including South, West & Canada hedged GM)
(3)
7,350
6,350
6,250
Mark to Market of Hedges
(3,4)
(700)
100
100
Power New Business / To Go
250
600
650
Non-Power Margins Executed
250
100
50
Non-Power New Business / To Go
150
300
350
Total
Gross
Margin
(2)
7,300
7,450
7,400
2014 1Q Earnings Release Slides
14
Gross margin categories rounded to nearest $50M.
Total Gross Margin (Non-GAAP) is defined as operating revenues less
purchased power and fuel expense, excluding revenue related to
decommissioning, gross receipts tax, Exelon Nuclear Partners and
variable interest entities. Total Gross Margin is also net of direct cost of
sales for certain Constellation businesses. See Slide 25 for a Non-GAAP to
GAAP reconciliation of Total Gross Margin.
Includes Exelon’s proportionate ownership share of the CENG Joint Venture.
Mark to Market of Hedges assumes mid-point of hedge percentages.
(4)
Based on March 31, 2014 market conditions.
(5)
(1)
(2)
(3)
Reference Prices
(5)
2014
2015
2016
Henry
Hub Natural Gas ($/MMbtu)
$4.58
$4.20
$4.15
Midwest: NiHub ATC prices ($/MWh)
$39.73
$31.82
$31.84
Mid-Atlantic: PJM-W ATC prices ($/MWh)
$54.44
$40.59
$39.45
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$8.76
$8.57
$7.69
New York: NY Zone A ($/MWh)
$53.86
$40.42
$38.16
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$4.08
$4.85
$2.90
2014 1Q Earnings Release Slides |
 ExGen Disclosures
Generation and Hedges
2014
2015
2016
Exp. Gen (GWh)
(1)
210,200
203,500
204,600
Midwest
97,300
96,700
97,700
Mid-Atlantic
(2)
75,000
70,800
71,800
ERCOT
16,400
19,000
19,200
New York
(2)
12,700
9,400
9,300
New England
8,800
7,600
6,600
% of Expected Generation Hedged
(3)
91-94%
64-67%
37-40%
Midwest
91-94%
66-69%
36-39%
Mid-Atlantic
(2)
90-93%
63-66%
37-40%
ERCOT
93-96%
61-64%
42-45%
New York
(2)
94-97%
65-68%
47-50%
New England
91-94%
53-56%
15-18%
Effective Realized Energy Price ($/MWh)
(4)
Midwest
$36.50
$32.50
$33.00
Mid-Atlantic
(2)
$49.00
$42.00
$43.00
ERCOT
(5)
$12.00
$7.00
$5.00
New York
(2)
$43.00
$43.50
$37.50
New England
(5)
$9.00
$4.00
$0.50
2014 1Q Earnings Release Slides
15
(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 14 refueling outages in 2014
and 2015 and 12 refueling outages in 2016 at Exelon-operated nuclear plants, Salem
and CENG. Expected generation assumes capacity factors of 93.6%,
93.3% and 94.4% in 2014, 2015 and 2016 at Exelon-operated nuclear plants excluding Salem and
CENG. These estimates of expected generation in 2015 and 2016 do not represent
guidance or a forecast of future results as Exelon has not completed its planning or
optimization processes for those years. (2) Includes Exelon’s
proportionate ownership share of CENG Joint Venture. (3) 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. (4) 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. (5) Spark spreads shown for ERCOT and New England.
2014 1Q Earnings Release Slides |
 ExGen Hedged Gross Margin Sensitivities
Gross Margin Sensitivities (With Existing Hedges)
(1, 2)
2014
2015
2016
Henry Hub Natural Gas ($/Mmbtu)
+ $1/Mmbtu
$60
$285
$490
-
$1/Mmbtu
$(55)
$(230)
$(455)
NiHub ATC Energy Price
+ $5/MWh
$20
$250
$380
-
$5/MWh
$(20)
$(245)
$(375)
PJM-W ATC Energy Price
+ $5/MWh
$10
$125
$220
-
$5/MWh
$-
$(120)
$(210)
NYPP Zone A ATC Energy Price
+ $5/MWh
$-
$15
$25
-
$5/MWh
$-
$(15)
$(25)
Nuclear Capacity Factor
(3)
+/-
1%
+/-
$50
+/-
$45
+/-
$45
2014 1Q Earnings Release Slides
16
(1) Based on March 31, 2014 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 price 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) Sensitivities
based on commodity exposure which includes open generation and all committed transactions.
(3) Includes Exelon’s proportionate ownership share of the CENG Joint
Venture. |
 Exelon Generation Hedged Gross Margin Upside/Risk
$5,000
$5,500
$6,000
$6,500
$7,000
$7,500
$8,000
$8,500
$9,000
$9,500
2016
$9,200
2015
$8,500
2014
$7,550
$7,000
$6,550
$5,950
2014 1Q Earnings Release Slides
17
(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
2014, 2015 and 2016 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 March 31, 2014 (2) Gross Margin Upside/Risk based
on commodity exposure which includes open generation and all committed transactions. (3) Gross
margin is defined as operating revenues less purchased power and fuel expense,
excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners and
variable interest entities . See Slide 25 for a Non-GAAP to GAAP
reconciliation of Gross Margin. |
 Illustrative Example of Modeling Exelon
Generation
2015 Gross Margin
Row
Item
Midwest
Mid-
Atlantic
ERCOT
New York
New
England
South,
West &
Canada
(A)
Start with fleet-wide open gross margin
$6.35 billion
(B)
Expected Generation (TWh)
96.7
70.8
19.0
9.4
7.6
(C)
Hedge % (assuming mid-point of range)
67.5%
64.5%
62.5%
66.5%
54.5%
(D=B*C)
Hedged Volume (TWh)
65.3
45.7
11.9
6.3
4.1
(E)
Effective Realized Energy Price ($/MWh)
$32.50
$42.00
$7.00
$43.50
$4.00
(F)
Reference Price ($/MWh)
$31.82
$40.59
$8.57
$40.42
$4.85
(G=E-F)
Difference ($/MWh)
$0.68
$1.41
$(1.57)
$3.08
$(0.85)
(H=D*G)
Mark-to-market value of hedges ($ million)
(1)
$45 million
$65 million
$(20) million
$20 million
$(5) million
(I=A+H)
Hedged Gross Margin ($ million)
$6,450 million
(J)
Power New Business / To Go ($ million)
$600 million
(K)
Non-Power Margins Executed ($ million)
$100 million
(L)
Non-
Power New Business / To Go ($ million)
$300 million
(N=I+J+K+L)
Total Gross Margin
(2)
$7,450 million
(1)
Mark-to-market rounded to the nearest $5 million.
(2)
Total
Gross
Margin
(Non-GAAP)
is
defined
as
operating
revenues
less
purchased
power
and
fuel
expense,
excluding
revenue
related
to
decommissioning,
gross
receipts
tax,
Exelon
Nuclear
Partners and variable interest entities. Total Gross Margin is also net of
direct cost of sales for certain Constellation businesses. See Slide 25 for a Non-GAAP to GAAP reconciliation of Total
Gross Margin.
2014 1Q Earnings Release Slides
18 |
  Additional Disclosures
2014 1Q Earnings Release Slides
19
2014 1Q Earnings Release Slides |
 BGE
Strong residential growth drives the
load in 2014. Improving economic
conditions are offset by continued
energy efficiency
Exelon Utilities Weather-Normalized Load
2014E
0.5%
-0.4%
0.3%
0.2%
2013
-0.3%
-0.5%
0.0%
-0.2%
Large C&I
Small C&I
Residential
All Customers
ComEd
2014 overall load growth is slightly
above 2013 due to slowly improving
economic conditions with partially
offsetting energy efficiency
2014E
2.0%
-1.7%
0.2%
0.6%
2013
1.5%
-1.1%
0.0%
0.3%
PECO
2014 load growth is driven primarily
by Large C&I, partially offset by
Small C&I. Improved economic &
customer growth is partially offset
by energy efficiency
2014E
-0.1%
0.1%
1.6%
0.6%
2013
-3.2%
2.1%
2.0%
-0.6%
Chicago GMP
2.4%
Chicago Unemployment
8.2%
Philadelphia GMP
1.9%
Philadelphia Unemployment
7.1%
Baltimore GMP
2.4%
Baltimore Unemployment
6.2%
2014 1Q Earnings Release Slides
20
2014 1Q Earnings Release Slides
Notes: Data is not adjusted for leap year. Source of economic outlook data is Global Insight (February 2014). Assumes 2014 GDP of 2.7% and U.S unemployment of 6.7%.
ComEd has the ROE collar as part of the distribution formula rate and BGE is
decoupled which mitigates the load risk. QTD and YTD actual data can be found in earnings release tables.
BGE amounts have been adjusted for true-up load from prior
quarters.
|
 |
 Appendix
Reconciliation of Non-GAAP
Measures
22
2014 1Q Earnings Release Slides |
 Q1 2014 GAAP EPS Reconciliation
Three Months Ended March 31, 2014
ExGen
ComEd
PECO
BGE
Other
Exelon
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.30
$0.11
$0.10
$0.10
$-
$0.62
Mark-to-market impact of economic hedging activities
(0.52)
-
-
-
-
(0.52)
Unrealized gains related to NDT fund investments
0.01
-
-
-
-
0.01
Merger and integration costs
(0.01)
-
-
-
-
(0.01)
Amortization of commodity contract intangibles
(0.04)
-
-
-
-
(0.04)
Tax Settlements
0.04
-
-
-
-
0.04
Q1 2014 GAAP Earnings (Loss) Per Share
$(0.22)
$0.11
$0.10
$0.10
$-
$0.10
NOTE: All amounts shown are per Exelon share and represent contributions
to Exelon's EPS. Amounts may not add due to rounding. 2014 1Q
Earnings Release Slides 23
Three Months Ended March 31, 2013
ExGen
ComEd
PECO
BGE
Other
Exelon
2013 Adjusted (non-GAAP) Operating Earnings Per Share
$0.39
$0.10
$0.14
$0.09
$(0.02)
$0.70
Mark-to-market impact of economic hedging activities
(0.29)
-
-
-
0.01
(0.27)
Unrealized gains related to nuclear decommissioning trust funds
0.04
-
-
-
-
0.04
Plant retirements and divestitures
0.02
-
-
-
-
0.02
Merger and integration costs
(0.03)
-
(0.00)
0.00
0.00
(0.03)
Amortization of commodity contract intangibles
(0.14)
-
-
-
-
(0.14)
Amortization of the fair value of certain debt
0.00
-
-
-
-
0.00
Remeasurement of like-kind exchange tax position
-
(0.20)
-
-
(0.11)
(0.31)
Nuclear uprate project cancellation
(0.02)
-
-
-
-
(0.02)
Q1 2013 GAAP Earnings (Loss) Per Share
$(0.02)
$(0.09)
$0.14
$0.09
$(0.12)
$(0.01) |
 GAAP to Operating Adjustments
NOTE: All amounts shown are per Exelon share and represent contributions
to Exelon's EPS. Amounts may not add due to rounding. 2014 1Q
Earnings Release Slides 24
•
Exelon’s 2014 adjusted (non-GAAP) operating earnings excludes the
earnings effects of the following: Mark-to-market adjustments from
economic hedging activities Unrealized gains and losses from NDT fund
investments to the extent not offset by contractual accounting as
described in the notes to the consolidated financial statements Certain
costs incurred associated with the Constellation and CENG merger and integration initiatives
Non-cash amortization of intangible assets, net, related to commodity
contracts recorded at fair value at the merger date for 2014
Favorable settlements of certain income tax positions on Constellation’s
2009-2012 tax returns One-time impacts of adopting new accounting
standards Other unusual items |
 ExGen Total Gross Margin Reconciliation to GAAP
Total Gross Margin Reconciliation (in $M)
(5)
2014
2015
2016
Revenue
Net
of
Purchased
Power
and
Fuel
Expense
(1)(6)
$7,800
$8,050
$8,050
Non-cash amortization of intangible assets, net, related to
commodity
contracts
recorded
at
fair
value
at
the
merger
date
(2)
$50
-
-
Other Revenues
(3)
$(250)
$(300)
$(300)
Direct cost of sales incurred to generate revenues for certain
Constellation businesses
(4)
$(300)
$(300)
$(350)
Total Gross Margin (Non-GAAP, as shown on slide 14)
$7,300
$7,450
$7,400
2014 1Q Earnings Release Slides
25
(1)
Revenue net of purchased power and fuel expense (RNF), a non-GAAP measure,
is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased
power and fuel expense. ExGen does not forecast the GAAP components of
RNF separately. RNF also includes the RNF of our proportionate ownership share of CENG.
(2)
The exclusion from operating earnings for activities related to the merger with
Constellation ends after 2014.
(3)
Reflects revenues from Exelon Nuclear Partners, variable interest entities,
funds collected through revenues for decommissioning the former PECO nuclear plants through
regulated rates and gross receipts tax revenues.
(4)
Reflects the cost of sales and depreciation expense of certain Constellation
businesses of Generation.
(5)
All amounts rounded to the nearest $50M.
(6)
Excludes the impact of the operating exclusion for mark-to-market due
to the volatility and unpredictability of the future changes to power prices.
2014 1Q Earnings Release Slides |