Attached files
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| 8-K - 8-K - EXELON CORP | d815901d8k.htm |
 Edison Electric Institute
Financial Conference
November 12 –
13, 2014
Exhibit 99.1
*
*
*
*
*
*
*
*
*
* |
 1
2014 EEI Financial Conference
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 Third Quarter 2014 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 18; 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. |
 2
2014 EEI Financial Conference
Our Strategy
Exelon
Corporation
Exelon Utilities
Exelon Generation
Attributes
Value Drivers
Guiding Principle
Corresponding Actions
•
Regulated growth
•
Dividend stability
•
Operational excellence
•
Earnings growth
•
Dividend yield
•
Public policy advocacy
General Characteristics
Role & Focus
•
Provide dividend coverage and
stable earnings growth platform
•
Invest in regulated growth
opportunities
•
Competitive growth
•
Commodity exposure
•
Operational excellence
•
Free cash flow growth
•
Power prices/volatility
•
Public policy advocacy
•
Diversify business to provide
growth and reduce earnings
volatility
•
Invest in existing and adjacent
markets and introduce new
products and services
Exelon’s Strategy
Leverage the integrated business model to create value and
diversify our business |
 3
2014 EEI Financial Conference
Driving Value at Exelon Utilities
Providing Material EPS Accretion
(1)
Significant Rate Base Growth
(2)
Operational Excellence
Creating
the Leading Mid-Atlantic Utility
•
Continue first quartile operating performance in
areas such as reliability and customer satisfaction
•
Achieve financial performance targets
•
Leverage standardization, common platforms and
best practices across operating companies
•
Improved operational performance at ComEd,
PECO and BGE since the merger
IL
Chicago
$0.00
$0.90
$1.70
$1.60
$1.40
$1.30
$1.20
$1.50
$1.10
$1.00
2017
$1.55
2016
2015
$1.40
2014
$1.25
$1.50
$1.20
$1.25
$0.95
$1.10
$21.8
$23.2
$24.7
$8.1
$8.8
$9.6
$20.1
$34.3
+15%
2017
2016
$32.0
2015
$29.9
2014
+49%
Exelon
PHI
(1)
Earnings guidance is for Exelon Utilities only and does not include PHI
utilities (2)
Denotes year end rate base
$20.1 |
 4
2014 EEI Financial Conference
Driving Value at Exelon Generation
Capacity Prices
Capacity
Performance
Role of Demand
Response
Shift in Demand
Curve
Power Prices
Carbon
Heat Rates
Liquidity
Taking action to create value today while preparing for a different
future Guiding Principles:
Preserve the value of our core
business . . .
•
Operate the nuclear fleet safely and
reliably
•
Provide clean, reliable and affordable
energy
•
Manage portfolio through hedging and
generation to load matching
. . . while strategically growing and
diversifying the business
•
Leverage competencies for growth
•
Identify and capitalize on emerging
trends and technologies by being a first
mover
•
Invest in business diversification to
position the company for the future
•
Use full arsenal of financing tools |
 5
2014 EEI Financial Conference
IL -
Market Based Solution
Possible Market Based Solutions
Benefits of Exelon’s Fleet to Illinois
Note: 2015 Legislative timeline is illustrative
•
•
•
•
•
•
Illinois could enact legislation to create a Clean Energy
Standard (CES)
A CES is a requirement that all customers purchase a
minimum percentage of “clean”
generation. The concept is
similar to a Renewable Portfolio Standard with the distinction
that the set of resources which qualify under the CES include
all zero or low CO
2
emission generators
Clean energy credits would be traded in a similar fashion to
how renewable energy credits (RECs) are traded today
Illinois could enact legislation to create a carbon trading
program or join an existing program like the Regional
Greenhouse Gas Initiative (RGGI)
Carbon trading programs put a cap on carbon emissions
and each fossil fuel generator must submit a carbon
allowance for each tonne of carbon the plant emits
These allowances are traditionally auctioned with the
proceeds going to the state treasury. Some of the funds may
be provided to customers to offset any rate impacts or
dedicated to other energy-related programs |
 6
2014 EEI Financial Conference
Exelon is positioned for a strong future
Operational Excellence
Financial Strength
Portfolio Optimization
Strategic Diversification
Strong
Integrated
Business
Model
We
operate
our
nuclear
fleet
at
world
class
levels,
and
deliver
first
quartile
performance
at
the
utilities
We
maintain
a
strong
balance
sheet
and
the
ability
to
raise
and
deploy
capital
for
growth
We
manage
commodity
market
volatility
and
optimize
earnings
through
our
hedging
strategy
We
diversify
our
business
to
capitalize
on
evolving
industry
trends
over
the
long
term
We
leverage
our
core
competencies
to
grow
our
regulated
and
competitive
business
while
expanding
to
adjacent
markets
Core Strength
Strategic Actions
Public Policy Advocacy
We
advocate
for
policies
that
strengthen
competitive
markets,
value
the
grid
and
enhance
the
value
of
clean,
reliable
generation |
 Key Developments
*
*
*
*
* |
 8
2014 EEI Financial Conference
Capacity Performance (CP) Impact on PJM Fleet
Source: NorthBridge Analysis; includes FRR resources/Loads; PJM proposal is to
fully procure CP for 2016/17 and 2017/18 but to incrementally procure up to 10 GW of base
capacity for 2015/16. Potential 2015/16 all-in CP procurement
quantity shown for comparison purposes. Exelon’s fleet is well
positioned to benefit from Capacity Performance due to significant
investments in reliability |
 9
2014 EEI Financial Conference
Asset Divestitures --
$ 1.4 Billion in Proceeds to Date
Retail
EXC Service Territory
PHI Service Territory
(1)
Represents EXC’s portion of the asset
Note: CF: Capacity Factor through September 2014; Safe Harbor capacity
factor through July 2014 Gas CT / 200 MW
2014 CF –
8%
Signed with Wayzata on
9/20
West Valley
Gas CT / 477 MW
2014 CF –
17%
Signed with Starwood
9/26
Quail Run
Gas / Oil CCGT / 688
MW
2014 CF –
61%
Signed with Calpine on
8/22
Fore River
Hydro / 277 MWZ
(1)
2014 CF –
38%
Transaction closed on
8/8 with Brookfield
Safe Harbor
Coal / 1245 MW
(1)
2014 CF –
74% / 82%
Signed with ArcLight on 10/24
Keystone / Conemaugh
Gas CCGT / 684 MW
2014 CF –
74%
Currently in sale
process
Hillabee
To date, Exelon has signed definitive agreements on five non-core
assets representing a total of nearly $1.4 billion of after-tax sales
proceeds upon closings; This excludes proceeds from Hillabee,
which is currently on the market |
 10
2014 EEI Financial Conference
ExGen Disclosures -
Asset Sale Impacts
Gross
Margin
Category
($M)
2015
2016
2017
Open Gross Margin
(including South, West & Canada hedged GM)
6,750
6,500
6,650
Mark to Market of Hedges
-
150
150
Power New Business / To Go
400
550
750
Non-Power Margins Executed
100
50
50
Non-Power New Business / To Go
300
350
350
Total Gross Margin
(2,5)
7,550
7,600
7,950
Impact of Removing Keystone / Conemaugh
(150)
(100)
(100)
Pro-forma Total Gross Margin excluding Keystone / Conemaugh
7,400
7,500
7,850
Impact
of
Announced
Assets
Sales
During
2014
(1)
2015
2016
2017
OGM Impact Q2 (Safe Harbor)
(50)
(50)
(50)
OGM Impact Q3 (Fore River, Quail Run, West Valley)
(100)
(100)
(100)
OGM Impact Q4 (Keystone / Conemaugh)
(150)
(100)
(100)
Total Impact to OGM from Announced Asset Sales
(300)
(250)
(250)
O&M
100
100
100
D&A
100
100
100
EBIT
(100)
(50)
(50)
CapEx
(50)
(50)
(100)
EPS Reduction
(6)
($0.06-$0.08)
($0.02-$0.04)
($0.02-$0.04)
(1)
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
(3)
Excludes
EDF’s
equity
ownership
share
of
the
CENG
Joint
Venture
(4)
Mark
to
Market
of
Hedges
assumes
mid-point
of
hedge
percentages
(5)
Reflects
the
divestiture
impact
of
Fore
River,
Quail
Run
and
West
Valley.
Does
not
include
divestiture
of
Keystone/Conemaugh
or
the
Integrys
Acquisition
(6)
EPS
impact
does
not
include
impact
of
investing
the
proceeds
from
the
sale.
As
a
reminder
these
sales
were
included
in
the
accretion
calculation
for
the
PHI
transaction
(3,4)
(3)
(1) |
 11
2014 EEI Financial Conference
2014 EEI Financial Conference
State of the Art Combined Cycles in ERCOT
•
Efficient:
Two of the cleanest, most efficient
Combined Cycle Gas Turbines (CCGT) in the
nation
•
Cost Effective:
Simplified design provides for
easier construction and maintenance, making
these units among the most predictable and
least costly to operate and maintain in the
industry
•
Environmental:
Plants
use
air
cooling
which
mitigates water constraint issues
•
Fast
Ramp:
100
MW/Minute
ramp
rate
(market
ramp rate ~50 MW/minute)
WEST
SOUTH
NORTH
HOUSTON
Wolf Hollow
Colorado Bend
Key Facts
Sites
Wharton County, TX
Granbury, TX
Total Capacity
~2,200MW
(Wolf Hollow: 1,085MW / Colorado
Bend: 1,104MW)
Construction Cost
~$700/kW
Heat Rate
~6,500 mmBtu/MWh
OEMs
GE and Alstom
EPC
Zachry
Cooling System
Air Cooled
Construction Start
2015
Commercial Operation
By Summer 2017
ERCOT Dispatch |
 12
2014 EEI Financial Conference
2014 EEI Financial Conference
Distributed Energy Platform
Distributed Energy is a Fast Growing Business
•
On-site generation, including solar, quadrupled since 2006
(Wall Street Journal 2013)
•
US C&I customers are spending ~$5-6 billion per year on self-
generation and energy efficiency programs (Bloomberg 2013)
•
Revenues from Distributed Generation are expected to reach
$12.7 billion by 2018 (Pike Research, Navigant, 2012)
Distributed Energy
Supports Exelon’s
Strategy:
Grow
Organically &
Through M&A
Participate in
Emerging
Trends
& Technologies
Commercializing
emerging
and
potentially
disruptive
energy
technologies
to
diversify
existing
technology
base
Acquiring
long
term
retail
customers
through
a
PPA
or
other
long-term
agreement
Attract
and
acquire
new
customers
with
unique
offering
Provides
adaptive
growth
in
an
emerging
market
sector
Bolstering
existing
relationships
with
customers
to
help
achieve
reliability
or
sustainability
objectives
Integrating
supply
&
demand
side
solutions
Key Attributes of Financial Value
Backup
Generation
Battery
Storage
Co-Generation
Fuel
Cell
CNG
Solar
Energy
Efficiency
•
Provide equity financing for 21 MW of Bloom Energy fuel cell projects
at 75 commercial facilities including AT&T
•
Provides renewable energy value or credits, if applicable
•
Provides tax incentives, if applicable
•
Own and operate CNG facilities
•
Leverage retail gas supply and risk management expertise
•
Long-term customer off-take agreement(s)
•
~ 200 MW of Retail Solar Projects in operation or under construction
•
Long-term customer PPA (usually @ fixed price)
•
Provides renewable energy value or credits, if applicable
•
Provides tax incentives, if applicable
•
Over 1,000 energy saving projects implemented
•
~ 50 MW conserved by customers
•
More than $1 billion in projects 3rd party customer financed
•
Own and operate energy assets as a service to retail customers
•
Bundled service offering with long-term customer agreements
through grid power supply & LR programs
•
Load Response market -based value creation (e.g., LR Programs)
•
Own and operate energy assets as a service to retail customers
•
Bundled service offering with long-term customer agreements
through grid power supply & LR programs
•
Load Response market based value creation (e.g., ancillary services)
•
Design, build and operate energy assets
•
Provides renewable energy value or credits, if applicable
•
Long-term O&M agreements
Owned Assets –
additional attributes:
•
Long-term customer PPA (usually @ fixed price)
•
Provides tax incentives, if applicable
Invested
more
than
$1
billion
of
capital
with
projects
averaging
returns
of
8%
-
12%,
and
well
positioned
for
growth
Preserve
Value |
 Financial Update |
 14
2014 EEI Financial Conference
2014 EEI Financial Conference
Financing Strategy
•
Our financing strategy incorporates a broad range of financial products, from
the standard corporate-style products (such as corporate debt and
equity), to alternative structures such as project financing,
partnership structures and other arrangements
•
We employ a wide variety of financing tools that will enable us to access
capital to grow on both the regulated and unregulated sides of the
business Financing
Growth
Balance Sheet
Debt
Equity or Equity-
Like Products
Structured
Finance
On Balance Sheet Debt
supports core business and/or
strategic assets
•
Senior Unsecured Notes
•
Utility First Mortgage Bonds
Equity or Equity-Like Products
support growth projects (both
on-going and strategic M&A)
•
Mandatory Convertible Units
•
Marketed Follow-On Offerings
Structured Financing supports
non-core assets that generate
consistent cash flows
•
Project Financing
•
Asset Based Lending
•
Joint Venture/Equity Partner
Asset Sales
Proceeds from asset sales
support
•
Reinvestment of Free Cash Flow
•
Strategic Diversification |
 15
2014 EEI Financial Conference
2014 EEI Financial Conference
Exelon’s Strategic and Financial Decisions Enable Growth
Across the Enterprise
Exelon has a proven ability to finance growth
A broad spectrum of financing alternatives beyond the
core financing options can be used to fund growth
o
Monetize assets in the portfolio via project
finance (Nearly $3B over past 3 years)
o
Sell assets which are worth more to others
($1.0-$1.5B after-tax in 2014-15)
o
Other financing structures (joint ventures,
minority partners, etc.) could be used based on
opportunity
Incremental Sources of Cash
750
750
750
775
775
550
425
675
300
625
275
2016
775
25
2015
2,650
1,900
2014
2018
1,200
2017
1,050
4,275
1,400
1,150
2013
1,175
Strategic and Diversified Deployment
Exelon
1.
Constellation
2.
BGE
3.
Utility Rate Base
4.
Retail Acquisitions
5.
Wind
6.
Annova LNG
7.
ERCOT New Build
8.
Pepco Holdings
9.
Distributed Energy
3
4
2/8
7
6
1
5
Contracted
Retail Regulated
Earnings Volatility
Higher
Lower
Merchant
Strategic Decisions
Dividend Reduction
Alternative Financings
Forward Equity Sale
Mandatory Converts
ExGen Texas Power, LLC
Asset Sales
(1)
EPU Cancellations
ExGen Renewables I
Continental Wind
(1)
Includes Safe Harbor, Fore River, Quail Run, West Valley and Keystone
Conemaugh. Does not include future Hillabee proceeds
9
Note: |
 16
2014 EEI Financial Conference
2014 EEI Financial Conference
Over the Last Three Years, Exelon Has Raised Nearly $3 Billion
through Project Financing
•
Exelon uses project financing to:
•
Maintain upside reward of the project while mitigating the downside risk
•
Enhance corporate credit metrics and strengthen the balance sheet via
non-recourse financing vehicles •
Provide different and new sources of liquidity that Exelon would
not typically be able to access corporately
•
Maximize Exelon’s returns on its strategic investments
Antelope Valley
Solar Ranch
•230 MW photovoltaic
solar generating plant in
Lancaster, CA
•$646 MM
Senior
Secured Bond –
due
January 2037 with a DOE
Loan Guaranty
Continental Wind
•667 MW of wind spread
across 13 projects and five
wind regimes
•$613MM Senior Secured
144a Project Bond –
due
February 2033 and
$141MM Senior Secured LC
and Working Capital
Facilities –
due February
2021
•Deal of the Year
•Project Finance’s 2013
North American Portfolio
Power Deal of the Year
•Project Finance & Risk’s
2013 Project Finance
Renewable Deal of the Year
ExGen Renewables
I
•HoldCo financing of
Continental’s distributions
to further maximize our
returns on our wind
investments
•$300MM Senior Secured
Team Loan B –
due
February 2021
ExGen Texas Power
•3,476 MW ERCOT
conventional power
portfolio consisting of
CCGTs and Simple Cycles
•$675MM Senior Secured
Term Loan B –
due
September 2021
•One of the largest non-
corporate, single-tranche
term loan B issuances in
the power sector in 2014 |
 17
2014 EEI Financial Conference
2014 Operating Earnings Guidance
2014 Original Guidance
$2.25 -
$2.55
(1)
$0.50 -
$0.60
$0.40 -
$0.50
$0.20 -
$0.30
ExGen
ComEd
PECO
BGE
2014 Revised Guidance (Disclosed
on 3Q2014 Earnings Call)
$2.30 -
$2.50
(1)
$1.25 -
$1.35
$0.45 -
$0.55
$0.35 -
$0.45
$0.15 -
$0.25
ExGen
ComEd
PECO
BGE
$1.10 -
$1.30
(1) Earnings guidance for OpCos may not add up to
consolidated EPS guidance. Refer to slide 24 for a list of adjustments from GAAP EPS to adjusted
(non-GAAP) operating EPS |
   18
2014 EEI Financial Conference
2014 EEI Financial Conference
EPS Sensitivities
2015
2016
2017
Fully Open
Henry Hub Natural Gas
+$1/MMBtu
$0.10
$0.37
$0.66
$0.88
-$1/MMBtu
($0.05)
($0.34)
($0.59)
($0.87)
NiHub ATC Energy Price
+$5/MWh
$0.07
$0.22
$0.31
$0.36
-$5/MWh
($0.07)
($0.22)
($0.31)
($0.36)
PJM-W ATC Energy Price
+$5/MWh
$0.03
$0.14
$0.21
$0.27
-$5/MWh
($0.02)
($0.13)
($0.20)
($0.27)
PJM Capacity Market
+$10/MW-day
$0.05
-$10/MW-day
($0.05)
30 Year Treasury Rate
+25 basis points
$0.01
$0.01
$0.01
$0.01
-25 basis points
($0.01)
($0.01)
($0.01)
($0.01)
Share Count (millions)
870
872
892
910
(1)
Based
on
September
30,
2014
market
conditions
and
hedged
position.
Gas
price
sensitivities
are
based
on
an
assumed
gas-power
relationship
derived
from
an
internal
model
that
is
updated
periodically.
Power
prices
sensitivities
are
derived
by
adjusting
the
power
price
assumption
while
keeping
all
other
price
inputs
constant.
Due
to
correlation
of
the
various
assumptions,
the
EPS
impact
calculated
by
aggregating
individual
sensitivities
may
not
be
equal
to
the
EPS
impact
calculated
when
correlations
between
the
various
assumptions
are
also
considered.
(2)
Assumes
2017/2018
auction
cleared
volumes
(3)
Does
not
include
shares
assumed
to
be
issued
via
forward
equity
sale
in
connection
with
PHI
acquisition
(3)
(2) |
 19
2014 EEI Financial Conference
2014 EEI Financial Conference
Capital Expenditure Expectations ($M)
Exelon Utilities
Exelon Generation
(1)
(1)
At Ownership
Note: Numbers rounded to nearest $25m
275
275
300
325
525
425
300
250
650
800
725
650
1,600
1,925
1,900
2,000
2016
3,225
2015
3,425
2014
3,050
2017
3,225
Gas Delivery
Smart Grid/Smart Meter
Electric Transmission
Electric Distribution
1,175
950
900
1,125
1,050
550
675
175
125
150
125
200
150
3,250
100
50
100
2014
2,775
75
1,025
1,000
950
100
75
2016
2,875
100
75
25
2015
2,200
2017
75
Wind
Base Capex
Nuclear Fuel
MD Commitments
TX New Build
Solar
Upstream
Nuclear Uprates |
 20
2014 EEI Financial Conference
2014 Projected Sources and Uses of Cash
Key Messages
(1)
•
Cash from Operations is projected to be $7,475M vs. 2Q14E of
$6,975M for a $500M variance. This variance is driven by:
$625M Net proceeds from divestitures
$175M Income taxes and settlements
$125M Reclassification of PHI preferred stock purchase
($325M) Integrys acquisition, including working capital
($100M) Working capital at Utilities
•
Cash from Financing activities is projected to be $375M vs.
2Q14E of $250M for a $125M variance. This variance is driven
by:
$175M Incremental project financing at ExGen
($50M) Decreased ComEd long term debt requirements
($25M) Decrease in projected commercial paper financings
•
Cash from Investing activities is projected to be ($5,725M) vs.
2Q14E of ($5,450M) for a ($275M) variance. This variance is
driven by:
($125M) ExGen development
($125M) Reclassification of PHI preferred stock purchase
($25M) Upstream
Projected Sources & Uses
(1)
(1)
All amounts rounded to the nearest $25M.
(2)
Excludes counterparty collateral of $134 million at 12/31/2013. In addition, the
12/31/2014 ending cash balance does not include collateral.
(3)
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, and ($125M) purchase of PHI preferred stock.
(4)
Adjusted Cash Flow from Operations (non-GAAP) primarily includes net cash
flows from operating activities and net cash flows from investing
activities excluding capital expenditures of $5.7B for 2014. (5)
Dividends are subject to declaration by the Board of Directors.
(6)
“Other Financing”
primarily includes CENG distribution to EDF, expected changes in short-term
debt, and proceeds from issuance of mandatory convertible units.
($ in millions)
BGE
ComEd
PECO
ExGen
Exelon
(3)
As of 2Q14
Variance
Beginning Cash Balance
1,475
1,475
--
Adjusted Cash Flow from Operations
675
1,600
650
4,550
7,475
6,975
500
CapEx (excluding other items below):
(550)
(1,475)
(500)
(1,275)
(3,700)
(3,450)
(250)
Nuclear Fuel
n/a
n/a
n/a
(1,000)
(1,000)
(1,000)
--
Dividend
(1,075)
(1,075)
--
Nuclear Uprates
n/a
n/a
n/a
(150)
(150)
(150)
--
Wind
n/a
n/a
n/a
(75)
(75)
(75)
--
Solar
n/a
n/a
n/a
(200)
(200)
(200)
--
Upstream
n/a
n/a
n/a
(75)
(75)
(50)
(25)
Utility Smart Grid/Smart Meter
(75)
(275)
(150)
n/a
(525)
(525)
--
Net Financing (excluding Dividend):
Debt Issuances
--
900
300
--
1,200
1,250
(50)
Debt Retirements
--
(625)
(250)
(525)
(1,375)
(1,375)
--
Project Finance/Federal Financing Bank
Loan
n/a
n/a
n/a
1,050
1,050
875
175
Other Financing
(75)
175
100
(375)
575
575
--
Ending Cash Balance
3,600
3,250
350
(2)
(4)
(2)
(6)
(5) |
 21
2014 EEI Financial Conference
Pension and OPEB Contributions and Expense
2015
2016
(in $M)
Pre-tax Expense
(1)
Contributions
(2)
Pre-Tax Expense
(1)
Contributions
(2)
Pension
(3)(4)
$375
$515
$325
$565
OPEB
(3)(4)
$5
$30
$5
$35
Total
$380
$545
$330
$600
(1)
Pension and OPEB expenses assume a ~27% and ~28% capitalization rate in 2015
and 2016, respectively (2)
Contributions shown in the table above are based on the current contribution
policy, which for the pension includes a discretionary component of $250M
(3)
Expected return on assets for pension is 7.00% and for OPEB is 6.59%
(4)
Projected 12/31/14 pension and OPEB discount rates are 4.28% and 4.26%,
respectively, for the majority of plans |
 22
2014 EEI Financial Conference
2015 Pension and OPEB Sensitivities
•
Tables below provide sensitivities for the combined company’s 2015 pension
and OPEB expense and contributions
(1)
under various discount rate and S&P 500 asset return scenarios
(1)
Contributions
shown
in
the
table
above
are
based
on
the
current
contribution
policy,
which
for
the
pension
includes
a
discretionary
component
of
$250M
(2)
Pension
and
OPEB
expenses
assume
an
~
27%
capitalization
rate
in
2015
(3)
Final
2014
asset
return
for
pension
and
OPEB
will
depend
in
part
on
overall
equity
market
returns
for
Q4
2014
as
proxied
by
the
S&P
500;
The
amounts
above
reflect
YTD
asset
returns
through
September
30,
2014
(4)
The
baseline
discount
rates
reflect
projected
12/31/14
pension
and
OPEB
discount
rates
of
4.28%
and
4.26%,
respectively,
for
the
majority
of
plans
2015 Pension Sensitivity
(2)
(in $M)
S&P Returns in Q4 2014
(3)
10%
0%
-10%
Discount Rate at
12/31/14
Pre-Tax
Expense
(1)
Contributions
(2)
Pre-Tax
Expense
(1)
Contributions
(2)
Pre-Tax
Expense
(1)
Contributions
(2)
Baseline
Discount
Rate
(4)
$365
$505
$375
$515
$390
$520
+50 bps
$345
$265
$345
$520
$355
$525
-
50bps
$400
$490
$410
$495
$425
$505
2015 OPEB Sensitivity
(2)
(in $M)
S&P Returns in Q4 2014
(3)
10%
0%
-10%
Discount Rate at
12/31/14
Pre-Tax
Expense
(1)
Contributions
(2)
Pre-Tax
Expense
(1)
Contributions
(2)
Pre-Tax
Expense
(1)
Contributions
(2)
Baseline
Discount
Rate
(4)
$0
$30
$5
$30
$25
$35
+50 bps
($10)
$30
$0
$30
$10
$30
-
50bps
$10
$30
$25
$35
$35
$50 |
 23
2014 EEI Financial Conference
Exelon-PHI Debt Maturity Profile
(1)
250
250
325
260
1,275
425
1,350
300
500
650
600
550
700
600
1,100
525
100
125
100
75
200
250
800
2022
1,450
2016
1,575
2015
1,985
2014
2021
900
2020
1,600
2019
925
25
2018
1,600
2017
1,225
25
ExCorp
PHI Holdco
PHI Regulated
EXC Regulated
ExGen
(1)
ExGen
debt
includes
legacy
CEG
debt;
EXC
Regulated
includes
capital
trust
securities;
Excludes
PHI
unregulated
debt,
which
totals
$25M;
Excludes
acquisition
debt
and
non-recourse
debt;
(2)
Current
senior
unsecured
ratings
for
Exelon,
Exelon
Generation
and
BGE
and
senior
secured
ratings
for
ComEd
and
PECO
(3)
All
ratings
are
“Stable”
outlook,
except
for
at
Fitch,
which
has
BGE
on
“Positive”
and
Exelon
and
ExGen,
on
“Ratings
Watch
Negative”
As of 10/31/14
Manageable debt maturity profile
Current
Ratings
(2)(3)
Moody’s
S&P
Fitch
Corp
Baa2
BBB-
BBB+
ComEd
A2
A-
A-
PECO
Aa3
A-
A
BGE
A3
A-
BBB+
Generation
Baa2
BBB
BBB+ |
 24
2014 EEI Financial Conference
GAAP to Operating Adjustments
•
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 -
Financial impacts associated with the increase and decrease in certain
decommissioning obligations -
Financial impacts associated with the sale of interests in generating
stations -
Non-cash charge to earnings related to the cancellation of previously
capitalized nuclear uprate projects and
the
impairment
of
certain
wind
generating
assets
and
certain
assets
held
for
sale
-
Gain recorded upon consolidation of CENG
-
Certain costs incurred associated with the Constellation, CENG merger, and
Pepco Holdings, Inc. 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 -
CENG interest not owned by Generation, where applicable
|
 Exelon Utilities
*
*
*
*
* |
 26
2014 EEI Financial Conference
Exelon Utilities Strategy
Strategy
Increase Total Enterprise Value
Maintain
First Quartile
Operating Performance
Achieve Financial
Performance Targets
Leverage standardization,
common platforms, and
best practices across
operating companies,
building a value creation
platform for future scale
Optimize Existing
Infrastructure
(get full potential from
current businesses)
Invest in Traditional
Infrastructure
(delivery network investments)
Grow Emerging
Infrastructure
(transformative growth)
Innovate
Products & Services
(expand customer offering)
Operational Excellence
Growth |
 27
2014 EEI Financial Conference
Leveraging Best Practices for Operational Excellence
Operations
Metric
At Merger (2012)
Post Merger (2014)
BGE
PECO
ComEd
BGE
PECO
ComEd
Electric
Operations
OSHA Recordable Rate
OSHA Severity Rate
2.5 Beta SAIFI
2.5 Beta CAIDI
Customer
Operations
Customer Satisfaction (MSI)
Service Level % of Calls Answered in
<30 Sec
Abandon Rate
Calls per Customer
Gas
Operations
Percent of Calls Responded to in
<=1 Hour
No
Gas
Operations
No
Gas
Operations
3rd Party Damages per 1,000 Gas
Locates
Q1
Q2
Q3
Q4
Performance
Quartiles
Exelon
Utilities
has
identified
and
transferred
best
practices
at
each
of
its
utilities
to
improve
operating
performance
in
areas
such
as:
•
System Performance
•
Emergency Preparedness
•
Corrective and Preventive Maintenance |
 28
2014 EEI Financial Conference
Capital Expenditures
(1)
Smart
Meter/Smart
Grid
CapEx
net
of
proceeds
from
U.S.
Department
of
Energy
(DOE)
grant;
For
BGE,
includes
CapEx
from
Smart
Energy
Savers
program
of
~$10M
per
year
175
150
175
200
275
350
300
225
150
100
475
575
425
375
75
75
125
175
225
200
1,000
1,225
1,225
1,325
350
350
325
325
250
350
350
350
125
125
125
100
25
2017E
775
25
2016E
750
2015E
725
50
2014E
650
2017E
525
2016E
525
2015E
550
50
2014E
650
50
2017E
1,925
2016E
1,950
2015E
2,150
2014E
1,750
Gas Delivery
Electric Transmission
Smart Grid/Smart Meter
(1)
Electric Distribution
($ in millions) |
 29
2014 EEI Financial Conference
Exelon
Utilities:
Rate
Base
(1)
and
ROE
Targets
2014E
Long-Term Target
Equity Ratio
52%
~53%
(4)
Earned ROE
7-8%
10%
Rate Case
2015
2014E
Long-Term Target
Equity Ratio
~46%
~53%
(2)
Earned ROE
8-9%
Based on 30-yr
US Treasury
(3)
Rate Case
Annual Formula Rate Filing
Continued investment in utilities will provide stable earnings growth
($ in billions)
(1)
ComEd,
PECO
and
BGE
rate
base
represents
end-of-year.
Numbers
may
not
add
due
to
rounding
(2)
Equity
component
for
distribution
rates
will
be
the
actual
capital
structure
adjusted
for
goodwill
(3)
Earned
ROE
will
reflect
the
weighted
average
of
11.5%
allowed
transmission
ROE
and
distribution
ROE
resulting
from
30-year
Treasury
plus
580
basis
points
for
each
calendar
year
(4)
Per
MDPSC
merger
commitment,
BGE
is
precluded
from
paying
dividends
through
2014
2014E
Long-Term Target
Equity Ratio
56%
~53%
Earned ROE
11-12%
10%
Rate Case
Possible 2015-2016
1.4
1.4
1.4
7.1
7.8
8.5
9.2
3.7
3.9
4.0
4.1
3.0
3.1
3.2
3.2
2.5
2.8
3.0
3.4
0.7
0.7
0.8
0.8
0.7
0.8
1.0
1.2
1.3
1.2
1.2
1.3
1.2
5.5
2015E
2017E
5.8
2016E
5.2
2014E
4.9
2017E
6.3
2014E
9.6
2016E
6.2
2015E
6.0
2014E
5.6
2017E
12.6
2016E
11.5
2015E
10.6
Gas
Distribution
Transmission |
 30
2014 EEI Financial Conference
9.9
2017 YE Rate Base
Other 2015-2017
$24.7B
(1.5)
Depreciation 2015-2017
(3.8)
CapEx 2015-2017
2014 YE Rate Base
$20.1B
Rate Base Growth
Utility CapEx spend outpaces depreciation, thereby growing rate base and
earnings |
 31
2014 EEI Financial Conference
Exelon Utility 2014-17 Adjusted Operating EPS
Guidance
By investing $16B in capital and improving earned ROEs, Exelon Utilities will
provide average earnings growth of ~8% per year from
2014-2017 |
 32
2014 EEI Financial Conference
Grand Prairie Gateway Transmission Line
Key Facts
•
Line:
60
mile,
345
kV
transmission
line
connecting
ComEd’s
Byron
and
Wayne
substations
alleviating
identified
congestion
and
enhancing
reliability
•
Cost:
$260
million
•
Customer
Savings:
$250
million
within
the
first
15
years
of
operation
–
net
of
all
costs
•
Recovery
Mechanism:
FERC-filed
transmission
rate
of
11.5%
and
construction
work
in
progress
and
abandonment
recovery
•
Construction:
Scheduled
to
begin
Q2
2015
•
In
Service
Date:
Q2
2017
•
Environmental
Benefits:
735,000
pounds
of
carbon
dioxide
(CO2)
reduced
over
the
first
15
years |
 33
2014 EEI Financial Conference
ComEd April 2014 Distribution Formula Rate
Docket #
14-0312
Filing Year
2013
Calendar
Year
Actual
Costs
and
2014
Projected
Net
Plant
Additions
are
used
to
set
the
rates
for
calendar
year
2015.
Rates
currently
in
effect
(docket
13-0318)
for
calendar
year
2014
were
based
on
2012
actual
costs
and
2013
projected
net
plant
additions
Reconciliation Year
Reconciles
Revenue
Requirement
reflected
in
rates
during
2013
to
2013
Actual
Costs
Incurred.
Revenue
requirement
for
2013
is
based
on
docket
13-0386
filed
in
June
2013
and
reflect
the
impacts
of
PA
98-0015
(SB9)
Common Equity Ratio
~
46%
for
both
the
filing
and
reconciliation
year
ROE
9.25%
for
the
filing
year
(2013
30-yr
Treasury
Yield
of
3.45%
+
580
basis
point
risk
premium)
and
9.20%
for
the
reconciliation
year
(2013
30-yr
Treasury
Yield
of
3.45%
+
580
basis
point
risk
premium
–
5
basis
points
performance
metrics
penalty).
For
2014
and
2015,
the
actual
allowed
ROE
reflected
in
net
income
will
ultimately
be
based
on
the
average
of
the
30-year
Treasury
Yield
during
the
respective
years
plus
580
basis
point
spread,
absent
any
metric
penalties
Requested Rate of Return
~
7%
for
both
the
filing
and
reconciliation
years
Rate Base
(1)
$7,369
million–
Filing
year
(represents
projected
year-end
rate
base
using
2013
actual
plus
2014
projected
capital
additions).
2014
and
2015
earnings
will
reflect
2014
and
2015
year-end
rate
base
respectively.
$6,596
million
-
Reconciliation
year
(represents
year-end
rate
base
for
2013)
Revenue Requirement
Increase
(1)
$269M
($96M
is
due
to
the
2013
reconciliation,
$173M
relates
to
the
filing
year).
The
2013
reconciliation
impact
on
net
income
was
recorded
in
2013
as
a
regulatory
asset.
Timeline
•
04/16/14 Filing Date
•
240 Day Proceeding
•
ALJ Proposed Order issued on 10/15/14 proposes a $239M revenue requirement
increase •
ICC order expected by December 12, 2014
(1)
Amounts
represent
ComEd’s
position
filed
in
rebuttal
testimony
on
July
23,
2014
Note:
Disallowance
of
any
items
in
the
2014
distribution
formula
rate
filing
could
impact
2014
earnings
in
the
form
of
a
regulatory
asset
adjustment
Given
the
retroactive
ratemaking
provision
in
the
Energy
Infrastructure
Modernization
Act
(EIMA)
legislation,
ComEd
net
income
during
the
year
will
be
based
on
actual
costs
with
a
regulatory
asset/liability
recorded
to
reflect
any
under/over
recovery
reflected
in
rates.
Revenue
Requirement
in
rate
filings
impacts
cash
flow.
The
2014
distribution
formula
rate
filing
establishes
the
net
revenue
requirement
used
to
set
the
rates
that
will
take
effect
in
January
2015
after
the
Illinois
Commerce
Commission's
(ICC’s)
review.
There
are
two
components
to
the
annual
distribution
formula
rate
filing:
•
Filing
Year:
Based
on
prior
year
costs
(2013)
and
current
year
(2014)
projected
plant
additions.
•
Annual
Reconciliation:
For
the
prior
calendar
year
(2013),
this
amount
reconciles
the
revenue
requirement
reflected
in
rates
during
the
prior
year
(2013)
in
effect
to
the
actual
costs
for
that
year.
The
annual
reconciliation
impacts
cash
flow
in
the
following
year
(2015)
but
the
earnings
impact
has
been
recorded
in
the
prior
year
(2013)
as
a
regulatory
asset. |
 34
2014 EEI Financial Conference
BGE Rate Case Settlement
Electric
Gas
Docket #
9355
Test Year
September 2013 -
August 2014
Common Equity Ratio
(1)(2)
52.3%
Authorized Returns
(1)(3)
ROE: 9.75%; ROR: 7.46%
ROE: 9.65%; ROR: 7.41%
Requested Rate of Return
7.93%
7.88%
Proposed Rate Base (adjusted)
(1)(4)
$2.9B
$1.2B
Revenue Requirement Increase
$22.0M
$38.0M
Distribution Increase as % of
overall bill
1%
5%
Timeline
•
07/02/14 BGE filed application with the MDPSC seeking increases in electric
& gas distribution base rates
•
210 Day Proceeding
•
7/08/14 –
Case delegated to the Public Utility Law Judge Division
•
10/17/14 –
BGE filed unanimous “black box”
settlement with MD PSC
•
Settlement must be approved by the MD PSC
•
If approved, new rates are expected to be effective no sooner than the middle
of December 2014
(1)
Due
to
the
“black
box”
nature
of
the
settlement,
the
Common
Equity
Ratio,
Authorized
Returns,
and
Proposed
Rate
Base
(adjusted)
were
not
agreed
upon
by
the
parties
in
determining
the
ultimate
revenue
requirement
increase
(2)
Reflects
BGE’s
actual
capital
structure
as
of
8/31/2014
(3)
ROE
and
ROR
stated
in
the
settlement
only
apply
to
AFUDC
and
carrying
costs
on
regulatory
assets
(4)
BGE’s
Proposed
Adjusted
rate
base
First BGE rate case settlement agreement since 1999
|
 35
2014 EEI Financial Conference
ComEd Load
Weather-Normalized Load Growth
Economic Forecast of Drivers that Influence Load
2014E
0.6%
0.1%
1.4%
0.7%
1.7%
2013
-0.3%
-0.5%
0.0%
-0.2%
1.2%
GMP
Large C&I
Small C&I
Residential
All Customers
Driver or Indicator
2015 Outlook
Gross Metro
Product (GMP)
2.3% growth in real GMP reflects overall
better economic conditions than the slower
growth in 2014 (Manufacturing and
Professional Business Services employment
accelerate in 2015)
Employment
1.3% increase in total employment is
expected for 2015, which is consistent with
the average growth for the past three years
Manufacturing
Manufacturing employment is expected to
grow 1.4% in 2015. This is a significant
improvement over the (0.4%) decline in
2013 and the (1.1%) decline in 2014
Households
Household formations are expected to
increase 0.7% in 2015 which is slightly
higher than the expected increase of 0.6% in
2014
Energy Efficiency
Continued expansion of EE program
expected to reduce usage in 2015 by
approximately 1.2%
Notes: 2013 data is not adjusted for leap year. Source of 2015 economic outlook
data is IHS Economics (September 2014). (C&I = Commercial and Industrial)
Improving economic conditions and energy efficiency initiatives will continue
to impact load growth |
 36
2014 EEI Financial Conference
PECO Load
Weather-Normalized Load Growth
Economic Forecast of Drivers that Influence Load
2014E
-0.6%
0.0%
1.1%
0.3%
1.2%
2013
1.5%
-1.1%
0.0%
1.3%
GMP
Large C&I
Small C&I
Residential
All Customers
Driver or Indicator
2015 Outlook
Gross Metro
Product (GMP)
GMP projected to grow at 2.5% for 2015,
the same as prerecession levels
Resident
Employment
Resident employment outlook is 1.7% in
2015 vs. 1.3% in 2014
Manufacturing
Employment
Manufacturing employment is expected to
grow at 1.7%. Philadelphia has had
negative growth from 2000 to 2014
Households
Household growth is expected to be 0.7%,
strongest growth since 2008, and at the
same level as 2014
Energy Efficiency
Deemed Energy Efficiency impact
forecasted to be ~0.9% reduction in
usage in 2015
Moderately strong economic recovery will drive sales in 2015, partially offset
by on-going energy efficiency initiatives
0.3%
Notes: 2013 data is not adjusted for leap year. Source of 2015 economic outlook
data is IHS Economics (September 2014). (C&I = Commercial and Industrial) |
 37
2014 EEI Financial Conference
BGE Load
Weather-Normalized Load Growth
Economic Forecast of Drivers that Influence Load
2014E
-1.8%
-0.5%
-0.7%
-1.2%
1.6%
2013
-3.2%
2.1%
2.0%
-0.6%
0.4%
GMP
Large C&I
Small C&I
Residential
All Customers
Moderately strong economic recovery will drive sales in 2015, partially offset
by energy efficiency initiatives
Driver or Indicator
2015 Outlook
Gross Metro
Product (GMP)
GMP is projected to grow at 2.6% for
2015
Employment
2.1% growth projected. BGE’s decoupled
non-rate case revenue growth is primarily
driven by customer growth. The main
driver for customer growth is employment
Manufacturing
Manufacturing employment is expected to
be fairly flat to 2014 levels in 2015
Households
Household growth is projected to be
0.8%, almost flat to 2014
Energy Efficiency
Continued expansion of EE programs will
partially offset growth seen due to
improvements in economic conditions
Notes: 2013 data is not adjusted for leap year. Source of 2015 economic outlook
data is IHS Economics (September 2014). (C&I = Commercial and Industrial) |
 PHI Acquisition
*
*
*
*
* |
 39
2014 EEI Financial Conference
Delivering Value to PHI’s Customers and Communities
|
 40
2014 EEI Financial Conference
PHI Acquisition Will Create the Leading Mid-Atlantic Utility
Operating Statistics
Commonwealth Edison
Potomac Electric Power
Customers:
Service Territory:
Peak Load:
2013 Rate
Base:
3,800,000
11,400 sq.
miles
23,753 MW
$8.7 bn
Customers:
Service Territory:
Peak Load:
2013 Rate Base:
801,000
640 sq. miles
6,674 MW
$3.4 bn
PECO Energy
Atlantic City Electric
Customers:
Service Territory:
Peak Load:
2013 Rate
Base:
2,100,000
2,100 sq. miles
8,983 MW
$5.4 bn
Customers:
Service Territory:
Peak Load:
2013 Rate Base:
545,000
2,700 sq. miles
2,797
MW
$1.6 bn
Baltimore Gas & Electric
Delmarva Power & Light
Customers:
Service Territory:
Peak Load:
2013 Rate
Base:
1,900,000
2,300 sq. miles
7,236 MW
$4.6 bn
Customers:
Service Territory:
Peak Load:
2013 Rate Base:
632,000
5,000 sq. miles
4,121 MW
$2.0 bn
___________________________
Source: Company filings.
Note: Operational statistics as of 12/31/2013
Combined Service Territory
Potomac Electric Power Service Territory
Atlantic City Electric Service Territory
Delmarva Power & Light Service Territory
Baltimore Gas and Electric Service Territory
PECO Energy Service Territory
ComEd Service Territory |
 41
2014 EEI Financial Conference
2014 EEI Financial Conference
Earnings Accretive First Full Year
(1)
Transaction Economics
Exelon Consolidated S&P FFO/Debt
24%
22%
2015
2016
(1) Assumes funding mix of assumed debt, new debt, asset sales and equity
issuance with appropriate discount to market price. (2) Reflects year end rate base
2016-2017 Operating Earnings
33%-39%
61%-67%
Pro Forma Business Mix
Regulated
Unregulated
Rate Base Growth ($B)
(2)
$21.8
$23.2
$24.7
$8.1
$8.8
$9.6
$20.1
$34.3
+15%
+49%
2017
2014
2015
2016
$29.9
$32.0
Exelon
PHI
2017
2016
$0.10 -
$0.15
$0.15 -
$0.20
Achieve run-rate
accretion of
$0.15-$0.20
starting in 2017
The transaction is EPS accretive, adds to rate base growth and further
strengthens our financials |
 42
2014 EEI Financial Conference
2014 EEI Financial Conference
PHI: Capital Expenditures and Rate Base
$725
$675
$700
$725
$350
$350
$350
$350
$250
$275
$325
$325
$1,400
2017E
2016E
$1,375
2015E
$1,300
2014E
(2)
$1,325
(2)
Pepco
DPL
ACE
Rate Base ($B)
(1)(3)
Capital Expenditures ($M)
(1)
$4.0
$4.4
$4.8
$2.2
$2.4
$2.5
$2.7
$1.6
$1.7
$1.9
$2.1
$3.6
2016E
$8.8
2015E
$8.1
2014E
$7.5
2017E
$9.6
(1)
Source: PHI Third Quarter Earnings Materials 10/31/14
(2)
Source for 2014 CapEx is PHI 2014 Analyst Day Conference Presentation 03/21/14
and PHI First Quarter 2014 Earnings Materials 05/07/14 (3)
Denotes year end rate base
Note: CapEx numbers rounded to nearest $25M; totals might not add due to
rounding Strong rate base growth will provide stable utility earnings
growth |
 43
2014 EEI Financial Conference
2014 EEI Financial Conference
Opportunity for ROE Improvement at PHI Utilities
Source: Pepco Holdings Inc. 2014 Analyst Conference Presentation,
3/21/14 |
 44
2014 EEI Financial Conference
2014 EEI Financial Conference
Regulatory Approval Timeline Supports a Q2/Q3 2015 Close
Jurisdiction
Application
Filing
Key Regulatory Milestones
Approved
Virginia
(Case No. PUE-2014-00048)
3-Jun
Approved October 7, 2015
Federal Energy
Regulatory Commission
(FERC)
(Docket No. EC14-96-000)
30-May
Department of Justice
(DOJ)
6-Aug
Request for additional information received
October 9
Delaware
(Docket 14-193)
18-Jun
Pre-Hearing Briefs: Feb 11, 2015
Hearings: Feb 18 -
20, 2015
Final Order: Mar 10, 2015
New Jersey
(Docket No. EM14060581)
18-Jun
Hearings: Jan 12 -
16, 2015
Briefs: Feb 6, 2015
Reply Briefs: March 3, 2015
Maryland
(Case No 9361)
19-Aug
Hearings: Jan 26 -
Feb 6, 2015
Briefs: Feb 27, 2015
Reply Briefs: March 13, 2015
Statutory Deadline: April 1, 2015
District of Columbia
(Formal Case No. 1119)
18-Jun
Hearings: Feb 9 –
13, 2015
Briefs: March 12, 2015
Reply Briefs: March 26, 2015 |
 |
 46
2014 EEI Financial Conference
2014 EEI Financial Conference
Commercial Business Overview
Scale, Scope and Flexibility Across the Energy Value Chain
Development and
exploration of natural gas
and liquids properties
9 assets in
six states
~165 BCFe of proved
Reserves
(1)
Leading merchant power
generation portfolio in the
U.S.
~32 GW of owned
generation capacity
(2)
Clean portfolio, well
positioned for evolving
regulatory requirements
Industry-leading wholesale
and retail sales and
marketing platform
~150 TWh of load and
~500 BCF of retail gas
delivered
(3)
~ 1 million residential and
100,000 business and
public sector customers
One of the largest and most
experienced Energy
Management providers
Over 4,000 energy savings
projects implemented
across the U.S.
A growing Distributed
Energy platform with over
$1B of investment to date
Benefiting from scale, scope and flexibility across the value chain
(1) 12/31/13
year-end
reserves
based
upon
assets
owned
as
of
9/30/14.
Includes
Natural
Gas
(NG),
NG
Liquids
(NGL)
and
Oil.
NGL
and
Oil
are
converted
to
BCFe
at
a
ratio
of
6:1.
(2)
Total
owned
generation
capacity
as
of
9/30/2014,
less
capacity
for
announced
divestitures
of
Fore
River,
Quail
Run,
West
Valley,
and
Keystone
Conemaugh
(3)
Expected
for
2014
as
of
9/30/2014.
Electric
load
and
gas
includes
fixed
price
and
indexed
products
Note:
Does
not
include
the
impact
of
Integrys
acquisition |
 47
2014 EEI Financial Conference
2014 EEI Financial Conference
10
15
5
9
18
7
15
16
49
71
27
97
25
ERCOT
38
Mid-Atlantic
108
Canada
Midwest
111
23
South/West/
New York
10
New England
Generation to Load Match
Industry-leading platform with regional diversification of the
generation fleet and
customer-facing load business
Generation Capacity, Expected Generation and Expected Load
2015 in TWh
(1,2)
(1)
Owned
and
contracted
generation
capacity
converted
from
MW
to
MWh
assuming
100%
capacity
factor
(CF)
for
all
technology
types,
except
for
renewable
capacity
which
is
shown
at
estimated
CF
(2)
Expected
generation
and
load
shown
in
the
chart
above
will
not
tie
out
with
load
volume
and
ExGen
disclosures;
Load
shown
above
does
not
include
indexed
products
and
generation
reflects
a
net
owned and
contracted
position;
Estimates
as
of
9/30/2014
Note:
Includes
divestitures
for
Safe
Harbor,
Fore
River,
Quail
Run,
and
West
Valley;
Does
not
include
impact
of
Keystone
/Conemaugh
divestiture
or
the
Integrys
acquisition
Expected Load
Expected
Generation
Baseload
Intermediate
Peaking
Renewables
Generation to Load match provides
portfolio management benefits in
differing volatility and price
environments
•
During the first quarter, our
nuclear baseload generation fleet,
in combination with our
dispatchable fleet, allowed us to
take advantage of the high
volatility/price environment while
managing load obligations
•
During the third quarter, we were
able to realize lower costs to serve
our load due to the low
volatility/price environment |
 48
2014 EEI Financial Conference
2014 EEI Financial Conference
Electric Load Serving Business: Growth Targets
(1)
0
20
40
60
80
100
120
140
160
180
2015E
2017E
2016E
2014E
165
70-80%
20-30%
165
60-70%
30-40%
150
60-70%
30-40%
165
70-80%
20-30%
Retail Load
(2)
Wholesale Load
Total Contracted
Commercial Load
2014 –
2017 TWh
8%
Load Split by Customer Class
(2014 TWh)
Expected growth in volumes and margins on the
back of a sustainable platform
A diverse set of customers enhances portfolio
management opportunities
Note: Index load expected to be 20% to 30% of total forecasted retail
load Customer Type
Load Size
Mass Markets
<1,000 MWhs per year
Small C&I
1,001-5,000 MWhs per year
Medium C&I
5,001-25,000 MWhs per year
Large C&I
>25,000 MWhs per year
Medium C&I
Large C&I
35%
15%
Small C&I
10%
Mass Markets
5%
Wholesale
35%
C&I = Commercial & Industrial
(1) Does not include Integrys acquisition |
 49
2014 EEI Financial Conference
2014 EEI Financial Conference
Electric Load Serving Business: Market Landscape
Total U.S. Power Market 2014 (~3,700 TWh load)
(2)
Eligible Non-
Switched
Eligible
Switched
Muni/Co-Op Market
Other
Ineligible
Constellation Active Retail Electric Markets
(1)
Competitive Retail Market Expected to Grow Faster Than Overall
Market 2014-2017
•
Underlying 1% load growth across the U.S.
•
C&I switched market to grow by about 8%
•
Residential switched market to grow by about 7%
Retail Mergers & Acquisitions Activity has Increased
•
EXC has been active in evaluating opportunities, and acquired
Integrys Energy Services earlier this year
•
34 deals announced 2014 YTD, compared to 27 deals in 2013,
and 23 deals in 2012
Conditions have improved in many markets as impacts of the
Polar Vortex have played out
•
During 2014, we have experienced improved margins, contract
tenors, and renewal rates
Existing suppliers continue to expand market footprint and
product portfolio
•
Existing suppliers entered 23 new markets in 2014 YTD
•
Energy efficiency among most popular for cross-selling
opportunities
Market Landscape
(2)
(1)
Does
not
include
Integrys
acquisition
(2)
Sources
are
EIA,
DNV
GL,
and
internal
estimates
Improving market driving higher margins and better contract terms
|
 50
2014 EEI Financial Conference
2014 EEI Financial Conference
Natural Gas Serving Business: Marketing Platform
Constellation Active Natural Gas Markets
Supply
~4-6 Bcf per day delivered in competitive markets
Transportation
Active shipper on more than 45 interstate pipelines on a daily basis
Trading
Active participant in all major supply basins, markets, and trading
points in North America
Volume
Management
Schedule, nominate and balance behind more than 100 LDCs
Nature
Gas
markets
continue
to
grow
on
both
the
consumption
and
supply
side
•
Lead by the industrial section, gas consumption is expected
to increase by 1.6% in 2014
•
EXC expanded it’s gas marketing presence through the
Integyrs and ETC ProLiance acquisitions
Growing domestic production impacting imports
•
Continued downward pressure on natural gas imports from
Canada
•
Mexican exports, specifically from Eagle Ford, are expected to
increase due to growing demand in the electric power sector
The
Polar
Vortex
provided
multiple
supply
opportunities
across
the
US
for
natural
gas
LNG imports and exports
•
Higher prices in Europe and Asia more attractive to sellers
than low US prices
•
LNG exports are still a very small part of the total picture;
however, the United States will remain a net importer of
natural gas because of pipeline imports from Canada
Gas Storage and Pipeline Investment
•
Gas inventories continue to drop year over year. Currently
373 BCF lower than last year driving storage opportunities
•
Investment in new pipelines supporting key production
areas continue grow supported by multiple parties (Equity,
LDCs)
(1) Source: EIA and internal estimates
Market Landscape 2014 -
2015
(1)
Top 10 US Gas Marketer with a growing presence |
 51
2014 EEI Financial Conference
Integrys Energy Services Acquisition
Natural Gas
Electric
Electric and Natural
Gas
•
Significantly
increases
natural
gas
portfolio
by
150
bcf
annually
•
Increases
power
load
by
15
TWh
•
Many
of
the
power
customers
served
by
Integrys
are
in
regions
where
Exelon
owns
significant
generation,
providing
generation
to
load
match
benefit
•
Mitigates
risk
of
hedging
in
illiquid
markets
•
Adds
1.2
million
customers,
bringing
the
total
Constellation
customer
base
to
approximately
2.5
million
homes
and
businesses |
 52
2014 EEI Financial Conference
(1) 12/31/13 year-end reserves based upon assets owned
as-of 9/30/14. Upstream E&P Assets
Estimated Net Proved
Reserves
(as of 12/31/13)
(1)
Average Net Daily
Production
(as of Q2 2014)
165 Bcfe
55 MMcfe
Investment Thesis
•
Our Upstream Gas business achieves strong returns
(>16% after-tax IRR)
•
$110m (~70% utilized) Reserve Based Lending (RBL)
facility in place
Non-recourse treatment at S&P
•
Provides valuable market intelligence in complex
natural gas markets
Forecasted Production
2014
2015
2016
2017
Net Daily Prod
(MMcfe / day)
50-55
40-55
35-50
40-55
Current Portfolio Of Investments
Mississippi Lime (OK)
Hunton Dewatering (OK)
Woodford Shale (OK)
Fayetteville Shale (AR)
Haynesville Shale (LA)
Floyd Shale (AL)
Woodbine Shale (TX)
Trenton Black River (MI)
Barnett Shale (TX) |
 53
2014 EEI Financial Conference
Pipeline capacity expansions and regional demand should balance higher gas
production starting in mid-2017, improving Mid-Atlantic gas
basis Mid-Atlantic Gas Basis: Improves Starting 2017
•
Northeastern U.S. gas production is projected to approach 25 bcf/day by 2018,
up from 19 bcf/day in 2015 •
Regional demand is projected to reach 18 bcf/day by 2018, up from 15 bcf/day in
2015 •
Based upon public announcements, we expect 19 bcf/day of pipeline takeaway
capacity by 2018 •
Pipeline
projects
are
underway
adding
takeaway
capacity.
2017
is
a
transition
year
where
timing
of
pipeline
expansions
(~9
bcf/day)
will
play
a role in determining local gas prices, but should be more balanced than
in prior years. This is consistent with the current forward market
which indicates an improving Mid-Atlantic natural gas basis
•
Additional pipeline capacity and regional demand will stabilize basis discounts
in non winter months and reduce price spikes in the winter Notes:
Values represent annual averages; Demand includes storage
|
 54
2014 EEI Financial Conference
Northeast Gas Pipeline Expansion Projects
Almost 19 bcf/day of pipeline expansion projects have been announced for
completion by the end of 2018 |
 55
2014 EEI Financial Conference
Power Markets -
NiHub
$2-$3/MWh power price upside
in 2016-2017 due to
higher dispatch costs and a modest increase in load
Expect continued volatility
due to incremental coal
retirements in the second half of 2015
Forward markets continued their upward trend
through 2014
•
During 2014, strong spot prices have started to reflect the
changing nature of the grid in PJM and new reliance on
different resources such as NG supply, demand response,
and oil peakers
•
As a result, we have seen stronger forward power and heat
rate curves
•
Our portfolio is positioned to take advantage of expected
volatility and power price upside
•
2015 seasonal upside in the second half of the year,
especially at NIHUB off peak
•
2016-2017 average upside of $2-$3/MWh |
 56
2014 EEI Financial Conference
Capacity Markets
2013/
2014
2014/
2015
2015/
2016
2016/
2017
2017/
2018
PJM
(3,8,9)
ComEd
Capacity
N/A
N/A
N/A
N/A
10,900
Price
N/A
N/A
N/A
N/A
$120
RTO
Capacity
11,500
11,500
11,500
11,250
0
Price
$28
$126
$136
$59
$120
EMAAC
Capacity
(4)
8,900
8,900
8,900
8,900
8,300
Price
$245
$137
$168
$119
$120
MAAC
Capacity
(5)
2,300
2,300
2,300
2,300
2,300
Price
$226
$137
$168
$119
$120
SWMAAC
Capacity
(6)
1,800
1,800
1,800
1,800
900
Price
$226
$137
$168
$119
$120
BGE
Capacity
N/A
N/A
N/A
N/A
900
Price
N/A
N/A
N/A
N/A
$120
Average Exelon
$140
$132
$153
$91
$120
New England
(7)
NEMA
Capacity
2,100
2,100
2,100
2,100
2,100
Price
$98
$107
$114
$219
$493
Rest of Pool Capacity
735
445
35
35
35
Price
$85
(8)
$95
(8)
$104
(8)
$90
$231
NYISO
(9)
Rest of Pool Capacity
1,100
1,100
1,100
1,100
1,100
MISO
(10)
AMIL
Capacity
1,100
1,100
1,100
1,100
1,100
Price
N/A
N/A
N/A
1
17
RTO = Regional Transmission Organization, MAAC = Mid-Atlantic Area
Council, EMAAC = Eastern Mid-Atlantic Area Council, SWMAAC = South
West Mid-Atlantic Area Council, NEMA = North East Massachusetts;
SEMA = Southeast Massachusetts, AMIL = Ameren Illinois. PJM
RPM
Capacity
Revenues
(1,9)
Exelon Fleet Weighted Price ($/MWd)
Revenue ($MM)
(2)
(1)
Revenues reflect capacity cleared in base and incremental auctions and are for
calendar years. Revenue rounded to nearest $50M
(2)
Weighted average $/MW-Day would apply if all owned generation cleared
(3)
Reflects owned and contracted generation Installed Capacity (ICAP) adjusted for
mid-year PPA roll offs (4)
ICAP is net of Eddystone 1&2, Cromby 1&2 and Schuykill 1 (total ~ 1,100
MW) (5)
ICAP is net of Safe Harbor divestiture (total ~300 MW); Impact of Keystone
Conemaugh diestiture not included (6)
ICAP is net of units divested (Brandon Shores, Wagner & Crane ~2,648 MW; and
Riverside 6 CT (~115MW) (7)
Reflects Qualified Summer Capacity including owned and contracted units;
excludes Fore River after 14/15 (8)
Price is pro-rated for auctions that clear at the floor price and there is
more capacity procured than suggested by the reliability
requirement (9)
Reflects 50.01% ownership in CENG
(10)
Does not include wind under PPA |
 57
2014 EEI Financial Conference
PJM –
Working to Address Reliability
Source: PJM Interconnection, Response to Committee Questions of U.S. House of
Representatives Committee on Energy and Commerce, April 18, 2014, Figure
4. Source: PJM Interconnection, “Analysis of Operational Events and
Market Impacts During the January 2014 Cold Weather,”
May 9, 2014, slide 10.
The polar vortex in the winter of 2014
highlighted generator reliability concerns
that PJM is now working to address
Source: Northbridge Analysis based on PJM data
|
 58
2014 EEI Financial Conference
PJM’s Proposed Solution -
Capacity Performance Proposal
•
PJM recognizes that generation resources procured through its existing forward
capacity market (RPM) may not be sufficient to meet future load
conditions, especially at winter peak
o
Additionally, current revenues and penalty structures are insufficient to
provide incentives for necessary investment to maintain highly available
capacity •
PJM
released
a
revised
“Capacity
Performance”
proposal
on
October
7,
2014
revamping
initial
reform
concepts suggested in August
o
The Capacity Performance concept reforms are intended to encourage commitment
of capacity resources that have secure fuel and other performance
characteristics to provide PJM confidence that
units
will
be
available
when
dispatched
to
meet
peak
summer
and
winter
load
o
PJM proposes to increase the capacity market offer cap to Net CONE, and to
substantially raise penalties for performance failure
o
PJM suggests transition mechanisms for delivery years in which it has already
made forward capacity procurements (2015-16, 2016-17, and
2017-18) o
PJM
proposes
a
method
of
integrating
“wholesale”
demand
response
through
PJM
Load
Serving
Entities in a manner that would clear by adjusting the RPM demand curve
|
 59
2014 EEI Financial Conference
Capacity Performance Impact on PJM Fleet
Total Potential CP
Resources
Procurement Quantity
(80% of RPM
Reliability Target)
Source: NorthBridge Analysis; Includes FRR resources/Loads; PJM proposal is to
fully procure CP for 2016/17 and 2017/18 but to incrementally procure up to 10 GW of base capacity for
2015/16; Potential 2015/16 all-in CP procurement quantity shown for
comparison purposes Only qualifies
with
significant
cost
Qualifies
without
significant
capital cost
Exelon’s fleet is well positioned to benefit from Capacity Performance due
to significant investment in reliability
|
 60
2014 EEI Financial Conference
2014 EEI Financial Conference
Exelon Generation Disclosures
As of September 30, 2014 |
 61
2014 EEI Financial Conference
2014 EEI Financial Conference
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
Note:
Hedge
strategy
has
not
changed
as
a
result
of
recent
and
pending
asset
divestitures
Credit Rating
Capital
Structure
Capital &
Operating
Expenditure
Dividend
•Aligns hedging program with financial
policies and financial outlook
•Establish minimum hedge targets to
meet financial objectives of the
company (dividend, investment-grade
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
Three-Year Ratable Hedging
Bull / Bear Program
Strategic Policy Alignment |
           62
2014 EEI Financial Conference
2014 EEI Financial Conference
Components of Gross Margin Categories
Open Gross
Margin
•Retail, Wholesale
planned gas sales
•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
•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
•Generation Gross
Margin at current
market prices,
including capacity
& ancillary
revenues, nuclear
fuel amortization
and fossils fuels
expense
•Exploration and
Production
(4)
•PPA Costs &
Revenues
•Provided at a
consolidated level
for all regions
(includes hedged
gross margin for
South, West &
Canada
(1)
)
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
Gross margin linked to power production and sales
Gross margin from
other business activities
(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
(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
generally
remain
within
“Non
Power”
New
Business
category
and
only
move
to
“Non
Power”
Executed
category
upon
management
discretion
(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 |
 63
2014 EEI Financial Conference
2014 EEI Financial Conference
ExGen Disclosures
Gross Margin Category ($M)
(1)
2014
2015
2016
2017
Open Gross Margin
(including South, West & Canada hedged GM)
(3)
7,300
6,750
6,500
6,650
Mark
to
Market
of
Hedges
(3,4)
(350)
-
150
150
Power New Business / To Go
50
400
550
750
Non-Power Margins Executed
350
100
50
50
Non-Power New Business / To Go
50
300
350
350
Total
Gross
Margin
(2,6)
7,400
7,550
7,600
7,950
Reference Prices
(5)
2014
2015
2016
2017
Henry Hub Natural Gas ($/MMbtu)
$4.44
$4.00
$4.08
$4.22
Midwest: NiHub ATC prices ($/MWh)
$39.45
$33.70
$33.21
$33.62
Mid-Atlantic: PJM-W ATC prices ($/MWh)
$51.38
$42.75
$40.69
$40.06
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$3.02
$6.47
$6.14
$6.27
New York: NY Zone A ($/MWh)
$49.00
$42.14
$38.94
$38.37
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$3.04
$8.95
$7.64
$5.48
(1)
Gross
margin
categories
rounded
to
nearest
$50M
(2)
Total
Gross
Margin
(Non-GAAP)
is
defined
as
operating
revenues
less
purchased
power
and
fuel
expense,
excluding
revenue
related
to
decommissioning,
gross
receipts
tax,
Exelon
Nuclear
Partners
and
variable
interest
entities.
Total
Gross
Margin
is
also
net
of
direct
cost
of
sales
for
certain
Constellation
businesses.
(3)
Excludes
EDF’s
equity
ownership
share
of
the
CENG
Joint
Venture
(4)
Mark
to
Market
of
Hedges
assumes
mid-point
of
hedge
percentages
(5)
Based
on
September
30,
2014
market
conditions
(6)
Reflects
the
divestiture
impact
of
Fore
River,
Quail
Run
and
West
Valley.
Does
not
include
divestiture
of
Keystone/Conemaugh
or
the
Integrys
acquisition |
 64
2014 EEI Financial Conference
2014 EEI Financial Conference
ExGen Disclosures
Generation and Hedges
(6)
2014
2015
2016
2017
Exp. Gen (GWh)
(1)
205,300
200,800
202,200
205,000
Midwest
97,000
96,600
97,500
95,800
Mid-Atlantic
(2)
74,300
71,300
72,100
68,900
ERCOT
11,400
16,400
16,900
25,300
New York
(2)
12,700
9,400
9,300
9,300
New England
9,900
7,100
6,400
5,700
% of Expected Generation Hedged
(3)
98-101%
86-89%
55-58%
27-30%
Midwest
97-100%
83-86%
49-52%
20-23%
Mid-Atlantic
(2)
98-101%
88-91%
55-58%
28-31%
ERCOT
101-104%
99-102%
82-85%
46-49%
New York
(2)
98-101%
87-90%
62-65%
42-45%
New England
102-105%
82-85%
62-65%
25-28%
Effective Realized Energy Price ($/MWh)
(4)
Midwest
$36.50
$33.50
$34.50
$36.00
Mid-Atlantic
(2)
$48.50
$42.50
$43.00
$46.50
ERCOT
(5)
$20.00
$8.50
$5.50
$6.00
New York
(2)
$42.50
$42.50
$40.00
$38.50
New England
(5)
$6.00
$11.50
$4.50
($2.50)
(1) Expected
generation
is
the
volume
of
energy
that
best
represents
our
financial
exposure
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,
12
in
2016,
and
15
in
2017
at
Exelon-operated
nuclear
plants,
and
Salem.
Expected
generation
assumes
capacity
factors
of
93.6%,
93.5%,
94.1%
and
93.4%
in
2014,
2015
,
2016
and
2017
respectively
at
Exelon-operated
nuclear
plants,
at
ownership.
These
estimates
of
expected
generation
in
2015,
2016
and
2017
do
not
represent
guidance
or
a
forecast
of
future
results
as
Exelon
has
not
completed
its
planning
or
optimization
processes
for
those
years.
(2)
Excludes
EDF’s
equity
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.
(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.
(6)
Reflects
the
divestiture
impact
of
Fore
River,
Quail
Run
and
West
Valley.
Does
not
include
divestiture
of
Keystone/Conemaugh
or
the
Integrys
acquisition |
 65
2014 EEI Financial Conference
2014 EEI Financial Conference
ExGen Hedged Gross Margin Sensitivities
(1) Based on September 30, 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 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; Sensitivities based on commodity
exposure which includes open generation and all committed transactions; Excludes EDF’s equity share of CENG
Joint Venture; Reflects the divestiture impact of Fore River, Quail Run and
West Valley; Does not include divestiture of Keystone/Conemaugh or the Integrys acquisition
Gross Margin Sensitivities (With Existing Hedges)
(1)
2014
2015
2016
2017
Henry Hub Natural Gas ($/MMbtu)
+ $1/Mmbtu
$15
$120
$440
$830
-
$1/Mmbtu
$10
$(60)
$(400)
$(750)
NiHub ATC Energy Price
+ $5/MWh
$-
$85
$265
$390
-
$5/MWh
$-
$(85)
$(260)
$(390)
PJM-W ATC Energy Price
+ $5/MWh
$(5)
$30
$165
$260
-
$5/MWh
$5
$(25)
$(155)
$(255)
NYPP Zone A ATC Energy Price
+ $5/MWh
$-
$5
$15
$25
-
$5/MWh
$-
$(10)
$(20)
$(25)
Nuclear Capacity Factor
+/-
1%
+/-
$15
+/-
$50
+/-
$45
+/-
$45 |
 66
2014 EEI Financial Conference
2014 EEI Financial Conference
Exelon Generation Hedged Gross Margin Upside/Risk
(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
2015,
2016
and
2017
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
September
30,
2014
(2)
Gross
Margin
Upside/Risk
based
on
commodity
exposure
which
includes
open
generation
and
all
committed
transactions
$7,450
$7,300
$8,000
$7,050
Note:
Reflects
the
divestiture
impact
of
Fore
River,
Quail
Run
and
West
Valley;
Does
not
include
divestiture
of
Keystone/Conemaugh
or
the
Integrys
acquisition |
 67
2014 EEI Financial Conference
2014 EEI Financial Conference
(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. Note:
Reflects the divestiture impact of Fore River, Quail Run and West Valley; Does not include divestiture of Keystone/Conemaugh
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
$6.75 billion
(B)
Expected Generation (TWh)
97.0
71.3
16.4
9.4
7.1
(C)
Hedge % (assuming mid-point of range)
84.5%
89.5%
100.5%
88.5%
83.5%
(D=B*C)
Hedged Volume (TWh)
82.0
63.8
16.4
8.3
5.9
(E)
Effective Realized Energy Price ($/MWh)
$33.50
$42.50
$8.50
$42.50
$11.50
(F)
Reference Price ($/MWh)
$33.70
$42.75
$6.47
$42.14
$8.95
(G=E-F)
Difference ($/MWh)
$(0.20)
$(0.25)
$2.03
$0.36
$2.55
(H=D*G)
Mark-to-market value of hedges ($ million)
(1)
$(15) million
$(15) million
$30 million
$5 million
$15 million
(I=A+H)
Hedged Gross Margin ($ million)
$6,750 million
(J)
Power New Business / To Go ($ million)
$400 million
(K)
Non-Power Margins Executed ($ million)
$100 million
(L)
Non-
Power New Business / To Go ($ million)
$300 million
(N=I+J+K+L)
Total Gross Margin
(2)
$7,550 million |
 Generation |
 69
2014 EEI Financial Conference
2014 EEI Financial Conference
Exelon Generation Fleet
A clean and diverse portfolio that is well positioned for environmental upside
from EPA regulations
(1)
Reflects owned generation less announced divestitures of Fore River, Quail Run
and West Valley and Keystone Conemaugh National Scope
•
Power generation assets in 20 states and
Canada
•
Low-cost generation capacity provides
unparalleled leverage to rising commodity
prices
Large and Diverse
•
32 GW of diverse generation
(1)
—
19 GW of Nuclear
—
8 GW of Gas
—
2 GW of Hydro
—
2 GW of Oil
—
1 GW of Wind/Solar/Other
Clean
•
One of nation’s cleanest fleets as
measured by CO2, SO2 and NOx intensity
•
Less than 5% of generation capacity will
require capital expenditures to comply
with Air Toxic rules |
 70
Exelon Nuclear Fleet Overview (including CENG and Salem)
Plant Location
Type/
Containment
Water Body
License Extension Status / License
Expiration
(1)
Ownership
Spent Fuel Storage/
Date to lose full core
discharge
capacity
(2)
Braidwood, IL
(Units 1 and 2)
PWR
Concrete/Steel Lined
Kankakee River
Filed application in May 2013 (decision
expected in 2015)/ 2026, 2027
100%
Dry Cask
Byron, IL
(Units 1 and 2)
PWR
Concrete/Steel Lined
Rock River
Filed application in May 2013 (decision
expected in 2015)/ 2024, 2026
100%
Dry Cask
Clinton, IL
(Unit 1)
BWR
Concrete/Steel Lined / Mark III
Clinton Lake
2026
100%
Dry Cask
(2016)
Dresden, IL
(Units 2 and 3)
BWR
Steel Vessel / Mark I
Kankakee River
Renewed / 2029, 2031
100%
Dry Cask
LaSalle, IL
(Units 1 and 2)
BWR
Concrete/Steel Lined / Mark II
Illinois River
Application will be filed Dec 2014(decision
expected 2017)/2022, 2023
100%
Dry Cask
Quad Cities, IL
(Units 1 and 2)
BWR
Steel Vessel / Mark I
Mississippi River
Renewed / 2032
75% Exelon, 25% Mid-
American Holdings
Dry Cask
Limerick, PA
(Units 1 and 2)
BWR
Concrete/Steel Lined / Mark II
Schuylkill River
Renewed
/
2044,
2049
(5)
100%
Dry Cask
Oyster Creek, NJ
(Unit 1)
BWR
Steel Vessel / Mark I
Barnegat Bay
Renewed / 2029
(3)
100%
Dry Cask
Peach Bottom, PA
(Units 2 and 3)
BWR
Steel Vessel / Mark I
Susquehanna
River
Renewed / 2033, 2034
50% Exelon, 50% PSEG
Dry Cask
TMI, PA
(Unit 1)
PWR
Concrete/Steel Lined
Susquehanna
River
Renewed / 2034
100%
2023
Salem, NJ
(Units 1 and 2)
PWR
Concrete/Steel Lined
Delaware River
Renewed / 2036, 2040
42.6% Exelon, 57.4%
PSEG
Dry Cask
Calvert Cliffs, MD
(Units 1and 2)
PWR
Concrete/Steel Lined
Chesapeake Bay
Renewed / 2034, 2036
100% CENG
(4)
Dry Cask
R.E. Ginna, NY
(Unit 1)
PWR
Concrete/Steel Lined
Lake Ontario
Renewed / 2029
100% CENG
(4)
Dry Cask
Nine Mile Point, NY
(Units 1 and 2)
BWR
Steel Vessel / Mark I
Concrete/Steel Vessel/ Mark II
Lake Ontario
Renewed / 2029, 2046
100% CENG
(4)
/
82% CENG
(4)
, 18% Long
Island Power Authority
Dry Cask
(1)
Operating license renewal process takes approximately 4--5 years from
commencement until completion of NRC review (2)
The date for loss of full core reserve identifies when the on-site storage
pool will no longer have sufficient space to receive a full complement of fuel from the reactor core; Dry cask storage will be in operation at those sites prior to losing full core discharge
capacity in their on-site storage pools
(3)
On December 8, 2010, Exelon announced that it will permanently cease generation
operations at Oyster Creek by December 31, 2019; Oyster Creek’s
current NRC license expires in 2029 (4)
Exelon Generation has a 50.01% ownership interest in CENG (Constellation Energy
Nuclear Group, LLC). Electricite de France SA (EDF) has a 49.99% ownership interest in CENG
(5)
Limerick Received a 20 year license renewal in October 2014
2014 EEI Financial Conference |
 71
2014 EEI Financial Conference
World Class Nuclear Operator
(1)
31%
36%
14%
14%
1,208
1,169
1,104
(1)
Exelon fleet averages exclude Salem and CENG
(2)
Source: 2013 Electric Utility Cost Group (EUCG) survey. Includes
Fuel Cost plus Direct O&M divided by net generation
(3)
Source: Platts Nuclear News, Nuclear Energy Institute and Energy
Information Administration (Department of Energy)
Nuclear Production Cost ($/MWh)
(2)
Capacity Factor (%)
(3)
EXC
EXC
Exelon is consistently one of the lowest-cost and most efficient producers
of electricity in the nation
2014 EEI Financial Conference |
 72
2014 EEI Financial Conference
Net
nuclear
generation
data
at
ownership
excluding
Salem
for
all
years
CENG excluded thru 2006 -
2014, but included in 2015 and beyond at ownership
2016 includes Clinton Refueling Only outage of shortened duration.
Nuclear Output and Refueling Outages
Fleet Average Refueling Outage Duration (Days)
31%
36%
14%
14%
Nuclear Output
Nuclear Refueling Cycle
•
All Exelon-owned units are on a 24 month cycle
except for Braidwood U1/U2, Byron U1/U2,
Ginna, and Salem U1/U2, which are on 18
month cycles
•
Starting in 2015 Clinton will be on annual
cycles
Actual
Target
# of Refueling Outages
2014 Refueling Outage Impact (Includes CENG)
•
14 planned refueling outages, including 2 at
Salem
•
8 spring refueling outages (average
duration of 25 days)
•
4 fall refueling outages
•
Salem -
1 refueling outage in the spring
and 1 in the fall
•
14 planned refueling outages, including 1 at
Salem
•
7 spring refueling outages and 6 Fall
refueling outages
•
1 Salem fall refueling outage
Exelon fleet averages exclude Salem and CENG
EXC
2014 EEI Financial Conference
2015 Refueling Outage Impact |
 73
2014 EEI Financial Conference
Nuclear Fuel Costs
(1)
Projected Exelon Uranium Demand
Components of Fuel Expense in 2014
2014 –
2016: 100% hedged in volume
2017:
~96% hedged in volume
2018:
~87% hedged in volume
2019:
~64% hedged in volume
2
1
0
11
10
9
8
7
6
5
4
3
2019E
2018E
2017E
2016E
2015E
2014
Enrichment
33%
Tax/Interest
2%
Conversion
4%
Uranium
40%
Nuclear Waste
6%
Fabrication
15%
(1)
All charts exclude Salem. Includes CENG as of 4/1/2014
(2)
At ownership. Excludes costs reimbursed under the settlement agreement with the
DOE Projected
Total
Nuclear
Fuel
Spend
(2)
0
200
400
600
800
1,000
1,200
2019E
1048
2018E
1027
2017E
1020
2016E
1016
2015E
988
2014E
1000
Nuclear Fuel Capex
Nuclear Fuel Expense (Amortization + Spent Fuel)
2014 EEI Financial Conference |
 74
2014 EEI Financial Conference
Exelon
Power
Fleet
Overview
(owned
generation,
excludes
wind
and
solar)
(1) 100%, unless otherwise indicated
(2) Fossil/Hydro Capacity values shown represent summer ratings.
Net Generation Capacity (MW) is stated at proportionate ownership share
Station
Location
Number of
Units
Primary Fuel
Type
Percent
Owned
(1)
Net Generation
Capacity (MW)
(2)
Muddy Run
Drumore, PA
8
Hydro
1070
Notch Cliff
Baltimore, MD
8
Gas
118
Pennsbury
Morrisville, PA
2
Landfill Gas
6
Perryman
Belcamp, MD
5
Oil/Gas
353
Philadelphia Road
Baltimore, MD
4
Oil
61
Richmond
Philadelphia, PA
2
Oil
98
Riverside
Baltimore, MD
3
Oil/Gas
113
Salem
Lower Alloways
Creek Twp, NJ
1
Oil
42.59
16
Schuylkill
Philadelphia, PA
2
Oil
30
Southwark
Philadelphia, PA
4
Oil
52
Westport
Baltimore, MD
1
Gas
115
Southeast Chicago
Chicago, IL
8
Gas
296
Framingham
Framingham, MA
3
Oil
33
Medway
West Medway, MA
3
Oil/Gas
117
Mystic 7
Charlestown, MA
1
Oil/Gas
575
Mystic 8, 9
Charlestown, MA
2
Gas
1418
Mystic Jet
Charlestown, MA
1
Oil
9
New Boston
South Boston, MA
1
Oil
16
Wyman
Yarmouth, ME
1
Oil
5.9
36
Grand Prairie
Alberta, Canada
1
Gas
75
Hillabee
Alexander City, AL
1
Gas
670
Sunnyside
Sunnyside, UT
1
Waste Coal
50
26
Station
Location
Number of
Units
Primary Fuel
Type
Percent
Owned
(1)
Net Generation
Capacity (MW)
(2)
Colorado Bend
Wharton, TX
1
Gas
498
Handley 3
Fort Worth, TX
1
Gas
395
Handley 4, 5
Fort Worth, TX
2
Gas
870
LaPorte
Laporte, TX
4
Gas
152
Mountain Creek 6, 7
Dallas, TX
2
Gas
240
Mountain Creek 8
Dallas, TX
1
Gas
565
Wolf Hollow 1, 2, 3
Granbury, TX
3
Gas
704
Chester
Chester, PA
3
Oil
39
Colver
Colver Twp., PA
1
Waste Coal
25
26
Conowingo
Darlington, MD
11
Hydro
572
Croydon
West Bristol, PA
8
Oil
391
Delaware
Philadelphia, PA
4
Oil
56
Eddystone
Eddystone, PA
4
Oil
60
Eddystone 3, 4
Eddystone, PA
2
Oil/Gas
760
Fairless Hills
Fairless Hills, PA
2
Landfill Gas
60
Falls
Morrisville, PA
3
Oil
51
Gould Street
Baltimore, MD
1
Gas
97
Handsome Lake
Kennerdell, PA
5
Gas
268
Moser
Lower
PottsgroveTwp.,
PA
3
Oil
51
2014 EEI Financial Conference |
 75
2014 EEI Financial Conference
2014 EEI Financial Conference
Investment in New Generation Technology
Exelon is investing in an innovative, carbon-free, gas-fired technology
through an investment in NET Power to support the development of an
11.4MWe demonstration facility to prove the technology NET
Power’s
system
has
the
potential
to
transform
both
the
electricity
and
the
oil
and
gas
markets.
Using
a
novel,
supercritical
CO
2
-
power
cycle
known
as
the
Allam
Cycle,
the
technology
is
projected
to
match
or
lower
the
current
cost
of
electricity
from
natural
gas
generation
technologies
while
also
capturing
all
carbon
dioxide
emissions.
The
system
produces
carbon
dioxide
as
a
low-cost,
pipeline-quality
byproduct
as
opposed
to
a
gas
emitted
through
a
stack
in
conventional
power
plants.
The
produced
CO
2
is
ready
for
sequestration
or
use
in
enhanced
oil
recovery.
Exelon is an equity investor in the NET
Power entity and will operate the
demonstration plant
8Rivers developed and patented the
technology and holds an equity stake
in NET Power
CB&I is an equity investor in NET
Power and will provide EPC services
for the demonstration plant
Toshiba is investing in the
development and manufacturing of a
novel supercritical CO2
turbine |