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file | filename |
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EX-99.1 - PRESS RELEASE AND EARNINGS RELEASE ATTACHMENTS - EXELON CORP | d666081dex991.htm |
8-K - FORM 8-K - EXELON CORP | d666081d8k.htm |
Earnings Conference Call
4
Quarter
2013
February
6
,
2014
Exhibit 99.2
th
th |
Cautionary Statements Regarding Forward-Looking Information
This presentation contains certain forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995, that are
subject to risks and uncertainties. The factors that could cause actual
results to differ materially from the forward-looking statements
made by Exelon Corporation, Commonwealth Edison Company,
PECO
Energy
Company,
Baltimore
Gas
and
Electric
Company
and
Exelon
Generation Company, LLC (Registrants) include those factors discussed herein,
as well as the items discussed in (1) Exelons 2012 Annual
Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7.
Managements Discussion and Analysis of Financial Condition and
Results of Operations and (c) ITEM 8. Financial Statements and
Supplementary Data: Note 19; (2) Exelons Third Quarter 2013 Quarterly Report
on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b)
Part 1, Financial Information, ITEM 2. Managements 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. 2013 4Q Earnings Release Slides
1 |
2013 4Q Earnings Release Slides
2
2013 In Review
(1)
Represents adjusted (non-GAAP) operating EPS. 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 the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.
Utilities
Top quartile and best ever customer
satisfaction index scores; top
quartile in SAIFI (outage frequency)
ExGen
Nuclear capacity factor over 94%
Power dispatch match over 99%
and renewables
energy capture
over 93%
Utilities
Successful installation of 1.3M
smart
meters
ExGen
Added 158 MW of clean generation,
primarily from our AVSR solar
project
2013 adjusted operating results of
$2.50/share
(1)
Strong balance sheet and free cash
flow metrics
Achieved lower than forecasted O&M
Utilities
SB9
ComEd
and BGE rate cases
ExGen
Successful court outcomes
against subsidized generation
Continued effort to achieve market
reforms to protect competition
Operational
Excellence
Financial
Discipline
Regulatory
Advocacy
Growth
Investments
Delivered solid 2013 results in the middle of our guidance range
Providing
initial
2014
adjusted
operating
earnings
guidance
of
$2.25-$2.55/share
(2) |
Exelon
Utilities
Adjusted
Operating
EPS
Contribution
(1)
3
2013 4Q Earnings Release Slides
4Q 2013
4Q 2012
$0.19
$0.13
$0.12
$0.31
$0.10
$0.02
$0.06
$0.31
BGE
PECO
ComEd
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)
The discrete impacts include $(0.05) related to the reinstatement of the 2011
return on pension asset and $(0.04) related to 2012 pension asset costs recorded in the fourth quarter of 2012.
(3)
Due to the distribution formula rate, changes in ComEds 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
4Q13
vs.
4Q12
:
BGE
(+0.04):
Decreased storm costs: $0.02
Distribution revenue due to rate cases: $0.02
PECO
(+0.02):
Decreased storm costs: $0.03
Income taxes: $(0.01)
ComEd
(-0.06):
Discrete impacts of the 2012 distribution formula rate
order
(2)
: $(0.09)
Weather,
load
and
customer
mix
(3)
:
$0.02
2013 4Q Earnings Release Slides |
4
4Q
$0.21
2013
2012
(excludes Salem and CENG)
4Q12
Actual
4Q13
Actual
Planned Refueling Outage Days
113
94
Non-refueling Outage Days
1
33
Nuclear Capacity Factor
93.0%
92.3%
Key
Drivers
4Q13
vs.
4Q12
Lower gross margin, primarily due to lower
realized energy prices, partially offset by
increased capacity pricing: $(0.11)
Higher other expense, primarily due to lower
realized NDT fund gains: $(0.02)
Lower O&M costs, primarily due to merger
synergies:
$0.02
ExGen Adjusted Operating EPS Contribution
(1)
$0.33
(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.
2013 4Q Earnings Release Slides |
HoldCo
ExGen
ComEd
PECO
BGE
HoldCo
ExGen
ComEd
PECO
BGE
2014 Guidance
$2.25 -
$2.55
(2)
$1.10
-
$1.30
$0.50
-
$0.60
$0.40
-
$0.50
$0.20
-
$0.30
2013 Actual
$2.50
(1)
$1.40
$0.49
$0.46
$0.23
2014 Adjusted Operating Earnings Guidance
(1)
2013 results based on 2013 average outstanding shares of 860M. Refer to
Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-
GAAP) operating EPS to GAAP EPS.
(2)
2014 earnings guidance based on expected average outstanding shares of ~860M.
Earnings guidance for OpCos may not add up to consolidated EPS guidance. Refer to the Appendix for a
reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS. Key
Year-Over-Year Drivers
Lower ExGen Total Gross Margin
primarily due to lower energy prices,
partially offset by higher capacity
revenue: $(0.17)
Higher ComEd RNF primarily from DST
revenues due primarily to increasing rate
base and higher expected treasury yields
impact on ROE: $0.09
Higher BGE RNF: $0.05
Higher O&M, mainly at the utilities,
driven primarily by inflation and storm
costs offset by synergies and lower
pension/OPEB expense: $(0.07)
Higher D&A: $(0.04)
Other expense, primarily lower ExGen
interest: $0.04
5
2013 4Q Earnings Release Slides
Expect
Q1
2014
Adjusted
Operating
Earnings
of
$0.60
-
$0.70
per
share |
Exelon Consolidated Cash Flow: 2014 Expected vs 2013
Actuals
Key Messages
(6)
Adjusted Cash from Operations
(2)
is projected to be
$6,100M vs
2013A of $6,025M for a
$75M variance. This variance is primarily
driven by:
Cash from Financing activities is projected to be ($825M) vs 2013A of ($775M) for a ($50M) variance. This variance is
primarily driven by:
CapEx is projected to be
$5,475M vs 2013A $5,350M for a
($125M) variance. This
variance is primarily driven by: Projected Sources & Uses
(6)
6
2013 4Q Earnings Release Slides
2014
Projected
Sources
and
Uses
of
Cash
(7)
($ in millions)
BGE
ComEd
PECO
ExGen
Exelon
2014E
Exelon
2013A
Delta
Beginning
Cash
Balance
(1)
1,475
1,575
(100)
Adjusted Cash Flow from
Operations
(2)
650
1,525
600
3,175
6,100
6,025
75
CapEx (excluding other items
below):
(525)
(1,575)
(450)
(1,050)
(3,675)
(3,250)
(425)
Nuclear Fuel
n/a
n/a
n/a
(900)
(900)
(1,000)
100
Dividend
(3)
(1,075)
(1,250)
175
Nuclear Uprates
n/a
n/a
n/a
(150)
(150)
(150)
--
Wind
n/a
n/a
n/a
(75)
(75)
(25)
(50)
Solar
n/a
n/a
n/a
(200)
(200)
(450)
250
Upstream
n/a
n/a
n/a
(25)
(25)
(50)
25
Utility Smart Grid/Smart Meter
(75)
(200)
(175)
n/a
(450)
(425)
(25)
Net Financing (excluding
Dividend):
Debt Issuances
--
900
300
--
1,200
1,200
--
Debt Retirements
--
(625)
(250)
(525)
(1,375)
(1,600)
225
Project Finance/Federal Financing
Bank Loan
n/a
n/a
n/a
675
675
725
(50)
Other
(4)
(50)
300
100
(375)
(250)
150
1,275
1,475
(200)
(3) Dividends are subject to declaration by the Board of Directors.
(5) Includes cash flow activity from Holding Company, eliminations, and other
corporate entities. (6) All amounts rounded to the nearest $25M.
(1) Excludes counterparty collateral of $(28) million and $134 million at
12/31/12 and 12/31/13. In addition, the 12/31/14 ending cash
balance does not include collateral. (2) 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 $5.5B and
$5.4B for 2014 and 2013, respectively. (4) Other
includes CENG distribution to EDF, proceeds from stock options,
redemption of PECO preferred stock and
expected changes in short-term debt.
(7) Net 2014 sources and uses for each operating company are expected to be $0M, $325M, $125M
and $550M for BGE, ComEd, PECO and ExGen, respectively.
-
$350M Increase in ComEds 2014 distribution rates
-
$125M Income Taxes and Settlements
-
($150M) Higher working capital at the utilities
-
($225M) Lower ExGen Gross Margin
-
($350M) Higher ComEd investment in transmission, distribution and
Smart Grid / Smart Meter
-
$225M AVSR due to majority of work being completed in 2013
-
$100M Lower nuclear fuel expenditures
-
($75M) Maryland commitments
-
($400M) CENG distribution to EDF
-
$175M Increased ComEd LTD requirements primarily to fund
incremental capital investment
-
$175M Reduced dividend to common shareholders
(400)
(5)
(5)
Ending
Cash
Balance
(1) |
Adjusted O&M Forecast
(2)
2014
forecast
of
$6.6B
(1)
$550M run-rate Constellation merger synergies in 2014
Excludes costs to achieve which are considered non-operating
Expect CAGR of ~(0.6%) for
2014-2016
2014E
$6,575
(1)
-$75
$4,050
$1,225
$700
$675
2013 Actuals
$6,475
(1)
-$25
$4,000
$1,225
$650
$625
(in $M)
ExGen
(3)
ComEd
ComEd
PECO
PECO
BGE
Corp
(1)
Refer to the Appendix for a reconciliation of adjusted (non-GAAP) O&M
to GAAP O&M. Further, the Utilities adjusted O&M excludes regulatory O&M costs that are P&L neutral. ExGen adjusted
O&M excludes direct cost of sales for certain Constellation business,
P&L neutral decommissioning costs and the impact from O&M related to variable interest entities.
(2)
All amounts rounded to the nearest $25M.
(3)
Excludes CENG.
ExGen
(3)
BGE
7
Key
Year-over-Year
Drivers
(2)
Merger synergies, primarily at
ExGen:
$175M
Pension/OPEB: $75M
Inflation: $150M
Average Storm Costs: $50M
Other Utility O&M: $25M
Other ExGen O&M, primarily
contracting and other site,
corporate and project
expenses: $100M
Corp
2013 4Q Earnings Release Slides |
Exelon Utility 2014-16 Adjusted Operating EPS
Guidance
2013 4Q Earnings Release Slides
8
$1.35
$1.30
$1.20
$1.70
$1.65
$1.25
$1.60
$1.55
$1.50
$1.45
$1.40
$1.15
$1.10
$0.00
2016
$1.55
2015
$1.45
2014
$1.40
2013
$1.17
Exelon Utilities provide stable earnings growth based on sound investment and
strong operational performance
$1.25
$1.15
$1.10
(1)
Refer to Earnings Release Attachments and to the Appendix for a 2013
reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS and to the Appendix for a reconciliation of adjusted
(non-GAAP) Operating EPS guidance to GAAP EPS.
$15 billion of investment from 2014-2018 to upgrade aging infrastructure and
invest in new technologies to achieve rate base growth of 5-7%
Long-term target of 10% ROE at each utility by 2017
Managing the regulatory environment to achieve a fair rate of return at all
utilities |
Exelon Generation: Gross Margin Update
2013 4Q Earnings Release Slides
9
December 31, 2013
Change
from
Sept
30,
2013
(7)
Gross Margin Category ($M)
(1)
2014
2015
2016
2014
2015
2016
Open
Gross
Margin
(3)
margin)
5,850
5,700
5,650
250
(50)
(50)
Mark-to-Market
of
Hedges
(3,4)
750
500
250
(150)
50
-
350
650
700
(150)
(100)
(50)
Non-Power Margins Executed
100
50
50
-
-
-
300
350
350
-
-
-
7,350
7,250
7,000
(50)
(100)
(100)
Recent Developments
Severe weather in our load serving regions led to significant power and gas
volatility
Our balanced generation to load strategy, as well as our geographic and
commodity diversity, allowed
us
to
navigate
through
several
offsetting
issues
such
as
gas
curtailments
and
nuclear
outages
The return of volatility to the markets may lead to more appropriate pricing of
risk premiums Non-Power
New
Business
/
To
Go
(5)
Power New Business / To Go
4)
Mark to Market of Hedges assumes mid-point of hedge percentages.
5)
Any changes to new business estimates for our non-power business are
presented as revenue less costs of sales.
6)
Based on December 31, 2013 market conditions
7)
Adjusted gross margin based on 8-K issued on December 9, 2013. Refer to
slide 41 for details.
1)
Gross margin categories rounded to nearest $50M.
(including South, West, Canada hedged gross
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 35 for a Non-GAAP to GAAP
reconciliation of Total Gross Margin.
3)
Includes Exelons proportionate ownership share of the CENG Joint
Venture. Total
Gross
Margin
(2) |
Hedging Activity and Market Fundamentals
10
(1)
Mid-point of disclosed total portfolio hedge % range was used
2015-Actual (excl NG hedges)
2015-Ratable
2015-Actual
We have shifted our strategy from fixed-price length to a larger
cross-commodity position leaving our exposure to power upside
4Q13
3Q13
2Q13
1Q13
4Q12
3Q12
$35
$15
$60
$55
$45
$40
$50
1Q11
4Q11
2Q12
3Q11
1Q13
4Q12
3Q13
4Q13
2Q13
3Q12
1Q12
2Q11
Fundamental View PJMW
Market PJMW
Market NiHub
Fundamental View NiHub
10%
20%
30%
40%
50%
60%
70%
Fundamental
View
vs.
Market
-
2015
2015: Rotating into a Large Heat Rate Strategy
We align our hedging strategies with our fundamental
views
As of 12/31/2013 we were 2-3% behind ratable in PJM and
are relying on an even larger amount of cross-commodity
hedges to capture our view that heat rates will expand
As of 12/31/2013, Natural gas sales represented 12-15%
of our hedges in 2015 and 2016
Late in Q4, as Cal 2015-2016 gas prices increased and
heat rates declined, we shifted our strategy from fixed-price
length to a longer cross-commodity position
Structural changes in the stack are expected to increase
volatility in the spot energy market and drive prices higher
than current market
Continue to see a disconnect in forward heat rates
compared to our fundamental forecast given current
natural gas prices, expected retirements, new generation
resources, and load assumptions
2013 4Q Earnings Release Slides
Impacts of our view on our hedging activity
Impacts of our view on our hedging activity |
ExGens Financial Flexibility
Declining base CapEx, cash vs. earnings differences and balance sheet capacity
result in significant financial flexibility and robust metrics when
evaluating ExGen on a cash basis Balance Sheet Focus
Free Cash Flow Benefits
Resulting 2014 Metrics
Pension Improvements
Rising interest rate environment
results in lower pension
expense and contributions
2015 forecast of just under
$100M lower contributions than
expense
(2)
Tax Position
Use of NOLs and various tax
credits provide substantial near-
term cash tax favorability
compared to book taxes
Longer term tax position shows
tax capacity for growth
opportunities
Robust Balance Sheet
Strong cash flow metrics to
maintain investment grade
ratings and fund incremental
growth opportunities
Declining Base CapEx
Management model process
prioritizes safety and reliability
Prior investment largely to
prepare for license extensions
and mitigate
asset
management
issues
Cost initiatives to reduce capital
including reverse engineering
Key
Cash
Metrics
(1)
2013 FFO/Debt
(3)
= 37%
Improving for 2014
Well above threshold for
investment grade
Adjusted
EBITDA
Base
CapEx
= $1,500M -
$1,800M
Reducing base CapEx by
$200M from 2013-16
mitigates declining RNF
$1,225M of FCF before Growth
CapEx and Dividend
Positive FCF in excess of
planned growth CapEx
and ExGen dividend
(1)
See Slides 36-37 for a Non-GAAP to GAAP reconciliation of
cash flow metrics. (2)
Reflects Exelon consolidated forecast with the majority of the difference due
to the expected ExGen amounts. (3)
FFO/Debt for ExGen is shown using S&Ps methodology and includes
parent company debt and interest. Final 2013 calculation is still pending agency review.
2013 4Q Earnings Release Slides
11 |
$1.10 -
$1.30
$1.15 -
$1.30
Long-Term EPS Growth Potential comes from controllable
actions, opportunistic investments and market upside
12
2013 4Q Earnings Release Slides
We are committed to drive shareholder value by streamlining operations, cutting
costs, optimizing our generation portfolio and deploying capital
to drive growth.
We firmly believe that our controllable efforts coupled with market upside
should help us deliver a positive earnings CAGR by end of our planning
period Controllable
Market/Advocacy Upside
Continued investments in utilities for stable
earnings and growth
Aggressive
cost
management
in
addition
to
our
merger synergies of $550M, we expect to pursue
incremental cost cutting measures across the
organization
Operational
efficiencies
productivity
enhancements and portfolio optimization efforts
to reduce operational costs
Asset
rationalization
potential
sale
or
retirement of unprofitable assets
Capital
deployment
pursue
growth
and
investments opportunities
Power
market
upside
manage
our
portfolio in line with our fundamental
view to maximize the benefit to our
asset value
Regulatory
policies
continue
to
pursue capacity market design
changes, GHG policy implementation
and other policies to get fair
compensation for our nuclear fleet |
13
Exelon Generation Disclosures
December 31, 2013
2013 4Q Earnings Release Slides |
14
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
2013 4Q Earnings Release Slides
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
Three-Year Ratable Hedging
Bull / Bear Program
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
Capital
Structure
Dividend
Capital &
Operating
Expenditure
Credit Rating
Strategic Policy Alignment |
15
Components of Gross Margin Categories
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
2013 4Q Earnings Release Slides
Retail, Wholesale
planned electric
sales
Portfolio
Management new
business
Mid marketing new
business
Retail, Wholesale
executed gas sales
Load Response
Energy
Efficiency
(4)
BGE
Home
(4)
Distributed Solar
Retail, Wholesale
planned gas sales
Load Response
Energy
Efficiency
(4)
BGE
Home
(4)
Distributed Solar
Portfolio
Management /
origination fuels
new business
Proprietary
trading
(3)
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. 2013 4Q Earnings Release Slides
Open Gross
Margin
MtM of
Hedges
(2)
Power
New
Business
Non Power
Executed
Non Power
New Business |
16
ExGen Disclosures
Gross Margin Category ($M)
(1)
2014
2015
2016
Open Gross Margin
(including South, West & Canada hedged GM)
(3)
5,850
5,700
5,650
Mark to Market of Hedges
(3,4)
750
500
250
Power New Business / To Go
350
650
700
Non-Power Margins Executed
100
50
50
Non-Power New Business / To Go
(5)
300
350
350
Total
Gross
Margin
(2)
7,350
7,250
7,000
2013 4Q Earnings Release Slides
(1)
Gross margin categories rounded to nearest $50M.
(2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less
purchased power and fuel expense, excluding revenue related to
decommissioning, gross receipts tax, Exelon Nuclear Partners and
variable interest entities. Total Gross Margin is also net of direct cost of
sales for certain Constellation businesses. See Slide 35 for a Non-GAAP to
GAAP reconciliation of Total Gross Margin.
(3)
Includes Exelons proportionate ownership share of the CENG Joint Venture.
(4)
Mark to Market of Hedges assumes mid-point of hedge percentages.
(5)
Any changes to new business estimates for our non-power business are
presented as revenue less costs of sales.
(6)
Based on December 31, 2013 market conditions.
2013 4Q Earnings Release Slides
Reference Prices
(6)
2014
2015
2016
Henry Hub Natural Gas ($/MMbtu)
$4.19
$4.14
$4.13
Midwest: NiHub ATC prices ($/MWh)
$31.45
$30.27
$30.32
Mid-Atlantic: PJM-W ATC prices ($/MWh)
$37.90
$36.45
$36.53
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$6.56
$7.43
$6.79
New York: NY Zone A ($/MWh)
$38.25
$35.85
$35.61
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$5.16
$2.86
$0.75 |
17
ExGen Disclosures
Generation and Hedges
2014
2015
2016
Exp. Gen (GWh)
(1)
208,800
201,700
203,600
Midwest
96,900
96,600
97,600
Mid-Atlantic
(2)
74,200
70,200
71,400
ERCOT
17,100
18,700
19,200
New York
(2)
12,700
9,300
9,300
New England
7,900
6,900
6,100
% of Expected Generation Hedged
(3)
91-94%
62-65%
30-33%
Midwest
88-91%
62-65%
29-32%
Mid-Atlantic
(2)
92-95%
64-67%
33-36%
ERCOT
99-102%
51-54%
33-36%
New York
(2)
95-98%
58-61%
25-28%
New England
96-99%
64-67%
14-17%
Effective Realized Energy Price ($/MWh)
(4)
Midwest
$33.50
$32.00
$32.50
Mid-Atlantic
(2)
$45.00
$44.50
$45.50
ERCOT
(5)
$10.50
$7.00
$5.00
New York
(2)
$37.00
$43.00
$38.50
New England
(5)
$4.00
$2.50
$5.00
2013 4Q Earnings Release Slides
(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 93.7%, 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 2014, 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 Exelons 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. |
18
ExGen Hedged Gross Margin Sensitivities
Gross Margin Sensitivities (With Existing Hedges)
(1, 2)
2014
2015
2016
Henry Hub Natural Gas ($/Mmbtu)
$110
$305
$515
$(40)
$(235)
$(480)
NiHub ATC Energy Price
$30
$290
$430
$(30)
$(285)
$(430)
PJM-W ATC Energy Price
$20
$175
$270
$(15)
$(165)
$(260)
NYPP Zone A ATC Energy Price
$5
$20
$35
$(5)
$(20)
$(35)
Nuclear Capacity Factor
(3)
+/-
$45
+/-
$40
+/-
$40
2013 4Q Earnings Release Slides
(1) Based on December 31, 2013 market conditions and hedged position. Gas price
sensitivities are based on an assumed gas-power relationship derived from an internal model that is
updated periodically. Power prices sensitivities are derived by adjusting the
power price assumption while keeping all other prices inputs constant. Due to correlation of the various
assumptions, the hedged gross margin impact calculated by aggregating
individual sensitivities may not be equal to the hedged gross margin impact calculated when correlations between the
various assumptions are also considered. (2) Sensitivities based on
commodity exposure which includes open generation and all committed transactions. (3) Includes Exelons proportionate
+ $1/Mmbtu
-
$1/Mmbtu
+ $5/MWh
-
$5/MWh
+ $5/MWh
-
$5/MWh
+ $5/MWh
-
$5/MWh
+/-
1%
ownership share of the CENG Joint Venture.
2013 4Q Earnings Release Slides |
19
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
2016
$8,550
2015
$7,950
2014
$7,650
$7,050
$6,650
$5,700
(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
December 31, 2013 (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 35 for a
Non-GAAP to GAAP reconciliation of Gross Margin.
2013 4Q Earnings Release Slides |
20
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
$5.70 billion
(B)
Expected Generation (TWh)
96.6
70.2
18.7
9.3
6.9
(C)
Hedge % (assuming mid-point of range)
63.5%
65.5%
52.5%
59.5%
65.5%
(D=B*C)
Hedged Volume (TWh)
61.3
46.0
9.8
5.5
4.5
(E)
Effective Realized Energy Price ($/MWh)
$32.00
$44.50
$7.00
$43.00
$2.50
(F)
Reference Price ($/MWh)
$30.27
$36.45
$7.43
$35.85
$2.86
(G=E-F)
Difference ($/MWh)
$1.73
$8.05
$(0.43)
$7.15
$(0.36)
(H=D*G)
Mark-to-market value of hedges ($ million)
(1)
$110 million
$370 million
$(5) million
$40 million
$0 million
(I=A+H)
Hedged Gross Margin ($ million)
$6,200 million
(J)
Power New Business / To Go ($ million)
$650 million
(K)
Non-Power Margins Executed ($ million)
$50 million
(L)
Non-
Power New Business / To Go ($ million)
$350 million
(N=I+J+K+L)
Total Gross Margin
(2)
$7,250 million
(1) Mark-to-market rounded to the nearest $5 million.
(2) Total 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 35 for a Non-GAAP
to GAAP reconciliation of Total Gross Margin. 2013 4Q Earnings Release
Slides |
21
Additional Disclosures
2013 4Q Earnings Release Slides
2013 4Q Earnings Release Slides |
2014
(4)(5)
$0.50 -
$0.60
Other
($0.02)
Depreciation &
Amortization
($0.01)
O&M
(3)
($0.00)
RNF
(2)
$0.09
2013
(1)
$0.01
ComEd Adjusted Operating EPS Bridge 2013 to 2014
Note: Drivers add up to mid-point of 2014 adjusted operating EPS
range. (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)
Revenue
net
fuel
(RNF)
is
defined
as
operating
revenues
less
purchased
power
and
fuel
expense.
(3) O&M excludes regulatory items that are P&L neutral.
(4) Shares Outstanding (diluted) are 860M in 2013 and ~860M in 2014. Refer to
slide 33 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.
(5) Guidance assumes an effective tax rate for 2014 of 39.9%.
$0.10 Distribution
$0.01 Transmission
($0.01) Weather/Volume
Interest
22
2013 4Q Earnings Release Slides
$0.02 Pension/OPEB
($0.02) Inflation
$0.49 |
2014
(4)(5)
$0.40 -
$0.50
Other
$0.01
O&M
(3)
($0.03)
RNF
(2)
$0.01
PECO Adjusted Operating EPS Bridge 2013 to 2014
23
2013 4Q Earnings Release Slides
2013
(1)
($0.02) Storm Costs
($0.01) Inflation
$0.01 Smart Meter Return
$0.46
Note: Drivers add up to mid-point of 2014 adjusted operating EPS range.
(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) Revenue
net
fuel
(RNF)
is
defined
as
operating
revenues
less
purchased
power
and
fuel
expense.
(3) O&M excludes regulatory items that are P&L neutral.
(4)
Shares
Outstanding
(diluted)
are
860M
in
2013
and
~860M
in
2014.
(5)
Guidance
assumes
an
effective
tax
rate
for
2014
of
30.4%
Refer
to
slide
33
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
EPS
guidance
to
GAAP
EPS. |
($0.03)
2014
(4)(5)
$0.20 -
$0.30
Other
$0.01
Depreciation &
Amortization
($0.01)
O&M
(3)
RNF
(2)
$0.05
2013
(1)
BGE Adjusted Operating EPS Bridge 2013 to 2014
($0.01) Storm Costs
($0.01) Inflation
($0.01) Other O&M
$0.05 Pricing/Mix
($0.01) Other RNF
24
2013 4Q Earnings Release Slides
$0.01 Interest
$0.23
2013 4Q Earnings Release Slides
Note: Drivers add up to mid-point of 2014 adjusted operating EPS
range. (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) Revenue
net
fuel
(RNF)
is
defined
as
operating
revenues
less
purchased
power
and
fuel
expense.
(3) O&M excludes regulatory items that are P&L neutral.
(4) Shares
Outstanding
(diluted)
are
860M
in
2013
and
~860M
in
2014.
Refer
to
slide
33
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
EPS
guidance
to
GAAP
EPS.
(5) Guidance
assumes
an
effective
tax
rate
for
2014
of
39.1%. |
$0.02
Depreciation &
Amortization
(4)
$0.02
O&M
(3)
$0.03
Gross Margin
(2)
$0.17
2013
2014
(5)(6)
$1.10 -
$1.30
Other
ExGen Adjusted Operating EPS Bridge 2013 to 2014
($0.17) Generation Gross Margin primarily due
to lower pricing
$0.09 Merger synergies
$0.02 Pension/OPEB
($0.06) Inflation
($0.02) Contracting
($0.02) Site, Corporate and Project
Spending
($0.01) Nuclear Refueling Outages
($0.03) Other O&M
25
$0.01 Interest
$0.01 Other
$1.40
2013 4Q Earnings Release Slides
($0.02) Primarily AVSR and other
assets placed in service
(5) Shares
Outstanding
(diluted)
are
860M
in
2013
and
~860M
in
2014.
Refer
to
slide
33
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
EPS
guidance
to
GAAP
EPS.
(6) Guidance
assumes
an
effective
tax
rate
for
2014
of
29.7%.
Note: Drivers add up to mid-point of 2014 adjusted operating EPS
range. (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) 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 35 for a Non-GAAP to GAAP reconciliation of Total Gross Margin.
(3)
O&M
excludes
items
that
are
P&L
neutral
(including
decommissioning
costs
and
variable
interest
entities)
and
direct
cost
of
sales
for
certain
Constellation
businesses.
(4) Depreciation & Amortization excludes cost of sales for certain
Constellation businesses, which are included in gross margin |
26
Additional 2014 ExGen and CENG Modeling
2013 4Q Earnings Release Slides
P&L Item
2014 Estimate
ExGen
Model
Inputs
(1)
O&M
(2)
$4,050M
Taxes Other Than Income (TOTI)
(3)
$300M
Depreciation & Amortization
(4)
$800M
Interest Expense
$325M
CENG
Model
Inputs
(at
ownership)
(1)(5)
Gross Margin
Included in ExGen Disclosures
O&M/TOTI
$400M -
$450M
Depreciation & Amortization/Accretion of Asset
Retirement Obligations
$100M -
$150M
Capital Expenditures
$75M -
$125M
Nuclear Fuel Capital Expenditure
$50M -
$100M
(3)
TOTI excludes gross receipts tax for retail of $100M.
(4)
ExGen Depreciation & Amortization excludes the impact of P&L neutral
decommissioning costs of $25M and cost of sales of ExGens non-power businesses of $25M.
(5)
Includes ~$35M potential synergies related to the integration of Exelon Nuclear
and CENG operations. The CENG model inputs are intended to support Exelons guidance range and do
not represent CENGs final estimates. (2)
ExGen O&M excludes cost of sales of certain Constellation businesses,
certain impacts associated with the sale or retirement of generating stations, certain costs incurred associated with
the merger with Constellation, P&L neutral decommissioning costs, and the
impact from O&M related to variable interest entities. See Slide 33 for a Non-GAAP to GAAP reconciliation of
O&M.
(1)
ExGen amounts for O&M, TOTI and Depreciation & Amortization
exclude the impacts of CENG. CENG impact is reflected in Equity earnings of unconsolidated affiliates in the Statement
of Operations and Comprehensive Income. |
BGE
2014 load growth driven by a
stronger Residential class
and
improving economic conditions,
partially offset by
energy efficiency
27
Exelon Utilities Weather-Normalized Load
2014E
0.4%
-0.6%
-0.4%
-0.2%
2013
-0.3%
-0.5%
0.0%
-0.2%
Large C&I
Small C&I
Residential
All Customers
ComEd
2014 forecasted usage reflects a
continuation of the moderate growth
economy and on-going energy
efficiency programs
2014E
1.5%
-1.2%
-0.3%
0.3%
2013
1.5%
-1.1%
0.0%
0.3%
PECO
2014 load growth is driven by
modest economic growth and
strong growth in manufacturing
employment , partially offset by
energy efficiency.
2014E
0.0%
-0.4%
1.5%
0.6%
2013
-2.5%
2.4%
0.9%
-0.6%
Chicago GMP
2.3%
Chicago Unemployment
8.6%
Philadelphia GMP
2.1%
Philadelphia Unemployment
7.4%
Baltimore GMP
2.1%
Baltimore Unemployment
6.6%
2013 4Q Earnings Release Slides
Notes: Data is not adjusted for leap year. Source of 2013 economic
outlook data is Global Insight (November 2013). Assumes 2013 GDP of 1.7% 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 unbilled / true-up load from prior
quarters.
2013 4Q Earnings Release Slides |
2013 4Q Earnings Release Slides
28
ComEd April 2013 Distribution Formula Rate Updated Filing
Note: Disallowance of any items in the 2013 distribution formula rate
filing could impact 2013 earnings in the form of a regulatory asset adjustment. Amounts above as of surrebuttal testimony.
The 2013 distribution formula rate filing establishes the net revenue
requirement used to set the rates that will take effect in January 2014 after the ICCs
review. The filing was updated to reflect the impact of Senate Bill 9.
There are two components to the annual distribution formula rate filing:
Filing Year: Based on prior year costs (2012) and current year (2013)
projected plant additions.
Annual
Reconciliation:
For
the
prior
calendar
year
(2012),
this
amount
reconciles
the
revenue
requirement
reflected
in
rates
during
the
prior
year
(2012)
in
effect
to
the
actual
costs
for
that
year.
The
annual
reconciliation
impacts
cash
flow
in
the
following
year
(2014)
but
the earnings
impact has been recorded in the prior year (2012) as a regulatory asset.
|
29
BGE Rate Case
2013 4Q Earnings Release Slides
Rate Case Order
Electric
Gas
Docket #
9326
Test Year
August 2012
July 2013
Common Equity Ratio
51.1%
Authorized Returns
ROE: 9.75%; ROR: 7.49%
ROE: 9.6%; ROR: 7.41%
Rate Base
$2.8B
$1.0B
Revenue Requirement Increase
$33.6M
$12.5M
Distribution Price Increase as % of
overall bill
1.7%
1.1%
Timeline
5/17/13: BGE filed application with the MDPSC seeking increases in gas &
electric distribution base rates
8/5/13: Staff/Intervenors file direct testimony
8/23/13: Update 8 months actual/4 month estimated test period data with actuals
for last 4 months (March -
July 2013)
9/17/13: BGE and staff/intervenors file rebuttal testimony
10/3/13: Staff/Intervenors and BGE file surrebuttal testimony
10/18/13
11/1/13: Hearings
11/12/13: Initial Briefs
11/22/13: Reply Briefs
12/13/13: Final Order
New rates are in effect shortly after the final order
|
30
Appendix
Reconciliation of Non-GAAP
Measures
2013 4Q Earnings Release Slides |
4Q GAAP EPS Reconciliation
Three Months Ended December 31, 2013
ExGen
ComEd
PECO
BGE
Other
Exelon
2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.21
$0.13
$0.12
$0.06
$(0.02)
$0.50
Mark-to-market impact of economic hedging activities
0.16
-
-
-
-
0.16
Unrealized gains related to NDT fund investments
0.05
-
-
-
-
0.05
Plant Retirements and Divestitures
-
-
-
-
-
-
Merger and integration costs
(0.02)
-
(0.00)
(0.00)
-
(0.02)
Reassessment of State Deferred Income Taxes
0.01
-
-
-
(0.02)
-
Amortization of commodity contract intangibles
(0.09)
-
-
-
-
(0.09)
Asset Retirement Obligation
-
-
-
-
-
-
Midwest Generation bankruptcy charges
(0.02)
-
-
-
-
(0.02)
Long-lived asset impairments
-
-
-
-
-
-
4Q 2013 GAAP Earnings (Loss) Per Share
$0.31
$0.13
$0.12
$0.05
$(0.04)
$0.58
NOTE: All amounts shown are per Exelon share and represent contributions
to Exelon's EPS. Amounts may not add due to rounding. 2013 4Q
Earnings Release Slides 31
Three Months Ended December 31, 2012
ExGen
ComEd
PECO
BGE
Other
Exelon
2012 Adjusted (non-GAAP) Operating Earnings Per Share
$0.33
$0.19
$0.09
$0.02
$0.00
$0.64
Mark-to-market impact of economic hedging activities
0.17
-
-
-
(0.03)
0.14
Unrealized gains related to nuclear decommissioning trust funds
-
-
-
-
-
-
Plant retirements and divestitures
(0.05)
-
-
-
-
(0.05)
Asset retirement obligation
0.01
-
-
-
-
0.01
Merger and integration costs
(0.04)
(0.00)
(0.00)
(0.00)
(0.00)
(0.05)
Amortization of commodity contract intangibles
(0.24)
-
-
-
-
(0.24)
Amortization of the fair value of certain debt
-
-
-
-
-
-
Non-cash remeasurement of deferred income taxes
(0.01)
-
-
-
0.01
-
Midwest Generation bankruptcy charges
(0.01)
-
-
-
-
(0.01)
4Q 2012 GAAP Earnings (Loss) Per Share
$0.16
$0.19
$0.09
$0.02
$(0.02)
$0.44 |
2013 4Q Earnings Release Slides
32
Twelve
Months
Ended
December
31,
2012
ExGen
ComEd
PECO
BGE
Other
Exelon
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.89
$0.47
$0.47
$0.06
$(0.04)
$2.85
Mark-to-market impact of economic hedging activities
0.38
-
-
-
0.00
0.38
Unrealized gains related to nuclear decommissioning trust funds
0.07
-
-
-
-
0.07
Plant retirements and divestitures
(0.29)
-
-
-
-
(0.29)
Asset retirement obligation
(0.00)
-
-
-
-
(0.00)
Constellation merger and integration costs
(0.20)
(0.00)
(0.01)
(0.01)
(0.09)
(0.31)
Maryland commitments
(0.03)
-
-
(0.10)
(0.15)
(0.28)
Amortization of commodity contract intangibles
(0.93)
-
-
-
-
(0.93)
FERC settlement
(0.21)
-
-
-
-
(0.21)
Reassessment of state deferred income taxes
0.00
-
-
-
0.14
0.14
Amortization of the fair value of certain debt
0.01
-
-
-
-
0.01
Other acquisition costs
(0.00)
-
-
-
(0.00)
Midwest Generation bankruptcy charges
(0.01)
-
-
-
(0.01)
YTD 2012 GAAP Earnings (Loss) Per Share
$0.69
$0.46
$0.46
$(0.05)
$(0.14)
$1.42
Twelve
Months
Ended
December
31,
2013
ExGen
ComEd
PECO
BGE
Other
Exelon
2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.40
$0.49
$0.46
$0.23
$(0.07)
$2.50
Mark-to-market impact of economic hedging activities
0.35
-
-
-
-
0.35
Unrealized gains related to NDT fund investments
0.09
-
-
-
-
0.09
Plant retirements and divestitures
0.02
-
-
-
-
0.02
Asset retirement obligation
(0.01)
-
-
-
-
(0.01)
Merger and integration costs
(0.09)
(0.00)
(0.01)
0.00
(0.00)
(0.10)
Amortization of commodity contract intangibles
(0.41)
-
-
-
-
(0.41)
Reassessment of State Deferred Income Taxes
0.01
-
-
-
(0.01)
-
Amortization of the fair value of certain debt
0.01
-
-
-
-
0.01
Remeasurement of like kind exchange tax position
-
(0.20)
-
-
(0.11)
(0.31)
Midwest Generation Bankruptcy Charges
(0.02)
-
-
-
-
(0.02)
Long lived asset impairments
(0.12)
-
-
-
(0.01)
(0.14)
YTD 2013 GAAP Earnings (Loss) Per Share
$1.24
$0.29
$0.45
$0.23
$(0.22)
$2.00
Full Year GAAP EPS Reconciliation
NOTE: All amounts shown are per Exelon share and represent contributions
to Exelon's EPS. Amounts may not add due to rounding. |
GAAP to Operating Adjustments
2013 4Q Earnings Release Slides
Exelons 2014-16 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
One-time impacts of adopting new accounting standards
Other unusual items
33 |
Adjusted O&M Reconciliations to GAAP
34
2013 Adjusted O&M Reconciliation (in $M)
(4)
ExGen
ComEd
PECO
BGE
Other
Exelon
GAAP O&M
$4,500
$1,400
$725
$625
$(0)
$7,250
Impacts associated with Sale or Retirement of Generating
Stations
-
-
-
-
-
-
Certain costs incurred associated with the integration of
Constellation and CENG
$(100)
-
-
-
-
$(100)
Long Lived Asset Impairments
$(150)
-
-
-
$(25)
$(175)
Asset Retirement Obligations
-
-
-
-
-
-
Regulatory O&M
(3)
-
$(175)
$(75)
-
-
$(250)
Decommissioning and other expense
(1)
$(50)
-
-
-
-
$(50)
Direct cost of sales incurred to generate revenues for
certain Constellation businesses
(2)
$(200)
-
-
-
-
$(200)
Adjusted O&M (Non-GAAP, as shown on slide
7) $4,000
$1,225
$650
$625
$(25)
$6,475
2014 Adjusted O&M Reconciliation (in $M)
(4)
ExGen
ComEd
PECO
BGE
Other
Exelon
GAAP O&M
$4,400
$1,475
$800
$700
$(75)
$7,300
Certain costs incurred associated with the integration of
Constellation and CENG
$(150)
-
-
-
-
$(150)
Regulatory O&M
(3)
-
$(250)
$(100)
$(25)
-
$(375)
Decommissioning and other expense
(1)
-
-
-
-
-
-
Direct cost of sales incurred to generate revenues for certain
Constellation businesses
(2)
$(200)
-
-
-
-
$(200)
Adjusted O&M (Non-GAAP, as shown on slide
7) $4,050
$1,225
$700
$675
$(75)
$6,575
2013 4Q Earnings Release Slides
(1)
Other expense primarily reflects O&M related to variable interest entities.
(2)
Reflects the direct cost of sales of certain Constellation businesses of
Generation, which are included in Total Gross Margin. (3)
Reflects P&L neutral O&M.
(4)
All amounts rounded to the nearest $25M. |
ExGen Total Gross Margin Reconciliation to GAAP
35
Total Gross Margin Reconciliation (in $M)
(5)
2014
2015
2016
Revenue
Net
of
Purchased
Power
and
Fuel
Expense
(1)(6)
$7,650
$7,650
$7,400
Non-cash amortization of intangible assets, net, related to
commodity
contracts
recorded
at
fair
value
at
the
merger
date
(2)
$50
-
-
Other Revenues
(3)
$(100)
$(100)
$(50)
Direct cost of sales incurred to generate revenues for certain
Constellation businesses
(4)
$(250)
$(300)
$(350)
Total Gross Margin (Non-GAAP, as shown on slide
9) $7,350
$7,250
$7,000
2013 4Q Earnings Release Slides
(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 $50M.
(6)
Excludes the impact of the operating exclusion for mark-to-market due
to the volatility and unpredictability of the future changes to power prices. |
36
2013 ExGen/HoldCo FFO/Debt and 2014 ExGen Free Cash
Flow Reconciliations to GAAP
FFO
Calculation
($M)
(1)
GAAP Operating Income
$1,675
Depreciation & Amortization
$850
EBITDA
$2,525
+/-
Nonoperating activities
and nonrecurring items
$200
-
Interest Expense
($350)
-
Current Income Tax Expense
($300)
+ Nuclear Fuel Amortization
$925
+ PPA Depreciation
Adjustment
(3)
$325
+ Operating Lease
Depreciation Adjustment
(4)
$25
+/-
Other FFO Adjustments
(5)
$125
= FFO (a)
$3,475
(1)
All amounts rounded to the nearest $25M.
(2)
Using S&P Methodology
final 2013 numbers still pending agency review.
(3)
Reflects net capacity payment -
interest on PV of PPA's (using 7% discount rate from S&P).
(4)
Reflects operating lease payments -
interest on PV of future operating leases payments (using 7% discount rate
from S&P). (5)
Includes pension adjustment, stock compensation adjustment, HoldCo interest
adjustment, and capitalized interest expense adjustment . (6)
Reflects PV of net capacity purchases (using 7% discount rate from
S&P). (7)
Reflects
PV
of
minimum
future
operating
lease
payments
(using
7%
S&P
discount rate).
(8)
Reflects unfunded status, net of taxes at 35%.
(9)
Long term debt held at HoldCo imputed to ExGen.
(10)
Includes non-recourse project debt.
(11)
Offsets FV write-up of CEG and BGE (recorded at Corp) debt at merger.
(12)
Applies 75% of excess cash against balance of LTD.
(13)
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
5.5B
for
2014
2013 4Q Earnings Release Slides
Long-Term Debt (including
current maturities)
$7,725
Short-Term Debt
25
+ PPA Imputed Debt
(6)
$1,350
+ Operating Lease Imputed
Debt
(7)
$300
+ Pension/OPEB Imputed
Debt
(8)
$1,125
+ HoldCo Debt Adjustment
(9)
$1,400
-
Off-Credit Treatment of
Debt
(10)
($1,225)
-
Fair Value Adjustment
(11)
($375)
-Surplus Cash Adjustment
(12)
($950)
+/-
Accrued Interest
$75
= Adjusted Debt (b)
$9,450
2014 Free Cash Flow
Calculation
($M)
(1)
Adjusted Cash from
Operations
(13)
$3,175
Non-Growth CapEx
(includes MD
Commitments)
($1,050)
Nuclear Fuel CapEx
($900)
= FCF before Growth
CapEx and Dividend
$1,225
2013
FFO/Debt
(2)
FFO (a)
=
37%
Adjusted Debt (b)
Adjusted
Debt
Calculation
($M)
(1) |
37
2014 ExGen Adjusted EBITDA
Base CapEx Reconciliation to
GAAP
Adjusted EBITDA
Adjusted Operating Net Income
(1)
$950M -
$1,125M
Depreciation & Amortization
(2)
$800M
Interest Expense
(2)
$325M
Taxes/Other
(3)
$275M -
$400M
Adjusted EBITDA
(6)
$2,350M -
$2,650M
Base CapEx
Total Capital Expenditures
(4)
$2,400M
Growth CapEx (Nuclear Uprates/Wind/Solar/Upstream)
(4)
($450M)
Nuclear Fuel
(4)
($900M)
Fukushima Response
(5)
($100M)
Maryland Commitments
(5)
($100M)
Base CapEx
(6)
$850M
2013 4Q Earnings Release Slides
(1)
Adjusted Operating Net Income (non-GAAP) is based on the adjusted
operating EPS range provided on slide 5 and ~860M shares outstanding. Refer to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS guidance
to GAAP EPS.
(2)
Refer to slide 26 for details. ExGen Depreciation & Amortization excludes
the impact of P&L neutral decommissioning costs of $25M and cost of sales of ExGens
non-power businesses of $25.
(3)
Includes taxes based on the effective tax rate of 29.7%, decommissioning income
and other items.
(4)
Refer to slide 6 for ExGen CapEx amounts.
(5)
Fukushima Response and Maryland Commitments both included in the CapEx
(excluding other items below line item on slide 6 but are one-time in nature and
therefore excluded from Base CapEx.
(6)
Excludes CENG. |
38
Appendix
Change to Format of Exelon
Generation Disclosures
8-K issued December 9, 2013
All numbers as of September 30, 2013
2013 4Q Earnings Release Slides |
39
Change
to
Format
of
Exelon
Generation
Disclosures
Gross
Margin, O&M and Depreciation & Amortization Definitions
Direct costs incurred to generate revenues (Cost of Sales) for
certain Constellation businesses (Energy Efficiency, BGE Home and
Upstream) have been included in O&M or Depreciation &
Amortization (D&A) in previous Exelon Generation
disclosures
Cost of Sales previously included in O&M and D&A is approximately $250M
- $300M/year
Including the Cost of Sales in Gross Margin better reflects the scale of these
Constellation businesses while reducing volatility in disclosures
resulting from only capturing changes in revenue
Beginning with Q4 2013 Exelon Generation disclosure, Exelon is revising
Gross
Margin
to
include
Cost
of
Sales
for
certain
Constellation
businesses;
while simultaneously reducing O&M and D&A by an equal amount
Effect of revised format:
Gross Margin
lowered by
$250M -
$300M
O&M/D&A
lowered by
$250M -
$300M
Net Change to EBIT
$0 |
40
Impacted Components of Gross Margin Categories
Margins move from new business to MtM of hedges over
the course of the year as sales are executed
Margins move from Non power new business
to
Non power executed
over the course of the year
Gross margin linked to power production and sales
Gross margin from
other business activities
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)
)
Retail, Wholesale
planned gas sales
Load Response
Energy
Efficiency
(4)
BGE
Home
(4)
Distributed Solar
Portfolio Management
/ origination fuels new
business
Proprietary trading
(3)
(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. These
sections
going
forward
will
be
inclusive
of
Cost
of
Sales;
see
additional
Footnote
(4)
Open Gross
Margin
MtM of
Hedges
(2)
Power
New
Business
Non Power
Executed
Non Power
New Business |
41
ExGen Disclosures
Previous and Revised Presentations
Sept
30,
2013
Revised
presentation
Change from previous
presentation
Gross Margin Category ($M)
2013
2014
2015
2016
2013
2014
2015
2016
Open Gross Margin
(including South, West, Canada hedged gross
margin)
$5,550
$5,600
$5,750
$5,700
($50)
($50)
($50)
($100)
Mark-to-Market of Hedges
$1,700
$900
$450
$250
0
0
0
0
Power New Business / To Go
$50
$500
$750
$750
0
0
0
0
Non-Power Margins Executed
$300
$100
$50
$50
($100)
($100)
($50)
($50)
Non-Power New Business / To Go
$100
$300
$350
$350
($100)
($100)
($150)
($150)
Total Gross Margin
$7,700
$7,400
$7,350
$7,100
($250)
($250)
($250)
($300)
These reductions shown in gross margin, are offset by commensurate
reductions in O&M and D&A; There is no impact on net income
Gross
Margin
Category
($M)
(1,2)
(as presented in EEI presentation slide 37)
2013
2014
2015
2016
Open Gross Margin
(including South, West & Canada hedged GM)
(3)
$5,600
$5,650
$5,800
$5,800
Mark to Market of Hedges
(3,4)
$1,700
$900
$450
$250
Power New Business / To Go
$50
$500
$750
$750
Non-Power Margins Executed
(5)
$400
$200
$100
$100
Non-Power New Business / To Go
(5)
$200
$400
$500
$500
Total Gross Margin
$7,950
$7,650
$7,600
$7,400
(1)
Gross margin (net of direct cost of sales) rounded to nearest $50M.
(2)
Gross margin does not include revenue related to decommissioning, gross
receipts tax, Exelon Nuclear Partners and entities consolidated solely
as a result of the application of FIN 46R.
(3)
Includes CENG Joint Venture.
(4)
Mark to Market of Hedges assumes mid-point of hedge percentages.
(5)
Any changes to new business estimates for our non-power business
are presented as revenue less costs of sales.
(6)
Based on September 30, 2013 market conditions. |
P&L Item
2013 Estimate
ExGen
Model
Inputs
(1)
O&M
(2)
$4,275M
$4,075M
Taxes Other Than Income (TOTI)
(3)
$300M
No change
Depreciation & Amortization
(4)
$825M
$775M
Interest Expense
$350M
No change
CENG
Model
Inputs
(at
ownership)
(5)
Gross Margin
Included in ExGen Disclosures
No change
O&M/TOTI
$400M -
$450M
No change
Depreciation & Amortization/Accretion of
Asset Retirement
Obligations
$100M -
$150M
No change
Capital Expenditures
$75M -
$125M
No change
Nuclear Fuel Capital Expenditure
$100M -
$150M
No change
42
Additional 2013 ExGen and CENG Modeling
Previous and
Revised Presentations
EEI Slide 13 presentation
Revised presentation
(1)
ExGen amounts for O&M, TOTI and Depreciation & Amortization exclude the
impacts of CENG. CENG impact is reflected in Equity earnings of unconsolidated affiliates in the
Income Statement.
(2)
ExGen O&M excludes costs of sales for certain Constellation businesses,
P&L neutral decommissioning costs and the impact from O&M related to entities consolidated solely
as a result of the application of FIN 46R.
(3)
TOTI excludes gross receipts tax for retail.
(4)
ExGen Depreciation & Amortization excludes costs of sales for certain
Constellation businesses and the impact of P&L neutral decommissioning.
(5)
The CENG model inputs are intended to support Exelons guidance range and
do not represent CENGs final estimates.
Reduced O&M ~$200M and
D&A ~$50M. Footnotes (2)
and (4) have been updated
to reflect new definition |