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EX-99.1 - PRESS RELEASE AND EARNINGS RELEASE ATTACHMENTS - EXELON CORP | d872864dex991.htm |
8-K - 8-K - EXELON CORP | d872864d8k.htm |
Earnings Conference Call
4
th
Quarter 2014
February 13
th
, 2015
Exhibit 99.2 |
1
2014 4Q Earnings Release Slides
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 2014 Annual
Report on Form 10-K (to be filed on February 13, 2015) 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 22 and (2) 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. |
2014 4Q Earnings Release Slides
2
Utilities
Top decile for safety; top quartile for
outage frequency
ExGen
Nuclear capacity factor over 94%
(2)
Power dispatch match nearly 97%
and renewables energy capture of
95%
2014 adjusted operating results of
$2.39/share
(1)
Total shareholder return of 41%
Successful ~$3B billion forward equity
and mandatory convertible offering
$75M in total savings from
consolidation of CENG plants
(3)
$675M ExGen Texas Power Financing
2014 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)
Exelon operated plants at ownership
(3)
Total CapEx and O&M savings from consolidation. Includes EDFs equity
ownership share of the CENG Joint Venture
Delivered solid 2014 results at the mid-point of our guidance range
Financial
Discipline
Operational
Excellence
Growth
Investments
Regulatory
Advocacy
Utilities
$3.1 billion invested in technology
and infrastructure
PHI Acquisition
ExGen
Integrys and ProLiance Acquisitions
Texas CCGTs, Bloom & NetPower
partnership
Added 215 MW of clean generation
ComEd and BGE rate cases:
3
rd
consecutive rate case in which
ComEd
achieved
95%
of
its
ask
1
st
rate case settlement for BGE
since 1999
ExGen
HR 1146
Capacity Performance Product
EPAs Clean Power Plan (111(d)) |
3
2014 4Q Earnings Release Slides
HoldCo
ExGen
ComEd
PECO
BGE
HoldCo
ExGen
ComEd
PECO
BGE
2015 Guidance
$2.25 -
$2.55
(2)
$1.15 -
$1.35
$0.45 -
$0.55
$0.35 -
$0.45
$0.20 -
$0.30
$2.39
(1)
$1.34
$0.47
$0.41
$0.23
2015 Adjusted Operating Earnings Guidance
(1)
2014 results based on 2014 average outstanding shares of 864M. 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)
2015 earnings guidance based on expected average outstanding shares of ~866M. 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. Expect
Q1
2015
Adjusted
Operating
Earnings
of
$0.60
-
$0.70
per
share
2014 Actual
Key Year-Over-Year Drivers
Total impact of asset divestitures:
$(0.12)
Additional planned nuclear outage
$(0.02)
ExGen Pension/OPEB: $(0.02)
ComEd: increased capital
investments in distribution and
transmission partially offset by
lower US Treasury Yields: $0.03
Capacity Prices: $0.07
Full year elimination of DOE fee:
$0.04 |
4
2014 4Q Earnings Release Slides
Adjusted O&M Forecast
(2)
2015 forecast of $7.225B
(1)
Expect CAGR of ~0.2 % for
2015-2017
2015E
$7,225
(1)
$4,525
$1,250
$750
$775
2014 Actuals
$6,950
(1)
$4,350
$1,200
$750
$725
(in $M)
ExGen
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 businesses,
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)
Prior
to
consolidation
on
April
1,
2014,
CENG
was
under
the
equity
method
of
accounting.
CENG
0&M
prior
to
consolidation
is
not
included.
ExGen
(3)
BGE
Key Year-over-Year Drivers
(2)
Growth including Integrys & full
year of CENG: $250M
Inflation: $125M
Plant Divestitures: $(100M)
Pension/OPEB: $50M
PECO Storm Costs:
$(50M)
BGE & ComEd Storm Costs: $25M
Corp
-75
-75 |
5
2014 4Q Earnings Release Slides
Hedging Activity and Market Fundamentals
Heat Rates have expanded throughout 2014
% of Expected Generation Hedged
(1)
Total Portfolio
(1)
Mid-point of disclosed hedge % ranges was used
Impacts of our view on our hedging activity
Over the last several quarters, power prices have increased and heat rates have
expanded
We have adjusted our strategy by reducing our long heat rate position and
increasing our fixed-price length where we see remaining upside
During 4Q, we lowered our cross-commodity hedges monetizing our long heat
rate view as heat rates expanded
but
continued
to
stay
behind
ratable
by
carrying
a
long
fixed-price
position
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
3Q14
4Q14
1Q14
2Q14
3Q14
4Q14 |
6
2014 4Q Earnings Release Slides
Exelon Generation: Gross Margin Update
December 31, 2014
Change from Sept 30, 2014
Gross Margin Category ($M)
(1)
2015
2016
2017
2015
2016
2017
Open Gross Margin
(3)
(including South, West, Canada hedged gross
margin)
$5,700
$5,850
$6,100
$(1,050)
$(650)
$(550)
Mark-to-Market of Hedges
(3,4)
$1,050
$550
$350
$1,050
$400
$200
Power New Business / To Go
$350
$550
$800
$(50)
-
$50
Non-Power Margins Executed
$200
$100
$50
$100
$50
-
Non-Power New Business / To Go
$250
$350
$400
$(50)
-
$50
Total Gross Margin
(2)
$7,550
$7,400
$7,700
-
$(200)
$(250)
Load
serving
business
had
strong
2014
and
is
off
to
a
good
start
in
2015
Cleared 195MW of new peaking generation in ISO-NE Forward Capacity Auction
9. Expected to be online in mid-2018
Natural gas and power prices declined during the fourth quarter
Aggressively hedged our PJM East and New England Portfolios in early Q4 when
prices were higher
Recent Developments
4)
Mark to Market of Hedges assumes mid-point of hedge percentages.
Note: Inclusive of all asset divestitures as of December 31, 2014 and
Quail Run, as well as the Integrys acquisition.
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, operating
services agreement with Fort Calhoun and variable interest entities.
Total Gross Margin is also net of direct cost of sales for certain Constellation
businesses. See Slide 36
for a Non-GAAP to GAAP reconciliation of Total Gross Margin.
3)
Excludes EDFs equity ownership share of the CENG Joint Venture |
7
2014 4Q Earnings Release Slides
Properly Valuing Nuclear Energy |
8
2014 4Q Earnings Release Slides
Exelon Generation Disclosures
December 31, 2014 |
9
2014 4Q Earnings Release Slides
Portfolio Management Strategy
Protect Balance Sheet
Ensure Earnings Stability
Create Value
Exercising Market Views
Purely ratable
Actual hedge %
Market views on timing, product
allocation and regional spreads
reflected in actual hedge %
High End of Profit
Low End of Profit
% Hedged
Open Generation
with LT Contracts
Portfolio Management &
Optimization
Portfolio Management Over Time
Align Hedging & Financials
Establishing Minimum Hedge Targets
Aligns hedging program with
financial policies and financial
outlook
Establish minimum hedge targets
to meet financial objectives of the
company (dividend, credit rating)
Hedge enough commodity risk to
meet future cash requirements
under a stress scenario
Ensure stability in near-term cash
flows and earnings
Disciplined approach to hedging
Tenor aligns with customer
preferences and market liquidity
Multiple channels to market that
allow us to maximize margins
Large open position in outer years
to benefit from price upside
Ability to exercise fundamental
market views to create value within
the ratable framework
Modified timing of hedges versus
purely ratable
Cross-commodity hedging (heat
rate positions, options, etc.)
Delivery locations, regional and
zonal spread relationships
Credit Rating
Capital
Structure
Capital &
Operating
Expenditure
Dividend
Strategic Policy Alignment
Three-Year Ratable Hedging
Bull / Bear Program |
10
2014 4Q Earnings Release Slides
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
Open Gross
Margin
MtM of
Hedges
(2)
Power
New
Business
Non Power
Executed
Non Power
New Business
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)
)
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
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)
(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 |
11
2014 4Q Earnings Release Slides
ExGen Disclosures
Gross Margin Category ($M)
(1)
2015
2016
2017
Open Gross Margin
(including South, West & Canada hedged GM)
$5,700
$5,850
$6,100
Mark to Market of Hedges
(3,4)
$1,050
$550
$350
Power New Business / To Go
$350
$550
$800
Non-Power Margins Executed
$200
$100
$50
Non-Power New Business / To Go
$250
$350
$400
Total
Gross
Margin
$7,550
$7,400
$7,700
(1)
Gross margin categories rounded to nearest $50M
(2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less
purchased power and fuel expense, excluding revenue related to
decommissioning, gross receipts tax, Exelon Nuclear Partners, operating
services agreement with Fort Calhoun and variable interest entities.
Total Gross Margin is also net of direct cost of sales for certain
Constellation businesses. See Slide 36 for a Non-GAAP to GAAP reconciliation of Total
Gross Margin
(3)
Excludes EDFs equity ownership share of the CENG Joint Venture Reference Prices
(5)
2015
2016
2017
Henry Hub Natural Gas ($/MMbtu)
$3.03
$3.46
$3.76
Midwest: NiHub ATC prices ($/MWh)
$30.13
$30.96
$31.98
Mid-Atlantic: PJM-W ATC prices ($/MWh)
$37.76
$37.74
$37.83
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
$6.38
$6.10
$5.93
New York: NY Zone A ($/MWh)
$36.12
$36.79
$36.64
New England: Mass Hub ATC Spark Spread($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$10.25
$9.08
$8.02
(4)
Mark to Market of Hedges assumes mid-point of hedge percentages
(5)
Based on December 31, 2014 market conditions
(6)
Inclusive of all asset divestitures as of December 31, 2014, and Quail Run, as
well as Integrys acquisition (2,6) |
12
2014 4Q Earnings Release Slides
ExGen Disclosures
Generation and Hedges
2015
2016
2017
Exp. Gen (GWh)
(1)
191,200
192,400
196,800
Midwest
97,100
97,400
95,900
Mid-Atlantic
(2)
62,400
62,900
60,700
ERCOT
16,800
17,300
25,700
New York
(2)
9,300
9,300
9,300
New England
5,600
5,500
5,200
% of Expected Generation Hedged
(3)
61%-64%
31%-34%
Midwest
88%-91%
55%-58%
23%-26%
Mid-Atlantic
(2)
99%-102%
67%-70%
36%-39%
ERCOT
94%-97%
77%-80%
48%-51%
New York
(2)
84%-87%
60%-63%
38%-41%
New England
118%-121%
68%-71%
32%-35%
Effective Realized Energy Price ($/MWh)
(4)
Midwest
$34.00
$34.50
$36.00
Mid-Atlantic
(2)
$45.00
$45.00
$47.00
ERCOT
(5)
$10.50
$7.50
$7.00
New York
(2)
$47.50
$43.50
$40.00
New England
(5)
$21.00
$14.50
$9.00
(1) Expected generation is the volume of energy that best represents our
commodity position in energy markets from owned or contracted for capacity 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 2015, 12 in 2016, and 15 in
2017 at Exelon-operated nuclear plants, and Salem. Expected generation assumes
capacity factors of 93.5%, 94.1% and 93.4% in 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 EDFs 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) Inclusive of all asset divestitures
as of December 31,2014 and Quail Run, as well as Integrys acquisition
93%-96% |
13
2014 4Q Earnings Release Slides
ExGen Hedged Gross Margin Sensitivities
Gross Margin Sensitivities (With Existing Hedges)
(1)
2015
2016
2017
Henry Hub Natural Gas ($/Mmbtu)
+ $1/Mmbtu
$25
$340
$730
-
$1/Mmbtu
$35
$(310)
$(710)
NiHub ATC Energy Price
+ $5/MWh
$35
$215
$370
-
$5/MWh
$(30)
$(215)
$(365)
PJM-W ATC Energy Price
+ $5/MWh
$(5)
$105
$205
-
$5/MWh
$10
$(100)
$(205)
NYPP Zone A ATC Energy Price
+ $5/MWh
$ -
$10
$25
-
$5/MWh
$(5)
$(15)
$(30)
Nuclear Capacity Factor
+/-
1%
+/-
$40
+/-
$45
+/-
$45
(1)
Based on December 31, 2014 market conditions and hedged position; Gas price
sensitivities are based on an assumed gas-power relationship derived from an internal model
that is updated periodically; Power prices sensitivities are derived by
adjusting the power price assumption while keeping all other 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 EDFs equity share of CENG Joint Venture; Inclusive of all asset
divestitures as of December 31, 2014, and Quail Run, as well as Integrys acquisition |
14
2014 4Q Earnings Release Slides
ExGen Hedged Gross Margin Upside/Risk
$7,800
$7,250
$8,350
$6,650
5,000
5,500
6,000
6,500
7,000
7,500
8,000
8,500
9,000
9,500
10,000
10,500
11,000
2015
2016
2017
$9,950
$6,050
14
2014 4Q Earnings Release Slides
(1)
Represents an approximate range of expected gross margin, taking into account
hedges in place, between the 5th and 95th percent confidence levels assuming
all unhedged supply is sold into the spot market; Approximate gross margin
ranges are based upon an internal simulation model and are subject to change based
upon market inputs, future transactions and potential modeling changes; These
ranges of approximate gross margin in 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 December 31, 2014 (2) Gross Margin Upside/Risk based on commodity
exposure which includes open generation and all committed transactions
(3)
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, operating services agreement with Fort
Calhoun and variable interest entities. Total Gross Margin is also net of direct cost
of sales for certain Constellation businesses. See Slide 36 for a
Non-GAAP to GAAP reconciliation of Total Gross Margin Excludes EDFs equity ownership share of
the CENG Joint Venture
(4)
Inclusive of all asset divestitures as of December 31, 2014 and Quail Run, as
well as Integrys acquisition |
15
2014 4Q Earnings Release Slides
Illustrative Example of Modeling Exelon
Generation
2016 Gross Margin
Row
Item
Midwest
Mid-
Atlantic
ERCOT
New York
New
England
South,
West &
Canada
(A)
Start with fleet-wide open gross margin
$5.85 billion
(B)
Expected Generation (TWh)
97.4
62.9
17.3
9.3
5.5
(C)
Hedge % (assuming mid-point of range)
56.5%
68.5%
78.5%
61.5%
69.5%
(D=B*C)
Hedged Volume (TWh)
55.0
43.1
13.6
5.7
3.8
(E)
Effective Realized Energy Price ($/MWh)
34.50
45.00
7.50
43.50
14.50
(F)
Reference Price ($/MWh)
30.96
37.74
6.10
36.79
9.08
(G=E-F)
Difference ($/MWh)
3.54
7.26
1.40
6.71
5.42
(H=D*G)
Mark-to-market value of hedges ($ million)
(1)
195
315
20
40
20
(I=A+H)
Hedged Gross Margin ($ million)
$6,400
(J)
Power New Business / To Go ($ million)
$550
(K)
Non-Power Margins Executed ($ million)
$100
(L)
Non-
Power New Business / To Go ($ million)
$350
(N=I+J+K+L)
Total Gross Margin
(2)
$7,400 million
(1)
Mark-to-market rounded to the nearest $5 million
(2)
Total Gross Margin (Non-GAAP) is defined as operating revenues less
purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts
tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun
and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain
Constellation businesses. See Slide 36 for a Non-GAAP to GAAP reconciliation of Total Gross Margin
Note: Inclusive of all asset divestitures as of December 31, 2014, and
Quail Run as well as Integrys acquisition |
16
2014 4Q Earnings Release Slides
Additional Disclosures |
17
2014 4Q Earnings Release Slides
2014 Adjusted Operating Earnings by Quarter
$ 0.30
$ 0.27
$ 0.27
$ 0.15
$ 0.50
$ 0.13
$ 0.11
$ 0.09
$ 0.10
$ 0.10
$ 0.11
$ 0.09
$ 0.06
$ 0.05
$ 0.10
ExGen
BGE
ComEd
PECO
Q4
$0.48
Q3
$0.78
Q2
$0.51
$ 0.02
Q1
$0.62
Refer to the Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS
Amounts may not add due to rounding |
18
2014 4Q Earnings Release Slides
Exelon Utilities Adjusted Operating EPS Contribution
(1)
Key
Drivers
4Q14
vs.
4Q13
:
BGE
(+0.00):
Higher RNF offset by higher O&M: $(0.00)
PECO (-0.01):
Unfavorable weather conditions: $(0.01)
ComEd
(-0.04):
Impact of bonus depreciation on ComEds distribution and
transmission
(2)
earnings: $(0.02)
Unfavorable
weather
conditions
and
volume
(2)
:
$(0.01)
$0.13
4Q 2014
$0.26
$0.06
$0.11
$0.09
4Q 2013
$0.31
$0.06
$0.12
ComEd
PECO
BGE
(1)
(2)
Due to the distribution formula rate, changes in ComEds earnings are
driven primarily by changes in 30-year U.S. Treasury rates (inclusive of ROE), rate base and capital structure
in addition to weather, load and changes in customer mix.
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.
Numbers may not add due to rounding.
|
19
2014 4Q Earnings Release Slides
$0.45 -
$0.55
Other
($0.02)
Depreciation &
Amortization
($0.02)
O&M
(3)
($0.06)
RNF
(2)
2014
(1)
($0.01)
2015
(4)(5)
ComEd Adjusted Operating EPS Bridge 2014 to 2015
Interest
$0.14
$0.47
$0.11
Distribution
$0.02
Transmission
$0.01
Weather/Volumes
($0.01)
Storm
($0.02)
Inflation
($0.01)
Pension/OPEB
($0.01)
Other
(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 866M in 2015 and 864M 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 2015 of 39.5%.
Note: Drivers add up to mid-point of 2015 adjusted operating EPS
range. |
20
2014 4Q Earnings Release Slides
$0.41
RNF
(2)
($0.00)
2015
(4)(5)
$0.35 -
$0.45
Tax
($0.02)
Interest
($0.00)
Depreciation &
Amortization
(0.00)
O&M
(3)
$0.01
PECO Adjusted Operating EPS Bridge 2014 to 2015
2014
(1)
($0.02) Storm Tax Repairs
Benefit
$0.03 Storm
($0.01) Inflation
($0.01) Operational/IT Increases
Note: Drivers add up to mid-point of 2015 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.
e
(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 864M in 2014 and
866M in 2015. 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 2015 of
28.5%.
|
21
2014 4Q Earnings Release Slides
$0.05
$0.23
Other
O&M
(3)
($0.04)
RNF
(2)
2014
(1)
$0.20 -
$0.30
$0.01
2015
(4)(5)
BGE Adjusted Operating EPS Bridge 2014 to 2015
($0.01) Storm Costs
($0.01) Preventative Maintenance
($0.01) Inflation
($0.01) Other
$0.04 Pricing/Mix
$0.01 Other RNF
Note: Drivers add up to mid-point of 2015 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 864M in 2014 and 866M in 2015. 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 2015 of
39.2%. |
22
2014 4Q Earnings Release Slides
$0.08
$1.34
$1.15 -
$1.35
Other
2015
(5)(6)
Depreciation &
Amortization
(4)
$0.04
2014
(1)
Gross Margin
(2)
($0.03)
O&M
(3)
($0.02)
ExGen Adjusted Operating EPS Bridge 2014 to 2015
$0.22 Higher Capacity Revenue, Higher retail
volumes (primarily Integrys), Plant Performance
and Market Conditions
$0.04 Impact of full year DOE fee removal
($0.22) Plant Divestitures
($0.05) Depreciation Additions
$0.03 Plant Divestitures
($0.06) Generation Growth, including
Integrys
($0.05) Inflation
($0.02) Pension / OPEB
($0.02) Nuclear Outages
$0.07 Plant Divestitures
$0.02 Other Divestitures
$0.01 Asbestos Reserve
$0.03 Other
($0.05) Interest
($0.04) Decom, primarily
unregulated realized gains
Note: Drivers add up to mid-point of 2015 adjusted operating EPS range.
(1)
Refer to the Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(2)
(3)
Gross Margin (Non-GAAP) is defined as operating revenues less purchased
power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating
services agreement with Fort Calhoun and variable interest entities. Total
Gross Margin is also net of direct cost of sales for certain Constellation businesses. See Slide 36 for a Non-GAAP to GAAP
reconciliation of Total Gross Margin.
(4)
O&M excludes items that are P&L neutral (including
decommissioning costs and variable interest entities) and direct cost of sales for certain Constellation businesses.
(5)
Depreciation & Amortization excludes cost of sales for certain
Constellation businesses, which are included in gross margin
(6)
Shares Outstanding (diluted) are 864M in 2014 and 866M in 2015. Refer to slide
33 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.
(7)
Guidance assumes an effective tax rate for 2015 of 26%.
2014 Income statement categories have been normalized for a full year comparison
of CENG at ownership (50.01) (
) |
23
2014 4Q Earnings Release Slides
2015 Projected Sources and Uses of Cash
($ in millions)
(1)
BGE
ComEd
PECO
ExGen
Exelon
(3)
2015E
Beginning Cash Balance
3,575
Adjusted Cash Flow from Operations
(4)
600
2,075
600
3,400
6,775
CapEx (excluding other items below):
(675)
(1,875)
(525)
(1,925)
(5,100)
Nuclear Fuel
n/a
n/a
n/a
(1,125)
(1,125)
Dividend
(5)
(1,075)
Nuclear Uprates
n/a
n/a
n/a
(100)
(100)
Wind
n/a
n/a
n/a
(100)
(100)
Solar
n/a
n/a
n/a
(125)
(125)
Upstream
n/a
n/a
n/a
(25)
(25)
Utility Smart Grid/Smart Meter
(25)
(325)
(25)
n/a
(400)
Net Financing (excluding Dividend):
Debt Issuances
250
700
350
750
2,050
Debt Retirements
(75)
(250)
0
(550)
(1,675)
Project Finance/Federal Financing Bank
Loan
n/a
n/a
n/a
200
200
Other Financing
(6)
0
(50)
0
1,075
1,250
Ending Cash Balance
4,125
(1)
All amounts rounded to the nearest $25M.
(2)
Excludes counterparty collateral posted of $1.7 billion at 12/31/2014. In addition, the
12/31/2015 ending cash balance does not include collateral.
(3)
Includes cash flow activity from Holding Company and other corporate entities. (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.
(5)
Dividends are subject to declaration by the Board of Directors.
(6)
Other Financing primarily includes expected changes in short-term debt. (2)
(2) |
24
2014 4Q Earnings Release Slides
Additional 2015 ExGen Modeling
P&L Item
2015 Estimate
ExGen Model Inputs
O&M
(2)
$4,525M
Taxes Other Than Income (TOTI)
(3)
$350M
Depreciation & Amortization
(4)
$925M
Interest Expense
$400M
(1)
ExGen amounts for O&M, TOTI and Depreciation & Amortization; excludes EDFs equity ownership share of the CENG Joint Venture
(2)
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.
Refer to the Appendix for a reconciliation of adjusted (non-GAAP) O&M
to GAAP O&M (3)
TOTI excludes gross receipts tax for retail of $125M.
(4)
ExGen Depreciation & Amortization excludes the cost of sales impact of
ExGens non-power businesses of $25. (1)
|
25
2014 4Q Earnings Release Slides
2015 Regulatory and Legislative Timelines
ExGen
Exelon Utilities
PHI Acquisition
Illinois
Legislative
Session
Begins
(Jan 14)
Cert Petition
Filed in
EPSA v.
FERC (Order
745
Demand
Response)
(Jan 15)
Supreme
Court
decision on
cert in
EPSA v.
FERC
(Demand
Response)
(March-
April)
Supreme
Court
hearing on
Michigan v.
EPA
(MATS)
(March-
April)
FERC Ruling
on PJM
Capacity
Performance
Proposal
(April)
MATS Rule
in Effect
(April)
PJM BRA
Auction
(May 11)
PJM BRA
Auction
Results
(May 22)
Illinois
Legislative
Session
Adjourns
(May 31)
Supreme
Court
Decision in
Michigan
vs. EPA
(June)
Final Clean
Power Rule
(111d)
Issued
(Mid-
Summer)
Illinois
Legislative
Veto
Session
(Nov)
ComEd Formula Rate Filing
(April)
BGE Electric and Gas Rate
Case Filing (TBD) MD PSC
Ruling Expected 7 Months
after Filing
PECO Electric Rate Case
Filing (TBD) PaPUC Ruling
Expected within 9 Months of
Filing
ICC Rules on ComEd
Formula Rate Filing (Dec)
Settlement
Filed in New
Jersey (Jan 14)
Maryland
Hearings (Jan
26
Feb 6)
New Jersey
Approval
(Feb 11)
DC Hearings
(March 30-
April 8)
Maryland
Deadline (April
8)
Expected
Transaction
Close (Q2/Q3) |
Exelon Utilities Load
2015E
2014
Large C&I
Small C&I
Residential
All Customers
2015E
2014
2014
2015E
Chicago GMP
1.6%
Chicago Unemployment
5.9%
Philadelphia GMP
0.8%
Philadelphia Unemployment
4.8%
Baltimore GMP
1.4%
Baltimore Unemployment
5.5%
Notes: Data is not adjusted for leap year. Source of economic outlook
data is Global Insight (December 2014 ) and Bureau of Economic Analysis. Assumes 2014 GDP of 2.4% and U.S.
unemployment of 5.6%.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 ComEd
PECO
BGE
2015 load growth is similar to
2014, driven by slowly
improving economic conditions
and partially offset by energy
efficiency
2015 load growth is driven by
modest economic growth
coupled with increased shale
gas transportation and
production, partially offset by
energy efficiency
2015 load growth rate is
driven by weaker economic
conditions, primarily
reflected in residential and
small C&I, further decreased
by energy efficiency
0.4%
0.2%
0.8%
0.3%
0.4%
-0.3%
-0.1%
0.7%
0.8%
0.1%
0.4%
0.5%
-0.7%
0.0%
1.9%
-0.1%
-1.3%
-0.2%
-0.9%
-2.4%
0.1%
0.6%
-1.9%
-0.5%
26
2014 4Q Earnings Release Slides |
27
2014 4Q Earnings Release Slides
ComEd April 2014 Distribution Formula Rate
Note: Disallowance of any items in the 2014 distribution formula rate
filing could impact 2014 earnings in the form of a regulatory asset adjustment. Total disallowances in the 2014
distribution formula rate filing include items that are recoverable via other
ratemaking mechanisms. 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 established the net revenue requirement
used to set the rates that took effect in January 2015 after the Illinois
Commerce Commission's (ICCs) 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.
|
28
2014 4Q Earnings Release Slides
BGE Rate Case Settlement
(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 BGEs 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)
BGEs Proposed Adjusted rate base
First BGE rate case settlement agreement since 1999
Electric
Gas
Docket #
9355
Test Year
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
which
was approved by
the PSC
Increased rates effective with service on or after December 15, 2014
September 2013 - August 2014
|
29
2014 4Q Earnings Release Slides
Appendix
Reconciliation of Non-GAAP
Measures |
30
2014 4Q Earnings Release Slides
4Q GAAP EPS Reconciliation
Three Months Ended December 31, 2014
ExGen
ComEd
PECO
BGE
Other
Exelon
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$0.27
$0.09
$0.11
$0.06
$(0.04)
$0.48
Mark-to-market impact of economic hedging activities
(0.08)
-
-
-
-
(0.08)
Unrealized losses related to NDT fund investments
0.03
-
-
-
-
0.03
Merger and integration costs
(0.01)
-
-
-
(0.08)
(0.09)
Reassessment of state deferred income taxes
0.04
-
-
-
(0.01)
0.03
Amortization of commodity contract intangibles
(0.03)
-
-
-
-
(0.03)
Plant retirements and divestitures
0.06
-
-
-
-
0.06
Long-lived asset impairment
(0.39)
-
-
-
-
(0.39)
Bargain-purchase gain
0.03
-
-
-
-
0.03
Tax settlements
0.01
-
-
-
-
0.01
Non-controlling interest
(0.03)
-
-
-
-
(0.03)
4Q 2014 GAAP Earnings (Loss) Per Share
($0.11)
$0.09
$0.11
$0.06
$(0.13)
$0.02
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 nuclear decommissioning trust funds
0.05
-
-
-
-
0.05
Constellation merger and integration costs
(0.02)
-
-
-
-
(0.02)
Reassessment of state deferred income taxes
0.02
-
-
-
(0.02)
-
Amortization of commodity contract intangibles
(0.09)
-
-
-
-
(0.09)
Midwest Generation bankruptcy charges
(0.02)
-
-
-
-
(0.02)
4Q 2013 GAAP Earnings (Loss) Per Share
$0.31
$0.13
$0.12
$0.06
$(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. |
31
2014 4Q Earnings Release Slides
4Q YTD GAAP EPS Reconciliation
NOTE: All amounts shown are per Exelon share and represent contributions
to Exelon's EPS. Amounts may not add due to rounding. Year Ended
December 31, 2013 ExGen
ComEd
PECO
BGE
Other
Exelon
2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.40
$0.49
$0.45
$0.23
$(0.07)
$2.50
Mark-to-market impact of economic hedging activities
0.35
-
-
-
(0.00)
0.35
Unrealized gains related to nuclear decommissioning trust funds
0.09
-
-
-
-
0.09
Asset retirement obligation
(0.01)
-
-
-
-
(0.01)
Plant retirements and divestiture
0.02
-
-
-
-
0.02
Long-lived asset impairment
(0.12)
-
-
-
(0.02)
(0.14)
Merger and integration costs
(0.08)
-
-
-
-
(0.08)
Amortization of commodity contract intangibles
(0.41)
-
-
-
-
(0.41)
Remeasurement of like kind exchange tax position
-
(0.20)
-
-
(0.11)
(0.31)
Amortization of the fair value of certain debt
0.01
-
-
-
-
0.01
Reassessment of state deferred income taxes
0.01
-
-
-
(0.01)
-
Midwest Generation bankruptcy charges
(0.02)
-
-
-
-
(0.02)
4Q 2013 GAAP Earnings (Loss) Per Share
$1.24
$0.29
$0.45
$0.23
$(0.21)
$2.00 |
32
2014 4Q Earnings Release Slides
4Q YTD GAAP EPS Reconciliation -
continued
Year Ended December 31,
2014 ExGen
ComEd
PECO
BGE
Other
Exelon
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
$1.34
$0.47
$0.41
$0.23
$(0.06)
$2.39
Mark-to-market impact of economic hedging activities
(0.42)
-
-
-
-
(0.42)
Unrealized gains related to NDT fund investments
0.10
-
-
-
-
0.10
Asset retirement obligation
0.02
-
-
-
-
0.02
Plant retirements and divestitures
0.28
-
-
-
-
0.28
Long-lived asset impairment
(0.49)
-
-
-
(0.02)
(0.50)
Gain on CENG integration
0.18
-
-
-
-
0.18
Merger and integration costs
(0.10)
-
-
-
(0.11)
(0.21)
Amortization of commodity contract intangibles
(0.07)
-
-
-
-
(0.07)
Tax settlements
0.12
-
-
-
-
0.12
Reassessment of state deferred income taxes
0.04
-
-
-
(0.01)
0.03
Bargain-purchase gain
0.03
-
-
-
-
0.03
Non-controlling interest
(0.07)
-
-
-
-
(0.07)
4Q 2014 GAAP Earnings Per Share
$0.97
$0.47
$0.41
$0.23
($0.20)
$1.88
NOTE: All amounts shown are per Exelon share and represent contributions
to Exelon's EPS. Amounts may not add due to rounding. |
33
2014 4Q Earnings Release Slides
GAAP to Operating Adjustments
NOTE: All amounts shown are per Exelon share and represent contributions
to Exelon's EPS. Amounts may not add due to rounding.
Exelons 2015 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 sale of interests in generating
stations
Certain costs incurred associated with the Integrys acquisition 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 date of acquisition of Integrys
Energy Services in 2014
Other unusual items |
2014 4Q Earnings Release Slides
34
Adjusted O&M Reconciliations to GAAP
2014 Adjusted O&M Reconciliation (in $M)
(3)
ExGen
ComEd
PECO
BGE
Other
Exelon
GAAP O&M
$5,575
$1,450
$875
$700
$(25)
$8,575
PHI Merger and Acquisition Costs
-
-
-
-
(25)
(25)
Regulatory O&M
(1)
-
(250)
(100)
-
-
(350)
Upstream and Power Impairments
(525)
-
-
-
(25)
(525)
Constellation Merger Commitments
(50)
-
-
-
-
(50)
Direct cost of sales incurred to generate revenues for
certain Constellation businesses
(2)
(325)
-
-
-
-
(325)
O&M for managed plants that are partially owned
(300)
-
-
-
-
(300)
Other
(25)
-
-
-
-
(25)
Adjusted O&M (Non-GAAP, as shown on slide 4)
$4,350
$1,200
$750
$700
$(75)
$6,950
(1)
Reflects P&L neutral O&M.
(2)
Reflects the direct cost of sales of certain Constellation businesses of
Generation, which are included in Total Gross Margin. (3)
All amounts rounded to the nearest $25M. |
35
2014 4Q Earnings Release Slides
Adjusted O&M Reconciliations to GAAP
2015 Adjusted O&M Reconciliation (in $M)
(3)
ExGen
ComEd
PECO
BGE
Other
Exelon
GAAP O&M
$5,225
$1,550
$850
$775
$(75)
$8,350
PHI Acquisition Costs
(25)
-
-
-
-
(25)
Regulatory O&M
(1)
-
$(300)
(100)
-
-
(425)
Decommissioning
25
-
-
-
-
25
Direct cost of sales incurred to generate revenues for certain
Constellation businesses
(2)
(300)
-
-
-
-
(300)
O&M for managed plants that are partially owned
(400)
-
-
-
-
(400)
Adjusted O&M (Non-GAAP, as shown on slide 4)
$4,525
$1,250
$750
$775
$(75)
$7,225
(1)
Reflects P&L neutral O&M.
(2)
Reflects the direct cost of sales of certain Constellation businesses of
Generation, which are included in Total Gross Margin. (3)
All amounts rounded to the nearest $25M. |
36
2014 4Q Earnings Release Slides
ExGen Total Gross Margin Reconciliation to GAAP
Total Gross Margin Reconciliation (in $M)
(4)
2015
2016
2017
Revenue
Net
of
Purchased
Power
and
Fuel
Expense
(1)(5)
$8,100
$8,000
$8,400
Other Revenues
(2)
$(250)
$(250)
$(250)
Direct cost of sales incurred to generate revenues for certain
Constellation businesses
(3)
$(300)
$(350)
$(450)
Total Gross Margin (Non-GAAP, as shown on slide 6)
$7,550
$7,400
$7,700
(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)
Reflects revenues from operating services agreement with Fort Calhoun, variable
interest entities, funds collected through revenues for decommissioning
the former PECO nuclear plants through regulated rates and gross receipts tax
revenues.
(3)
Reflects the cost of sales and depreciation expense of certain Constellation
businesses of Generation.
(4)
All amounts rounded to the nearest $50M.
(5)
Excludes the impact of the operating exclusion for mark-to-market due
to the volatility and unpredictability of the future changes to power prices.
2014 4Q Earnings Release Slides |