 EFH
Corp. Q1 2013 Investor Call
May 2, 2013
Exhibit 99.2 |
 1
Safe Harbor Statement
Forward Looking Statements
This
presentation
contains
forward-looking
statements,
which
are
subject
to
various
risks
and
uncertainties.
A
discussion
of
risks
and
uncertainties
that
could
cause
actual
results
to
differ
materially
from
management's
current
projections,
forecasts,
estimates
and
expectations
is
contained
in
EFH
Corp.'s
filings
with
the
Securities
and
Exchange
Commission
(SEC).
In
addition
to
the
risks
and
uncertainties
set
forth
in
EFH
Corp.'s
SEC
filings,
the
forward-looking
statements
in
this
presentation
regarding
the
company’s
natural
gas
hedging
program
could
be
affected
by,
among
other
things:
changes
in
the
ERCOT
electricity
market,
including
a
regulatory
or
legislative
change,
that
results
in
wholesale
electricity
prices
not
generally
moving
with
natural
gas
prices;
any
decrease
in
market
heat
rates
as
the
program
generally
does
not
mitigate
exposure
to
changes
in
market
heat
rates;
the
unwillingness
or
failure
of
any
hedge
counterparty
to
perform
their
respective
obligations;
or
any
other
event
that
results
in
the
inability
to
continue
to
use
a
first
lien
on
TCEH’s
assets
to
secure
a
substantial
portion
of
the
hedges
under
the
program.
Regulation
G
This
presentation
includes
certain
non-GAAP
financial
measures.
A
reconciliation
of
these
measures
to
the
most
directly
comparable
GAAP
measures
is
included
in
the
appendix
to
this
presentation. |
 2
Today’s Agenda
Q&A
Financial and Operational
Overview
Q1 2013 Review
Paul Keglevic
Executive Vice President & CFO |
 Consolidated: reconciliation of GAAP net loss to adjusted (non-GAAP) operating
results Q1 12 vs. Q1 13
1
; $ millions, after tax
EFH Corp.
Adjusted (Non-GAAP) Operating Results
3
1
Three months ended March 31.
Factor
Q1 12
Q1 13
Change
EFH Corp. GAAP net loss
(304)
(569)
(265)
Items excluded from adjusted (non-GAAP) operating results (after tax)
– noncash:
Unrealized commodity-related mark-to-market net losses
98
314
216
Unrealized mark-to-market net gains on interest rate swaps
(74)
(98)
(24)
Effect of favorable resolution of income tax positions –
Competitive business
-
(84)
(84)
Effect of favorable resolution of income tax positions –
Oncor
-
(8)
(8)
EFH Corp. adjusted (non-GAAP) operating loss
(280)
(445)
(165) |
 Consolidated key drivers of the change in (non-GAAP) operating results
Q1 12 vs. Q1 13; $ millions, after tax
EFH Corp.
Adjusted (Non-GAAP) Operating Results Key Drivers (after tax)
1
Competitive business consists of Competitive Electric segment and Corp. &
Other. 4
Description/Drivers
Better (Worse)
Than
Q1 12
Competitive business¹:
Lower net margin from asset management driven by lower natural gas hedge volumes and
prices (139)
Higher net fuel expense driven by lower lignite blend at coal plants
(6)
Higher net generation due to reduced unplanned outage days at coal plants
14
Lower amortization of intangibles arising from purchase accounting
2
Contribution margin
(129)
Higher net interest expense driven by higher average borrowings
(24)
Higher operating costs reflecting planned outages at coal and nuclear generation
units (14)
Higher depreciation reflecting accelerated depreciation primarily associated with
asset retirements during planned outages at three coal units (9)
Lower effective tax rate reflecting lower accrued interest
8
All other -
net
1
Total change -
Competitive business
(167)
Regulated business:
Higher net revenues reflecting transmission tariff increases, automated meter
surcharges, colder (more normal) weather, and growth in points of delivery 17
Higher revenues from transmission and other cost recovery (reconcilable rate)
charges 5
Lower third party transmission fees
1
Higher depreciation and amortization reflecting infrastructure investment
(10)
Higher net interest expense driven by settlement of TCEH transition bond interest
reimbursement agreement in 2012 (6)
Higher operations and maintenance expense due to energy efficiency programs and
advanced metering (2)
All other –
net
(3)
Change in Regulated business (~80% owned by EFH Corp.)
2
Total change in EFH Corp. adjusted (non-GAAP) operating results
(165) |
 EFH
Corp. Adjusted EBITDA (Non-GAAP) EFH Corp. Adjusted EBITDA
(non-GAAP) 1
Q1
12 vs. Q1 13;
$ millions
Q1 13
Q1 12
1,051
1,230
638
834
415
386
TCEH
Oncor
Q1 13 performance was largely driven by the same key drivers impacting adjusted
(non- GAAP) operating results.
8%
1
See Appendix for Regulation G reconciliations and definition. Includes
$10 million and $(2) million of Corp. & Other Adjusted EBITDA in Q1 12 and Q1 13, respectively.
5
24%
15% |
 Luminant Operational Results
6
Q1 2013 Nuclear Plant Results
Solid safety performance
2 fewer generation days in Q1 2013
Top decile industry performance for
reliability and cost
Q1 2013 Coal-Fueled Plant Results
Higher generation due to improved
reliability -
fewer unplanned outages
Higher planned outage days due to
maintenance
~4.3 TWh of available generation was
uneconomic resulting in seasonal
operations and backdown of higher
cost units |
  Q1 2013
Results Sales volumes declined 4% driven
by business volumes
Residential attrition rates
improved over 25% compared to
Q1 2012. Q1 2013 attrition was
1.0% vs. 1.4% in Q1 2012
Lower SMB
1
and LCI
2
volumes
reflect competitive intensity and a
focus on margin discipline
TXU Energy Operational Results
Total residential customers3
End of period, thousands
Retail electricity sales volumes by customer class;
GWh
1
SMB –
small
business.
2
LCI –
large commercial and industrial.
3
Includes December 2012 acquisition of customers.
4
Last twelve months.
7 |
 8
Oncor Operational Results
Electric energy billed volumes
3
; GWh
1
SMB –
small business; LCI –
large commercial and industrial.
2
CREZ –
Competitive Renewable Energy Zone.
3
On average, billed volumes are on an approximate 17-day calendar lag; therefore,
amounts shown reflect partial impacts from prior quarters.
4
Last twelve months.
Electricity distribution points of delivery
End of period, thousands of meters
Q1 2013 Results
Higher residential volumes
principally due to more normal
weather and premise growth
Higher SMB & LCI
1
energy volumes
due to economic growth
$1.6 billion spent on CREZ
2
through
March 31, 2013; $167 million spent in
2013 |
 EFH
Corp. Liquidity Management As of March 31, 2013
9
Cash and Equivalents
TCEH Letter of Credit Facility¹
TCEH Revolving Credit Facility
EFH
Corp.
and
TCEH
continue
to
monitor
capital
market
conditions
for
opportunities
to
ensure
liquidity
needs
are
met
and
to
improve
financial
flexibility.
EFH Corp. (excluding Oncor) available liquidity
As of 3/31/13; $ millions
1
At March 31, 2013, restricted cash totaled $947 million, after reduction for a $115
million letter of credit drawn in 2009 related to a building financing. The restricted cash supports letters
of credit, of which $735 million are outstanding, leaving $212 million available.
|
 10
10
10
Commodity Prices
Commodity
Units
Q1 13
Actual
Q1 12
Actual
FY 12
1
Actual
13E
1
NYMEX gas price
2
$/MMBtu
3.48
2.46
2.75
4.12
HSC gas price
2
$/MMBtu
3.43
2.41
2.71
4.08
7x24 market heat rate (HSC)
3
MMBtu/MWh
7.69
10.00
9.53
10.16
North Hub 7x24 power price
$/MWh
26.45
23.46
25.17
41.47
TCEH weighted avg. hedge price
4
$/MMBtu
6.89
7.46
7.36
6.89
Gulf Coast ultra-low sulfur diesel
$/gallon
3.09
3.17
3.05
2.99
PRB 8400 coal
$/ton
9.17
8.28
7.57
9.62
LIBOR interest rate
5
percent
0.47%
0.76%
0.69%
0.59%
Commodity prices
Q1 13, Q1 12, FY 12 and 13E; mixed measures
1
FY
2012:
Year
ended
December
31,
2012;
13E:
2013
estimate
based
on
average
of
monthly
commodity
prices
as
of
March
28,
2013
for
April
2013
through
December
2013.
2
The
actual
prices
are
computed
based
on
settled
Gas
Daily
prices
for
Henry
Hub
or
Houston
Ship
Channel
(HSC)
respectively.
3
Based
on
ERCOT
Nodal
market
clearing
price
for
North
Hub.
4
Weighted
average
prices
in
the
TCEH
natural
gas
hedging
program.
Based
on
NYMEX
Henry
Hub
prices
of
forward
natural
gas
sales
positions
in
the
hedging
program
(excluding
the
impact
of
offsetting
purchases
for
rebalancing
and
pricing
point
basis
transactions).
5
The
index
for
the
settled
value
is
a
6-month
LIBOR
rate.
LIBOR
interest
rate
for
13E
is
based
on
9
month
LIBOR
rate. |
 11
Factor
Measure
2013
2014
Total
12/31/12
Natural gas hedges
mm MMBtu
~211
~146
~357
Wtd. avg. hedge price¹
$/MMBtu
~$6.89
~$7.80
Natural gas prices
$/MMBtu
~$3.54
~4.03
Cum. MtM gain at 12/31/12²
$ billions
~$1.0
~$0.6
~$1.6
03/31/13
Natural gas hedges³
mm MMBtu
~163
~146
~309
Wtd. avg. hedge price¹
$/MMBtu
~$6.89
~$7.80
Natural gas prices
4
$/MMBtu
~$4.12
~$4.23
Cum. MtM gain at 03/31/13²
$ billions
~$0.7
~$0.5
~$1.2
Q1 13 MtM (loss) gain
$ billions
~(0.3)
~(0.1)
~(0.4)
11
Unrealized Mark-To-Market Impact Of Hedging
Unrealized mark-to-market impact of hedging program
03/31/13 vs. 12/31/12; mixed measures, pre-tax
Hedge program decrease is due to settlement of Q1 position, as well as rising gas
prices. 1
Weighted
average
prices
are
based
on
forward
natural
gas
sales
positions
in
the
natural
gas
hedging
program
(excluding
the
impact
of
offsetting
purchases
for
rebalancing
and
pricing
point
basis
transactions).
Where
collars
are
reflected,
sales
price
represents
the
approximate
collar
floor
price.
December
31,
2012
prices
for
2013
represent
January
1,
2013
through
December
31,
2013
values
and
March
31,
2013
prices
for
2013
represent
April
1,
2013
through
December
31,
2013
values.
2
MtM
values
include
the
effects
of
all
transactions
in
the
natural
gas
hedging
program
including
offsetting
purchases
(for
re-balancing)
and
natural
gas
basis
deals.
3
As
of
March
31,
2013.
2013
represents
April
1,
2013
through
December
31,
2013
volumes.
Where
collars
are
reflected,
the
volumes
are
estimated
based
on
the
notional
position
of
the
derivatives
to
provide
protection
against
downward
price
movements.
The
notional
volumes
for
collars
are
approximately
150
million
MMBtu,
which
correspond
to
a
delta
position
of
approximately
146
million
MMBtu
in
2014.
4
2013
represents
the
average
of
monthly
forward
prices
for
April
1,
2013
though
December
31,
2013. |
 12
12
TCEH Natural Gas Exposure
TCEH Natural Gas Position
13-15¹; million MMBtu
Hedges Backed by Asset First Lien
Open Position
Factor
Measure
2013
2014
2015
Natural gas hedging program
million MMBtu
~152
~146
0
TXUE and LUME net positions
million MMBtu
~166
~51
~16
Overall estimated percent of
total NG position hedged
percent
~94%
~43%
~3%
TXUE and Luminant Net Positions2
TCEH has hedged approximately 94% of its estimated natural gas price exposure for
2013 1
As
of
March
31,
2013.
Balance
of
2013
is
from
May
1,
2013
to
December
31,
2013.
Assumes
conversion
of
electricity
positions
based
on
a
~8.5
heat
rate
with
natural
gas
generally
being
on
the
margin
~70-90%
of
the
time
(i.e.
when
other
technologies
are
forecast
to
be
on
the
margin,
no
natural
gas
position
is
assumed
to
be
generated).
2
Includes
estimated
forward
net
wholesale
and
retail
sales.
Excludes
any
transactions
associated
with
proprietary
trading
positions.
3
The
2014
position
includes
notional
volume
of
approximately
150
million
MMBtu
costless
collar
with
strikes
of
~$7.80/MMBtu
and
~$11.75/MMBtu
for
puts
and
calls,
respectively.
The
delta
equivalent
short
position
is
~146
million
MMBtu.
3 |
 2013 estimate based
on commodity positions as of March 31, 2013 and reflects the existing regulatory environment under the Clean Air Interstate Rule, net of
natural gas hedges and net wholesale and retail sales. Excludes gains and losses incurred prior
to March 31, 2013. Simplified representation of heat rate position in a single TWh position. Heat rate impacts are
typically differentiated across plants and respective pricing periods: nuclear and
coal-fueled plants generation (linked primarily to changes in North Hub 7x24), natural gas plants (primarily North Hub 5x16) and wind
(primarily West Hub7x8). Assumes conversion of electricity positions based on a ~8.5 market heat
rate with natural gas generally being on the margin ~70-90% of the time (i.e., when coal is
forecast to be on the margin, no natural gas position is assumed to be generated). Includes positions related to fuel surcharge on rail transportation.
Excludes fuel surcharge on rail transportation.
13
13
13
EFH Corp. Adjusted EBITDA Sensitivities
Commodity
Percent Hedged at
March 31, 2013
Change
BOY 13E Impact
$ millions
7X24 market heat rate (MMBtu/MWh)2
~85
0.1 MMBtu/MWh
~4
NYMEX gas price ($/MMBtu)
~94
$1/MMBtu
~20
Diesel ($/gallon)3
~80
$1/gallon
~6
Base coal ($/ton)
4
~92
$2/ton
~2
Generation operations
Nuclear-
and coal / lignite-fueled generation (TWh)
N/A
1 TWh
~15
Retail operations
BOY 2013
Residential contribution margin ($/MWh)
17 TWh
$1/MWh
~17
Residential consumption
17 TWh
1%
~5
Business markets consumption
12 TWh
1%
~1
Impact on EFH Corp. Adjusted EBITDA
13E¹; mixed measures
The majority of 2013 commodity-related risks are significantly mitigated
1
2
3
4 |
 Estimate as of March 31, 2013; $ billions
EFH / EFIH
TCEH
1
1st Lien
$0.02
$0.41
2
2nd Lien
$0.23
$1.88
3
Total
$0.25
$2.29
Estimated Secured Debt Capacity at EFH / EFIH and TCEH
1
14
1
The
debt
capacity
numbers
presented
above
are
for
informational
purposes
only
and
should
not
be
relied
upon
in
connection
with
any
investment
decision
regarding
the
securities
of
EFH
Corp.
or
its
subsidiaries.
All
of
these
amounts
are
estimates
based
on
EFH
Corp.'s
current
interpretation
of
the
covenants
set
forth
in
its
and
its
subsidiaries'
applicable
debt
agreements
and
do
not
take
into
account
exceptions
in
the
agreements
that
may
allow
for
the
incurrence
of
additional
secured
debt,
including,
but
not
limited
to,
acquisition
debt,
coverage
ratio
debt,
refinancing
debt,
capital
leases
and
hedging
obligations.
Moreover,
such
amounts
could
change
from
time
to
time
as
a
result
of,
among
other
things,
the
termination
of
any
debt
agreement
(or
specific
terms
therein)
or
a
change
in
the
debt
agreement
that
results
from
negotiations
with
new
or
existing
lenders.
In
addition,
covenants
included
in
agreements
governing
additional,
future
debt
may
impose
greater
or
lesser
restrictions
on
the
incurrence
of
secured
debt
by
EFH
Corp.
and
its
subsidiaries.
Consequently,
the
actual
amount
of
senior
secured
debt
that
EFH
Corp.
and
its
subsidiaries
are
permitted
to
incur
under
their
respective
debt
agreements
could
be
materially
different
than
the
amounts
provided
above.
EFH
Corp.
encourages
you
to
review,
in
consultation
with
your
own
advisors,
its
and
its
subsidiaries’
various
debt
agreements,
which
are
on
file
with
the
SEC,
in
order
to
assess
the
ability
and
capacity
of
EFH
Corp.
and
its
subsidiaries
to
incur
additional
debt
(secured
and
unsecured)
in
the
future.
2
Of
this
amount,
$1.0B
is
permitted
to
be
issued
for
cash
(entire
amount
is
permitted
to
be
issued
for
exchanges).
3
TCEH
is
permitted
to
issue
an
unlimited
amount
of
additional
first-priority
debt
in
order
to
refinance
the
first-priority
debt
outstanding
under
the
TCEH
Senior
Secured
Facilities. |
 15
Today’s Agenda
Q&A
Financial and Operational
Overview
Q1 2013 Review
John Young
President & CEO |
 Forward Natural Gas Prices and Heat Rates
Forward gas prices have shown some indications of stabilizing,
Heat rate markets continue to show volatility.
1
Calendar
2013
represents
market
price
for
the
balance
of
the
year.
For
example,
as
of
March
31,
2013,
the
market
price
is
for
April
to
December
2013.
2
2015
is
not
considered
liquid.
The
heat
rate
represents
indicative
pricing
from
limited
brokers.
16 |
 17
1
ERCOT Capacity, Demand and Reserve (CDR) Summary, December 2012.
2
ERCOT Capacity, Demand and Reserve (CDR) Summary, May 2013.
ERCOT reserve margin
2013E-2018E; percent
December 2012 CDR
1
May 2013 CDR
2
Resource Adequacy in ERCOT
13.75% target
reserve margin
–
–
–
–
13.2
13.8
11.6
10.4
10.5
9.4
'13
'14
'15
'16
'17
'18
ERCOT Loss of Load Probability
(LOLP) study results indicate a higher
target reserve margin is likely (i.e.,
15%-16%); final decision pending at
ERCOT
Stakeholders and PUCT continue
reviewing inputs to the ERCOT
reserve margin methodology (CDR)
PUCT considering additional market
design changes, such as an operating
reserve demand curve
Yesterday ERCOT issued the May
2013 CDR, which increased the 2014
planning reserve margin to 13.8
percent versus 10.9 in the December
2012 CDR. The increase is primarily
driven by higher expected generation
resources
Recent and pending PUCT/ERCOT
actions and potential deliberations: |
 18
Today’s Agenda
Q&A
Financial and Operational
Overview
Q1 2013 Review
EFH Corp. Senior Executive Team |
 19
Questions & Answers |
 20
Appendix –
Additional Slides and
Regulation G Reconciliations
Appendix |
 Financial Definitions
Measure
Definition
Adjusted (non-GAAP)
Operating Results
Net
income
(loss)
adjusted
for
items
representing
income
or
losses
that
are
not
reflective
of
underlying
operating
results.
These
items
include
unrealized
mark-to-market
gains
and
losses,
noncash
impairment
charges
and
other
charges,
credits
or
gains
that
are
unusual
or
nonrecurring.
EFH
Corp.
uses
adjusted
(non-GAAP)
operating
results
as
a
measure
of
performance
and
believes
that
analysis
of
its
business
by
external
users
is
enhanced
by
visibility
to
both
net
income
(loss)
prepared
in
accordance
with
GAAP
and
adjusted
(non-GAAP)
operating
earnings
(losses).
Adjusted EBITDA
(non-GAAP)
EBITDA
adjusted
to
exclude
interest
income,
noncash
items,
unusual
items,
results
of
discontinued
operations
and
other
adjustments.
Adjusted
EBITDA
is
not
intended
to
be
an
alternative
to
GAAP
results
as
a
measure
of
operating
performance
or
an
alternative
to
cash
flows
from
operating
activities
as
a
measure
of
liquidity
or
an
alternative
to
any
other
measure
of
financial
performance
presented
in
accordance
with
GAAP,
nor
is
it
intended
to
be
used
as
a
measure
of
free
cash
flow
available
for
EFH
Corp.’s
discretionary
use,
as
the
measure
excludes
certain
cash
requirements
such
as
interest
payments,
tax
payments
and
other
debt
service
requirements.
Because
not
all
companies
use
identical
calculations,
Adjusted
EBITDA
may
not
be
comparable
to
similarly
titled
measures
of
other
companies.
See
EFH
Corp.’s
filings
with
the
SEC
for
a
detailed
reconciliation
of
EFH
Corp.’s
net
income
prepared
in
accordance
with
GAAP
to
Adjusted
EBITDA.
Competitive Business
Results
Refers
to
the
combined
results
of
the
Competitive
Electric
segment
and
Corporate
&
Other.
Competitive
Electric
segment
refers
to
the
EFH
Corp.
business
segment
that
consists
principally
of
TCEH.
Contribution Margin (non-
GAAP)
Operating
revenues
less
fuel,
purchased
power
costs,
and
delivery
fees,
plus
or
minus
net
gain
(loss)
from
commodity
hedging
and
trading
activities,
which
on
an
adjusted
(non-GAAP)
basis,
exclude
unrealized
gains
and
losses.
EBITDA
(non-GAAP)
Net
income
(loss)
before
interest
expense
and
related
charges,
income
tax
expense
(benefit)
and
depreciation
and
amortization.
GAAP
Generally
accepted
accounting
principles.
Purchase Accounting
The
purchase
method
of
accounting
for
a
business
combination
as
prescribed
by
GAAP,
whereby
the
purchase
price
of
a
business
combination
is
allocated
to
identifiable
assets
and
liabilities
(including
intangible
assets)
based
upon
their
fair
values.
The
excess
of
the
purchase
price
over
the
fair
values
of
assets
and
liabilities
is
recorded
as
goodwill.
Depreciation
and
amortization
due
to
purchase
accounting
represents
the
net
increase
in
such
noncash
expenses
due
to
recording
the
fair
market
values
of
property,
plant
and
equipment,
debt
and
other
assets
and
liabilities,
including
intangible
assets
such
as
emission
allowances,
customer
relationships
and
sales
and
purchase
contracts
with
pricing
favorable
to
market
prices
at
the
date
of
the
Merger.
Amortization
is
reflected
in
revenues,
fuel,
purchased
power
costs
and
delivery
fees,
depreciation
and
amortization
and
interest
expense
in
the
income
statement.
Regulated Business Results
Refers
to
the
results
of
the
Regulated
Delivery
segment,
which
consists
largely
of
EFH
Corp.’s
investment
in
Oncor.
21 |
 Table
1: EFH Corp. Adjusted EBITDA Reconciliation Three Months Ended March 31, 2012
and 2013 $ millions
Factor
Q1 12
Q1 13
Net loss
(304)
(569)
Income tax benefit
(180)
(475)
Interest expense and related charges
785
784
Depreciation and amortization
337
351
EBITDA
638
91
Adjustments to EBITDA (pre-tax):
Oncor Holdings distributions of earnings
36
31
Interest income
(2)
-
Amortization of nuclear fuel
42
39
Purchase accounting adjustments
1
21
5
Impairment and write-down of assets
1
-
Equity in earnings of unconsolidated subsidiary (net of tax)
(57)
(67)
Unrealized net loss resulting from commodity hedging and trading
transactions
152
487
Noncash compensation expense
2
4
3
Transition and business optimization costs
3
9
6
Transaction and merger expenses
4
10
10
Restructuring and other
5
-
16
Expenses incurred to upgrade or expand a generation station
6
26
46
Subtotal
880
667
Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)
350
384
EFH Corp. Adjusted EBITDA per Restricted Payments Covenant
1,230
1,051
1
Includes
amortization
of
the
intangible
net
asset
value
of
retail
and
wholesale
power
sales
agreements,
environmental
credits,
coal
purchase
contracts,
nuclear
fuel
contracts
and
power
purchase
agreements
and
the
stepped-up
value
of
nuclear
fuel.
Also
includes
certain
credits
and
gains
on
asset
sales
not
recognized
in
net
income
due
to
purchase
accounting.
2
Represents
amounts
recorded
under
stock-based
compensation
accounting
standards
and
excludes
capitalized
amounts.
3
Includes
certain
incentive
compensation
expenses
as
well
as
professional
fees
and
other
costs
related
to
generation
plant
reliability
and
supply
chain
efficiency
initiatives.
4
Primarily
represents
Sponsor
Group
management
fees.
5
Includes
costs
associated
with
liability
management
program.
6
Represents
noncapital
outage
costs.
22 |
 Table
2: TCEH Adjusted EBITDA Reconciliation Three Months Ended March 31, 2012 and
2013 $ millions
Factor
Q1 12
Q1 13
Net loss
(238)
(524)
Income tax benefit
(115)
(378)
Interest expense and related charges
622
586
Depreciation and amortization
330
344
EBITDA
599
28
Adjustments to EBITDA (pre-tax):
Interest income
(17)
(4)
Amortization of nuclear fuel
42
39
Purchase accounting adjustments
1
9
5
Unrealized net loss resulting from commodity hedging and trading
transactions
152
487
EBITDA amount attributable to consolidated unrestricted subsidiaries
(2)
-
Corporate depreciation, interest and income tax expenses included in SG&A
expense 4
4
Noncash compensation expense
2
3
2
Transition and business optimization costs
3
9
5
Transaction and merger expenses
4
10
10
Restructuring and other
5
(1)
16
Expenses incurred to upgrade or expand a generation station
6
26
46
TCEH Adjusted EBITDA per Incurrence Covenant
834
638
Expenses related to unplanned generation station outages
26
10
TCEH Adjusted EBITDA per Maintenance Covenant
860
648
23
1
2
3
4
5
6
Includes amortization of the intangible net asset value of retail and wholesale power sales
agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power
purchase agreements and the stepped up value of nuclear fuel. Also includes certain
credits and gains on asset sales not recognized in net income due to purchase accounting.
Includes expenses recorded under stock-based compensation accounting standards and excludes
capitalized amounts. Includes certain incentive compensation expenses as well as professional fees and other costs related
to generation plant reliability and supply chain efficiency initiatives.
Primarily represents Sponsor Group management fees.
Includes costs associated with liability management program.
Represents noncapital outage costs.
|
 Table
3: Oncor Adjusted EBITDA Reconciliation Three Months Ended March 31, 2012 and
2013 $ millions
Factor
Q1 12
Q1 13
Net income
75
87
Income tax expense
49
39
Interest expense and related charges
91
94
Depreciation and amortization
184
199
EBITDA
399
419
Interest income
(8)
(1)
Purchase accounting adjustments1
(6)
(5)
Noncash compensation expense
1
1
Settlement of management incentive pay plan
-
1
Oncor Adjusted EBITDA
386
415
1
Purchase
accounting
adjustments
consist
of
amounts
related
to
the
accretion
of
an
adjustment
(discount)
to
regulatory
assets.
24 |