Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - Energy Future Holdings Corp /TX/ | d8k.htm |
| EX-99.1 - PRESS RELEASE - Energy Future Holdings Corp /TX/ | dex991.htm |
 EFH
Corp. Q2 2011 Investor Call
July 29, 2011
Exhibit 99.2 |
 1
Safe Harbor Statement
Forward Looking Statements
This presentation contains forward-looking statements, which are subject to
various risks and uncertainties. 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 long-term hedging program could be affected by, among other
things: any change in the ERCOT electricity market, including a regulatory or
legislative change, that results in wholesale electricity prices not being
largely correlated to natural gas prices; any decrease in market heat rates as
the long-term hedging program generally does not mitigate exposure
to
changes
in
market
heat
rates;
the
unwillingness
or
failure
of
any
hedge
counterparty or the lenders under the commodity collateral posting facility 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 long-term hedging
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
Q2 2011 Review
Paul Keglevic
Executive Vice President & CFO |
 Consolidated: reconciliation of GAAP net income to adjusted (non-GAAP) operating
results Q2 10 vs. Q2 11 ; $ millions, after tax
1
Three months ended June 30
EFH Corp.
Adjusted (Non-GAAP)
Operating
Results
-
QTR
3
Factor
Q2 10
Q2 11
Change
EFH Corp. GAAP net loss
(426)
(705)
(279)
Items
excluded
from
adjusted
(non-GAAP)
operating
results
(after
tax)
-
noncash:
Unrealized commodity-related mark-to-market net losses
93
45
(48)
Unrealized mark-to-market net losses on interest rate swaps
165
262
97
Debt extinguishment gains
(83)
(16)
67
Third-party fees associated with April 2011 TCEH amendment and extension
transactions -
64
64
State income tax charge due to April 2011 TCEH amendment and extension
transactions -
13
13
EFH Corp. adjusted (non-GAAP) operating loss
(251)
(337)
(86)
1 |
 Description/Drivers
Better (Worse)
Than
Q2 10
Competitive business²:
Lower net margin from asset management and retail activities, including commodity
hedging (49)
Higher fuel costs at legacy generation units primarily due to increased costs of
purchased coal and related transportation (8)
Impact of new lignite-fueled generation units
18
Higher retail consumption primarily due to warmer weather
11
Higher net production from legacy generation units
5
Lower amortization of intangibles arising from purchase accounting
3
Contribution margin
(20)
Gains in 2010 on sales of assets (reported in other income)
(48)
Higher net interest expense driven by higher amortization of debt issuance and
amendment costs and lower capitalized interest (20)
Higher depreciation reflecting the new lignite-fueled generation units and ongoing
investment in the legacy generation fleet (14)
Higher operating costs due to increased planned outage maintenance expense at nuclear
generation facility and the impact of new lignite-fueled generation units
(12)
Lower retail bad debt expense reflecting improved collections and customer mix
7
Effect of accrued interest on uncertain income tax positions (included in income tax
expense) 6
All
other
-
net
2
Total
change
-
Competitive
business
(99)
Regulated business:
Higher revenues from transmission rate and distribution tariff increases and growth in
points of delivery 19
Higher revenues from increased consumption primarily due to warmer weather
16
Higher depreciation reflecting infrastructure investment
(9)
Higher transmission fees
(5)
Higher net interest expense
(2)
All other -
net
(6)
Total
change
-
Regulated
business
(~80%
owned
by
EFH
Corp.)
13
Total change in EFH Corp. adjusted (non-GAAP) operating results
(86)
Consolidated key drivers of the change in (non-GAAP) operating results
Q2 10 vs. Q2 11; $ millions, after tax
EFH Corp.
Adjusted
(Non-GAAP)
Operating
Results
Key
Drivers
(after
tax)
-
QTR
4
1
Three months ended June 30
2
Competitive business consists of Competitive Electric segment and Corp. &
Other. 1 |
 Consolidated: reconciliation of GAAP net income to adjusted (non-GAAP) operating
results YTD 10 vs. YTD 11 ; $ millions, after tax
EFH Corp.
Adjusted
(Non-GAAP)
Operating
Results
-
YTD
5
Factor
YTD 10
YTD 11
Change
EFH Corp. GAAP net loss
(71)
(1,066)
(995)
Items
excluded
from
adjusted
(non-GAAP)
operating
results
(after
tax)
-
noncash:
Unrealized commodity-related mark-to-market net (gains) losses
(546)
248
794
Unrealized mark-to-market net losses on interest rate swaps
235
170
(65)
Debt extinguishment gains
(93)
(16)
77
Third-party fees associated with April 2011 TCEH amendment and extension
transactions -
64
64
Gain related to counterparty bankruptcy settlement
-
(14)
(14)
Income
tax
charges
8
13
5
EFH Corp. adjusted (non-GAAP) operating loss
(467)
(601)
(134)
2
1
1
2
Six months ended June 30
YTD 2010 charges recorded as a result of health care legislation in 2010; YTD 2011 state
income tax charges recorded as a result of TCEH amendment and extension transaction. |
 Description/Drivers
Better (Worse)
Than
YTD 10
Competitive business²:
Lower net margin from asset management and retail activities, including commodity
hedging (96)
Impact of winter weather event
(17)
Higher fuel costs at legacy generation units primarily due to increased costs of
purchased coal and related transportation (14)
Impact of new lignite-fueled generation units
36
Lower amortization of intangibles arising from purchase accounting
10
All
other
–
net
(9)
Contribution margin
(90)
Gains in 2010 on sales of assets (reported in other income)
(52)
Higher depreciation reflecting the new lignite-fueled generation units and ongoing
investment in the legacy generation fleet (31)
(24)
Lower retail bad debt expense reflecting improved collections and customer mix
21
Lower net interest expense driven by reduced amortization of dedesignated swap
losses 14
Lower accrued interest on uncertain tax positions
14
Other
-
net
14
Total
change
-
Competitive
business
(134)
Regulated business:
32
Higher revenues from increased consumption primarily due to warmer weather
5
Higher depreciation reflecting infrastructure investment
(12)
Higher operating costs, primarily transmission fees and vegetation management
expense (11)
Higher net interest expense driven by average rates
(5)
Lower accretion resulting from purchase accounting
(4)
All
other
–
net
(5)
Total
change
-
Regulated
business
(~80%
owned
by
EFH
Corp.)
-
Total change in EFH Corp. adjusted (non-GAAP) operating results
(134)
Consolidated key drivers of the change in (non-GAAP) operating results
YTD 10 vs. YTD 11; $ millions, after tax
EFH Corp.
Adjusted
(Non-GAAP)
Operating
Results
Key
Drivers
(after
tax)
-
YTD
6
1
Six months ended June 30
2
Competitive business consists of Competitive Electric segment and Corp. &
Other. Higher net revenues reflecting transmission rate and distribution tariff increases,
including AMS surcharge and growth in points of delivery
Higher operating costs due to increased planned outage maintenance expense at nuclear generation facility
and the impact of new lignite-fueled generation units
1 |
 EFH
Corp. Adjusted EBITDA (Non-GAAP) EFH Corp. Adjusted EBITDA
(non-GAAP) Q2
10 vs. Q2 11 and YTD
10 vs. YTD 11;
$ millions
Q2 11
Q2 10
1,266
1,303
858
940
404
357
TCEH
Oncor
7
3%
9%
13%
1
See
Appendix
for
Regulation
G
reconciliations
and
definition.
Includes
$6
million,
$4
million,
$16
million
and
$14
million
in
Q2
10,
Q2
11,
YTD
10
and
YTD
11,
respectively,
of
Corp.
&
Other Adjusted EBITDA.
3
Three months ended June 30
3
Six months ended June 30
YTD 11
YTD 10
2,432
2,566
1,663
1,831
755
719
5%
9%
5%
3
2
1
Q2 and YTD performance was largely driven by the same key drivers impacting adjusted (non-
GAAP) operating results. Adjusted EBITDA includes cash proceeds from sale of mineral interests
of $43 million which is not included in GAAP operating results. |
 Luminant Operational Results
8
Nuclear-fueled generation; GWh
Coal-fueled generation; GWh
Sandow 5 & Oak Grove
Legacy coal-fueled plants
Q2
2011
Nuclear
Plant
Results
Solid safety performance
Refueling outages in both Q2 2011 and
Q2 2010; lower generation due to
unplanned outage
Top decile industry performance for
reliability and cost
Q2
2011
Coal-Fueled
Plant
Results
New plants operated at ~83% capacity
factor for 1.4 TWh higher generation
Higher legacy coal-fueled generation due
to fewer planned outages and improved
reliability
Top quartile industry performance
1
Variance
does
not
include
generation
from
Sandow
5
and
Oak
Grove
1
&
2.
Q2 11
Q2 10
4,527
9,539
YTD 10
YTD 11
9,590
4,384
3%
QTR
3,952
4,802
8%
1
QTR
2,579
YTD 11
Q2 10
12,479
14,657
7,544
25,297
28,623
Q2 11
YTD 10
<1%
YTD
3%
1
YTD
21,079
20,495
10,705
9,900 |
  9
Q2 2011 Results
Lower LCI volumes reflect
competitive intensity and TXU Energy
focus on margin discipline
Lower residential sales volumes
driven by lower customer counts
offset by warmer weather in Q2 11
compared to Q2 10
Launched TXU Energy FlexPower
prepaid product to expand customer
base for control focused, cash based
and deposit required customer
segments
TXU Energy Operational Results
Total residential customers
End of period, thousands
Retail electricity sales volumes by customer class;
GWh
1,739
1,706
1
SMB
–
small
business
2
LCI -
large commercial and industrial
3
Latest twelve months
YTD 10
SMB
LCI
2
Residential
Q2 10
12,766
24,986
Q2 10
Q1 11
7%
LTM
3
12,777
6,848
6,509
3,925
1,993
3,572
Q2 11
Q2 11
1,706
1,830
2%
QTR
13,568
7,444
3,974
6,833
3,251
1,806
22,858
11,890
Q2 11
YTD 11
9%
YTD
7%
QTR
1 |
 16,245
16,380
31,799
32,880
19,476
19,284
9,067
8,419
10
Oncor Operational Results
Electric energy billed volumes
4
; GWh
Q2 10
Q2 11
1
SMB
–
small
business;
LCI
–
large
commercial
and
industrial
2
AMS –
Advanced Metering System
3
CREZ –
Competitive Renewable Energy Zone
4
On average, billed volumes are on an approximate 17-day calendar lag; therefore,
amounts shown reflect partial impacts from prior quarters
5
Latest twelve months
Residential
SMB
&
LCI
3,159
3,189
1%
LTM
5
Electricity distribution points of delivery
End of period, thousands of meters
Q2 11
Q1 11
3,181
3,189
Q2 2011 Results
Higher volumes principally due to
warmer weather in Q2 11 compared
to Q2 10
Higher
SMB
&
LCI
1
energy
volumes
due to improved economy and
warmer weather
Execution
of
AMS
2
plan
–
~227,000
advanced meters installed during Q2
11; over 1.8 million installed through
June 30, 2011
$538
million
spent
on
CREZ
3
through
June 30, 2011; $222 million spent
YTD 11
3%
YTD
1%
YTD
Q2 11
24,664
25,447
51,275
52,164
8%
QTR
Q2 10
YTD 10
YTD 11
1%
QTR
1 |
 2,054
1,432
622
1,250
208
1,042
780
Facilities Limit
LOCs/Cash Borrowings
Availability
EFH Corp. Liquidity Management
As of June 30, 2011
11
Cash and Equivalents
TCEH Letter of Credit Facilities
TCEH Revolving Credit Facilities
1,664
3,304
EFH Corp. and TCEH continue to monitor capital market conditions
to ensure liquidity needs
and financial flexibility.
1
Facility to be used for issuing letters of credit for general corporate purposes.
Cash borrowings of $1.250 billion were drawn on this facility in October 2007, and except
for $115 million related to a letter of credit drawn in June 2009, have been
retained as restricted cash. Outstanding letters of credit are supported by the restricted
cash.
EFH Corp. (excluding Oncor) available liquidity
As of 6/30/11; $ millions
1
2,420 |
 12
12
12
Commodity Prices
Commodity
Units
Q2 11 Actual
Q2 10 Actual
YTD 11
Actual
BOY 11E
NYMEX gas price
$/MMBtu
$4.35
$4.30
$4.26
$4.47
HSC gas price
$/MMBtu
$4.32
$4.25
$4.21
$4.46
7x24
market
heat
rate
(HSC)
MMBtu/MWh
8.08
8.17
8.72
8.42
North
Hub
7x24
power
price
4
$/MWh
$34.82
$34.85
$36.95
$37.51
TCEH
weighted
avg.
hedge
price
5
$/MMBtu
$7.35
$7.51
$7.64
$7.49
Gulf Coast ultra-low sulfur diesel
$/gallon
$3.08
$2.14
$2.95
$3.00
PRB 8400 coal
$/ton
$10.36
$9.59
$10.91
$11.40
LIBOR interest rate
6
percent
0.42%
0.63%
0.44%
0.40%
Commodity prices
Q2 11, Q2 10, YTD 11 and BOY 11E; mixed measures
1
BOY 11 estimate based on commodity prices as of 06/30/11 for July 1, 2011 through
December 31, 2011 2
Based on NYMEX forward curve
3
Based on ERCOT market clearing price for North Hub power for 2011 and ERCOT
market clearing price for North Zone for 2010 4
Excluding
the
volatile
pricing
that
occurred
in
early
February
2011
(2
and
3 ),
North
Hub
7X24
power
prices
averaged
approximately
$32.54
and
the
7X24
market
heat
rate averaged
7.71 MMBtu/MWh during the first 6 months of 2011
5
Weighted average prices in the TCEH long-term natural gas hedging
program. Based on NYMEX Henry Hub prices of forward natural gas sales positions in the long-term hedging
program
(excluding the impact of offsetting purchases for rebalancing and pricing point
basis transactions). The index for the settled value is a 6-month LIBOR rate.
6
The index for the settled value is a six-month LIBOR rate
nd
rd
3
1
2 |
 13
Factor
Measure
2011
2012
2013
2014
2015
Total or
Avg.
3/31/11
Natural gas hedges
mm MMBtu
~150
~398
~274
~149
~0
~971
Wtd. avg. hedge price
$/MMBtu
~$7.45
~$7.36
~$7.19
~$7.80
N/A
Natural gas prices
$/MMBtu
~$4.57
~$5.06
~$5.41
~$5.73
~$6.08
Cum.
MtM
gain
at
3/31/11
2
$ billions
~$0.8
~$1.1
~$0.5
~$0.4
N/A
~$2.8
06/30/11
Natural
gas
hedges
3
mm MMBtu
~88
~383
~265
~149
~0
~885
Wtd.
avg.
hedge
price
1
$/MMBtu
~$7.49
~$7.36
~$7.19
~$7.80
N/A
Natural gas prices
$/MMBtu
~$4.47
~$4.84
~$5.16
~$5.42
~$5.70
Cum.
MtM
gain
at
06/30/11
2
$ billions
~$0.6
~$1.2
~$0.6
~$0.4
~$0
~$2.7
Q2 11 MtM (loss) gain
$ billions
~$(0.2)
~$0.1
~$0.1
~$0
N/A
~$(0.1)
13
Unrealized Mark-To-Market Impact Of Hedging
Unrealized mark-to-market impact of hedging program
06/30/11 vs. 3/31/11; mixed measures, pre-tax
The overall value of the hedge program remained relatively flat as transactions
maturing during the quarter were offset by increases in value in the forward years of the
program. 1
Weighted average prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the long-term
hedging
program
(excluding
the
impact
of
offsetting
purchases for
rebalancing and
pricing
point
basis
transactions).
Where
collars
are
reflected,
sales
price
represents
the
collar
floor
price.
6/30/11
prices
for
2011
represent
July
1,
2011
through
December
31, 2011 values.
2
MtM values include the effects of all transactions in the long-term hedging program including
offsetting purchases (for re-balancing) and natural gas basis deals. 3
As of 6/30/11, 2011 represents July 1, 2011 through December 31,
2011 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 corresponds to a delta position of approximately 115
million MMBtu in 2014. |
 139
168
43
10
2
276
265
149
79
107
11
45
301
443
608
229
596
609
602
610
BAL 11
2012
2013
2014
2015
14
14
TCEH Natural Gas Exposure
TCEH Natural Gas Position
11-15 ; million MMBtu
Hedges Backed by Asset First Lien
Open Position
1
As of
.
Balance
of
2011
is
from
August
1,
2011
to
December
31,
2011.
Assumes
conversion
of
electricity
positions
based
on
a
~8.0
heat
rate
with
natural
gas
generally
being
on
the
margin
~75-90%
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 retail/wholesale effects. 2011 position includes ~2
million MMBtu of short gas positions associated with proprietary trading positions; excluding these positions,
2011 position is ~94% hedged.
100% Hedge Level
Factor
Measure
BAL 11
2012
2013
2014
2015
Total or Average
Natural gas hedging program
million
MMBtu
~79
~383
~265
~149
~0
~876
TXUE and Luminant net positions
million
MMBtu
~139
~168
~43
~10
~2
~362
Overall estimated percent of
total NG position hedged
percent
~95%
~93%
~51%
~26%
~0%
~47%
TXUE and Luminant Net Positions
Hedges Backed by CCP
1
2
06/30/1 |
 15
15
15
EFH Corp. Adjusted EBITDA Sensitivities
Commodity
Percent Hedged at
June 30, 2011
Change
BOY 11E
Impact
$ millions
7X24 market heat rate (MMBtu/MWh)
~90
0.1 MMBtu/MWh
~2
NYMEX gas price ($/MMBtu)
>95
$1/MMBtu
~11
Texas gas vs. NYMEX Henry Hub price ($/MMBtu)
3,4
~90
$0.10/MMBtu
~2
Diesel ($/gallon)
5
>95
$1/gallon
~1
Base coal ($/ton)
6
>95
$2/ton
~1
Generation operations
Nuclear-
and coal / lignite-fueled generation (TWh)
N/A
1 TWh
~15
Retail operations
FY 2011
Residential contribution margin ($/MWh)
13 TWh
$1/MWh
~13
Residential consumption
13 TWh
1%
~4
Business markets consumption
11 TWh
1%
~1
Impact on EFH Corp. Adjusted EBITDA
11E; mixed measures
The majority of 2011 commodity-related risks are significantly mitigated.
1
2011 estimate based on commodity positions as of 06/30/11, net of long-term
hedges and wholesale/retail effects, excludes gains and losses incurred prior to June 30, 2011. See
Appendix for definition.
2
Simplified representation
of
heat
rate
position
in
a
single
TWh
position.
In
reality,
heat
rate
impacts
are
differentiated
across
plants
and
respective
pricing
periods:
nuclear-
and coal /
lignite-fueled
plants
(linked
primarily
to
changes
in
North
Hub
7x24),
natural
gas
plants
(primarily
North
Hub
5x16)
and
wind
(primarily
West
Hub7x8).
3
Assumes conversion of electricity positions based on a ~8.0 market heat rate with
natural gas generally being on the margin ~75-90% of the time (i.e., when coal is forecast to be on the
margin, no natural gas position is assumed to be generated).
4
The percentage hedged represents
the
amount
of
estimated
natural
gas
exposure
based
on
Houston
Ship
Channel
(HSC)
gas
price
sensitivity
as
a
proxy
for
Texas
gas price.
5
Includes positions related to fuel surcharge on rail transportation.
6
Excludes fuel surcharge on rail transportation.
1
2 |
 EFH
Corp. Maturity Profile EFH
Corp.
debt
maturities
1
(excluding
Oncor),
2011-2021
and
thereafter
As of 6/30/11; $ millions
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021+
4,299
2
3,165
11
4,510
5,000
2,180
1,750
1,067
1,029
1,494
1,571
15,005
46
1,485
2,089
3
267
3,847
3,343
295
3
435
1
Includes amortization of the $15.4 billion Term Loan/DDTL facility beginning in Q4
2014 and excludes unamortized discounts and premiums. 2
Excludes
the
Deposit
Letter
of
Credit
Loans
maturing
in
2014
and
2017.
3
Non-Extended Revolver and Extended Revolver capacities are $645 million and
$1.409 billion respectively. 563
15,608
2
406
TCEH-1
Lien
EFH Corp
EFCH
TCEH-LBO
EFIH 1
Lien
TCEH-Revolver
TCEH-Other/PCRBs
TCEH-2
Lien
EFIH 2
Lien
16
st
nd
st
nd |
 17
Today’s Agenda
Q&A
Financial
and
Operational
Overview
Q2 2011 Review
John Young
President & CEO |
 18
Currently
Installed
1
Environmental
Control
Equipment
At
Luminant Coal Units
Coal Unit
Capacity
(MW)
FGD
(Scrubber)
Activated
Carbon
Injection
ESP
4
SNCR
5
SCR
5
Bag-
house
4
Fuel Source
Oak Grove 1
800
Lignite
Oak Grove 2
800
Lignite
Sandow 4
557
Lignite
Sandow 5
580
Lignite
Martin Lake 1
750
Lignite/PRB
6
Martin Lake 2
750
Lignite/PRB
Martin Lake 3
750
Lignite/PRB
Monticello 1
565
Lignite/PRB
Monticello 2
565
Lignite/PRB
Monticello 3
750
Lignite/PRB
Big Brown 1
575
Lignite/PRB
Big Brown 2
575
Lignite/PRB
Currently installed
1
There is no assurance that the currently installed control equipment will satisfy
the requirements under any change to applicable law or any future Environmental Protection Agency or
Texas Commission on Environmental Quality regulations.
2
FGD refers to flue gas desulfurization systems that reduce SO2 emissions with
co-benefits of other emissions reductions. 3
Activated carbon injection systems reduce mercury emissions.
4
ESP refers to electro-static precipitation systems. ESP and bag-house
systems reduce particulate emissions with co-benefits of other emissions reductions.
5
SNCR refers to selective non-catalytic reduction systems. SCR refers to
selective catalytic reduction systems. Both systems reduce NOx emissions.
6
PRB refers to Powder River Basin coal transported to plants via
railcar. 3
2 |
 Cross State Air Pollution Rule
Compliance Options
Option
Why We Are Considering This Option
•
Dry sorbent injection (DSI), assuming
adequate supply of sorbent
•
DSI potentially promising in SO2 removal; not yet proven on large scale or
with sustained operations. Sorbent market depth not fully tested
•
Increased levels of scrubber
utilization at sites with installed
equipment
•
At legacy Luminant units, maximum scrubber emissions reductions generally
in the 80-85% range before causing significant unit capacity reductions
•
Fuel switching
•
Switching from lignite to PRB fuel would reduce emissions, but impacts costs,
jobs, and infrastructure
•
Fuel switching at Luminant units requires de-rates due to higher boiler
temperatures until large boiler components can be replaced
•
May be in conjunction with mothballing/closure of related lignite mines
•
Reduced operating levels or
seasonal/temporary shut-downs at
certain fossil plants
•
Reduced operations may be required to ensure compliance, due to
impossibility of achieving sufficient reductions through other means beginning
January 1, 2012
•
Options include systematic reductions in operating levels, seasonal
shutdowns, temporary shutdowns, or mothballing certain fossil units
•
Mothballing certain fossil-fueled units
and lignite mines
•
Mothballing certain units may be efficient, due to impossibility
of achieving
reductions with current scrubbers or retrofitting by January 1, 2012
•
Fuel switching to PRB would lead to lack of demand for lignite
Emissions reduction must be achieved beginning January 1, 2012; impossible to
retrofit units in time to reach required emissions reductions beginning that
date Existing scrubbers on our legacy units cannot achieve 90-95%
reductions Switching from lignite to PRB (lower sulfur) fuel would have
significant impacts on Texas jobs; switching will impact costs and result in
de-rates until boiler components can be replaced Expect insufficient
near-term liquidity in emissions markets to buy required allowances
Near-term compliance will require deploying a combination of the compliance
options listed below: 19 |
 20
Luminant Coal/Lignite Plant And Mine Employees
1
Full Time Equivalent employees as of June 30, 2011
Plant/Mine Site
FTEs
Big Brown Plant
121
Big Brown Mine
225
Martin Lake Plant
256
Martin Lake Mine
688
Monticello Plant
195
Monticello Mine
289
Sandow Plant
145
Three Oaks Mine
259
Oak Grove Plant
149
Kosse Mine
319
Total coal/lignite plant employees
866
Total mine employees
1,780
Luminant –
total coal/lignite plant and mine employees
2,646
1 |
 21
Today’s Agenda
Q&A
Financial and Operational
Overview
Q2 2011 Review
EFH Corp. Senior Executive Team |
 22
Questions & Answers |
 23
Appendix –
Additional Slides and
Regulation G Reconciliations
Appendix |
 24
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 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, income
from discontinued operations and other adjustments allowable under the EFH
senior secured notes indenture. Adjusted EBITDA plays an important role in respect of
certain covenants contained in this indenture. 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’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’s filings with the SEC for a
detailed reconciliation of EFH’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. 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 Oncor and the Oncor ring-fenced entities.
|
 25
Table 1: EFH Corp. Adjusted EBITDA Reconciliation
Three and Six Months Ended June 30, 2010 and 2011
$ millions
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
Impairment of assets includes impairments of land.
3
Represents
amounts
recorded
under
stock-based
compensation
accounting
standards
and
excludes
capitalized
amounts.
4
Includes incentive compensation expenses and professional fees primarily for retail
billing and customer care systems enhancements. 5
Includes costs related to the 2007 merger and abandoned strategic transactions, the
Sponsor Group management fee, outsourcing transition costs, administrative costs related to the
cancelled program to develop coal-fueled facilities, and costs related to
certain growth initiatives. 6
Includes net third-party fees paid in connection with the amendment and
extension of the TCEH Senior Secured Facilities, gains on termination of a long-term power sales contract and
settlement of amounts due from a hedging/trading counterparty and reversal of
certain liabilities accrued in purchase accounting. 7
Reflects noncapital outage costs.
Factor
Q2 10
Q2 11
YTD 10
YTD 11
Net loss attributable to EFH Corp.
(426)
(705)
(71)
(1,066)
Income tax benefit
(237)
(384)
(35)
(599)
Interest expense and related charges
1,122
1,301
2,074
1,945
Depreciation and amortization
350
371
692
740
EBITDA
809
583
2,660
1,020
Adjustments to EBITDA (pre-tax):
Oncor distributions/dividends
57
16
87
32
Interest income
-
-
(9)
(2)
Amortization of nuclear fuel
27
32
64
69
Purchase
accounting
adjustments
58
88
114
138
Impairment
of
assets
and
inventory
write-down
2
1
2
1
Net gain on debt exchange offers
(129)
(25)
(143)
(25)
Equity in earnings of unconsolidated subsidiary
(59)
(72)
(122)
(122)
Unrealized net (gain) loss resulting from hedging transactions
145
69
(848)
385
Amortization of “day one”
net loss on Sandow 5 power purchase agreement
(5)
-
(11)
-
Noncash
compensation
expense
4
3
13
3
Severance expense
-
2
3
5
Transition
and
business
optimization
costs
4
-
9
-
14
Transaction
and
merger
expenses
5
11
9
24
18
Restructuring
and
other
6
6
100
-
73
Expenses
incurred
to
upgrade
or
expand
a
generation
station
77
64
100
100
EFH Corp. Adjusted EBITDA per Incurrence Covenant
1,003
879
1,934
1,709
Add back Oncor adjustments
300
387
632
723
EFH Corp. Adjusted EBITDA per Restricted Payments Covenant
1,303
1,266
2,566
2,432
1
2
3
7 |
 26
Table 2: TCEH Adjusted EBITDA Reconciliation
Three and Six Months Ended June 30, 2010 and 2011
$ millions
Factor
Q2 10
Q2 11
YTD 10
YTD 11
Net income (loss)
(406)
(650)
43
(951)
Income tax expense (benefit)
(212)
(343)
46
(499)
Interest expense and related charges
915
1,150
1,664
1,651
Depreciation and amortization
344
364
681
726
EBITDA
641
521
2,434
927
Adjustments to EBITDA (pre-tax):
Interest income
(21)
(19)
(42)
(46)
Amortization of nuclear fuel
27
32
64
69
Purchase accounting adjustments
1
47
77
91
115
Impairment of assets and inventory write down
2
1
-
1
-
Unrealized net (gain) loss resulting from hedging transactions
145
69
(848)
385
EBITDA amount attributable to consolidated unrestricted subsidiaries
-
(1)
-
(3)
Amortization of “day one”
net loss on Sandow 5 power purchase agreement
(5)
-
(11)
-
Corp. depreciation, interest and income tax expense included in SG&A
3
4
5
7
Noncash compensation expense
3
3
3
10
3
Severance expense
-
2
3
2
Transition and business optimization costs
4
1
9
2
15
Transaction and merger expenses
5
10
8
21
19
Restructuring and other
6
11
89
1
70
Expenses incurred to upgrade or expand a generation station
7
77
64
100
100
TCEH Adjusted EBITDA per Incurrence Covenant
940
858
1,831
1,663
Expenses related to unplanned generation station outages
32
33
91
91
Pro forma adjustment for Oak Grove 2 reaching 70% average capacity in Q2 2011
8
-
25
-
25
Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant
9
4
-
9
8
TCEH Adjusted EBITDA per Maintenance Covenant
976
916
1,931
1,787
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 impairment of land.
Includes expenses recorded under stock-based compensation accounting standards and excludes
capitalized amounts.
Includes incentive compensation expenses and professional fees primarily for retail billing and
customer care systems enhancements.
Includes costs related to the 2007 merger, the Sponsor Group management fee, outsourcing transition
costs and costs related to certain growth initiatives.
Includes net third-party fees paid in connection with the amendment and extension of the TCEH
Senior Secured Facilities, gains on termination of a long-term power sales contract and settlement of amounts due from
a hedging/trading counterparty, and reversal of certain liabilities accrued in purchase accounting. Reflects noncapital outage costs.
Represents the annualization of the actual three months ended June 30, 2011 EBITDA results for Oak
Grove 2. The TCEH senior secured facilities provide that upon achievement of 70% average capacity factor
the applicable unit’s EBITDA shall be included in the EBITDA calculation. Primarily pre-operating expenses related to Oak Grove and Sandow 5 generation facilities. 1
2
3
4
5
6
7
8
9 |
 1
27
1
Purchase accounting adjustments consist of amounts related to the accretion of an
adjustment (discount) to regulatory assets. Table 3: Oncor Adjusted EBITDA
Reconciliation Three Months Ended June 30, 2010 and 2011
$ millions
Factor
Q2 10
Q2 11
YTD 10
YTD 11
Net income
76
92
155
157
Income tax expense
47
58
96
98
Interest expense and related charges
86
88
170
177
Depreciation and amortization
164
178
331
350
EBITDA
373
416
752
782
Interest income
(9)
(8)
(19)
(18)
Purchase
accounting
adjustments
(9)
(7)
(18)
(15)
Transition and business optimization costs and other
2
3
4
6
Oncor Adjusted EBITDA
357
404
719
755 |