Attached files
| file | filename |
|---|---|
| EX-99.1 - PRESS RELEASE - Energy Future Holdings Corp /TX/ | dex991.htm |
| 8-K - FORM 8-K - Energy Future Holdings Corp /TX/ | d8k.htm |
 EFH
Corp. Q2 2010 Investor Call
August 3, 2010
Exhibit 99.2 |
 1
Safe Harbor Statement
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).
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. 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 lender under the commodity collateral
posting facility to perform its obligations; or any other unforeseen event
that results in the inability to continue to use a first lien to secure a
substantial portion of the hedges under the long- term hedging
program. |
 Today’s Agenda
Q&A
Financial and Operational
Overview
Q2 2010 Review
Paul Keglevic
Executive Vice President & CFO
2 |
 3
(248)
-
(299)
206
(155)
Q2 09
(3)
(251)
EFH Corp. adjusted (non-GAAP) operating (loss)
464
165
Unrealized mark-to-market net (gains) losses on interest rate swaps
(83)
93
(426)
Q2 10
(83)
Debt extinguishment
(gain)
–
Q2
10
debt
exchanges
and
repurchases
(113)
Unrealized commodity-related mark-to-market net (gains) losses
Items excluded from adjusted
(non-GAAP)
operating
results
(after
tax)
-
noncash:
(271)
GAAP net (loss) attributable to EFH Corp.
Change
Factor
Consolidated:
reconciliation
of
GAAP
net
income
(loss)
to
adjusted
(non-GAAP)
operating
results
¹
Q2
²
09
vs.
Q2
10;
$
millions,
after
tax
EFH Corp. Adjusted (Non-GAAP) Operating Results -
QTR
1
See Appendix for Regulation G reconciliations and definitions.
2
Three months ended June 30 |
 4
8
8
-
Income
tax charge recorded as a result of health care legislation enacted by
Congress in March 2010
(90)
-
90
Goodwill impairment charge
(512)
-
(432)
(457)
287
YTD 09
45
(467)
EFH Corp. adjusted (non-GAAP) operating (loss)
667
235
Unrealized mark-to-market net (gains) losses on interest rate swaps
(93)
(546)
(71)
YTD 10
(93)
Debt extinguishment (gain) –
2010 debt exchanges and repurchases
(89)
Unrealized commodity-related mark-to-market net (gains) losses
Items excluded from adjusted (non-GAAP) operating
results
(after
tax)
-
noncash:
(358)
GAAP net income (loss) attributable to EFH Corp.
Change
Factor
Consolidated:
reconciliation
of
GAAP
net
income
(loss)
to
adjusted
(non-GAAP)
operating
results
¹
YTD
²
09
vs.
YTD
10;
$
millions,
after
tax
1
See Appendix for Regulation G reconciliations and definitions.
2
Six months ended June 30
EFH Corp. Adjusted (Non-GAAP) Operating Results -
YTD |
 5
Consolidated key drivers of the change in (non-GAAP) operating results
Q2
¹
10 vs. Q2 09; $ millions, after tax
(9)
Higher depreciation reflecting ongoing investment in generation fleet
Description/Drivers
Better
(Worse)
Than
Q2 09
Competitive business²:
Impact of new lignite-fueled generation units
70
Lower amortization of intangibles arising from purchase accounting
17
Higher margin from asset management and the retail business
14
Higher fuel expense at the legacy coal-fueled generation units primarily due to
increased transportation costs (25)
Lower
production
from
nuclear
fueled
generation
units
due
to
timing
of
refueling
outage
(19)
All other -
net
(12)
Contribution margin
45
Gains on sales of assets (reported in other income)
48
Lower costs related to outsourcing transition and new retail customer care
system 19
Higher
net
interest
expense
driven
by
lower
capitalized
interest
due
to
completion
of
new
generation
units
(42)
Higher depreciation reflecting the three new lignite-fueled generation units and
mining facilities (29)
Higher operating costs related to new generation units
(16)
Higher nuclear plant maintenance due to timing of refueling outage
(11)
All other -
net
(1)
Total improvement -
Competitive business
4
Regulated business:
Higher
distribution
tariffs,
including
the
rates
approved
in
the
September
2009
final
rate
review
order
16
Surcharge to recover AMS deployment costs
10
Higher depreciation reflecting higher depreciation rates approved in the September
final rate review order and infrastructure investment (21)
Higher costs reflecting amortization of regulatory assets approved for recovery, AMS
implementation and higher transmission fees (14)
All
other
–
net
(includes
noncontrolling
interests)
2
Total improvement –
Regulated business (80% owned by EFH Corp.)
(7)
Total change in EFH Corp. adjusted (non-GAAP) operating results
(3)
1
Three months ended June 30
2
Competitive business consists of Competitive Electric segment and Corp. &
Other. EFH Corp. Adjusted (Non-GAAP) Operating Results -
QTR |
 6
Consolidated key drivers of the change in (non-GAAP) operating results
YTD
¹
10 vs. YTD 09; $ millions, after tax
(52)
Higher depreciation reflecting the three new lignite-fueled generation units and
mining facilities (25)
Higher depreciation reflecting ongoing investment in generation fleet
Description/Drivers
Better
(Worse)
Than
YTD 09
Competitive business²:
Impact of new lignite-fueled generation units
122
Lower amortization of intangibles arising from purchase accounting
35
Higher margin from asset management and the retail business
36
Higher
retail
volumes
primarily
driven
by
colder
winter
weather
and
improvement
in
economy
20
Higher fuel expense at the legacy coal-fueled generation units primarily due to
increased transportation costs (45)
Lower production from nuclear fueled generation units due to timing of refueling
outage and main transformer replacement (25)
All Other –
net
(2)
Contribution margin
141
Gains on sales of assets (reported in other income)
52
Lower costs related to outsourcing transition and new retail customer care
system 29
Higher net interest expense primarily driven by lower capitalized interest due to
completion of new generation units (69)
Higher operating costs related to new generation units
(29)
Higher retail bad debt expense
(10)
All other -
net
(2)
Total improvement -
Competitive business
35
Regulated business:
Higher
distribution
tariffs,
including
the
rates
approved
in
the
September
2009
final
rate
review
order
32
Higher average consumption driven by the effect of weather
27
Surcharge to recover AMS deployment costs
19
Higher depreciation reflecting higher depreciation rates approved in the September
final rate review order and infrastructure investment (47)
Higher costs reflecting amortization of regulatory assets approved for recovery, AMS
implementation and higher transmission fees (29)
All
other
–
net
(includes
noncontrolling
interests)
8
Total improvement –
Regulated business (80% owned by EFH Corp.)
10
Total change in EFH Corp. adjusted (non-GAAP) operating results
45
1
Six months ended June 30
2
Competitive business consists of Competitive Electric segment and Corp. &
Other. EFH Corp. Adjusted (Non-GAAP) Operating Results -
YTD |
 7
TCEH
EFH Corp. Adjusted EBITDA (Non-GAAP)
YTD 10
YTD 09
2,566
2,307
1
See Appendix for Regulation G reconciliations and definition. Includes $12
million, $6 million, $16 million and $16 million in Q2 09, Q2 10, YTD 09 and YTD 10, respectively, of Corp. &
Other Adjusted EBITDA.
2
Three months ended June 30
3
Six months ended June 30
Q2 10 and YTD 10 performance was largely driven by the same key drivers
impacting (non-GAAP) operating results.
EFH
Corp.
Adjusted
EBITDA
(non-GAAP)
¹
Q2
²
09
vs.
Q2
10
and
YTD
³
09
vs.
YTD
10;
$
millions
Oncor
Q2 10
Q2 09
1,303
1,192
940
851
357
329
1,831
1,674
719
617
9%
11%
9%
10%
17%
9% |
 8
8
Luminant Operational Results
Nuclear-fueled generation; GWh
Coal-fueled generation; GWh
2,579
YTD 10
Nuclear production for Q2 impacted by refueling
outage and YTD by main transformer replacement
Q2 09
10,450
12,479
Sandow
5 & Oak Grove
Legacy coal-fueled plants
Q2 10 Results
Continued strong safety focus and
results
New coal-fueled units added 2.6 TWh
of generation in Q2 2010 (4.8 TWh
YTD) to the baseload
fleet
Nuclear production impacted by
refueling outage in April 2010
Generation from legacy coal-fueled
plants was lower due to higher
planned outages and higher
economic backdown
Coal-fueled fleet benefiting from new coal-fueled units
Q2 10
Q2 09
5,103
10,293
7%
YTD
YTD 09
YTD 10
9,539
4,527
4,802
20,705
25,297
Q2 10
YTD 09
11%
QTR
5%
QTR
1%
YTD
Variance does not include generation from Sandow 5 and Oak Grove 1 & 2.
1
¹
¹ |
  9
Q2 10 Results
Lower residential sales volumes
driven by lower customer counts
partially offset by slightly warmer
weather in Q2 10 compared to Q2
09
Business load growth attributable
to new customers and slightly
improved economy
Lower residential customer counts
reflect competitive activity in the
marketplace
TXU Energy Operational Results
Continued strong competitive activity
Volume increases due to weather and improved economy
Total residential customers
End of period, thousands
Retail electricity sales volumes by customer class;
GWh
1,849
1,830
1
SMB
–
small
business
2
LCI
-
large
commercial
and
industrial
3
Latest twelve months
YTD 09
SMB
¹
LCI
²
Residential
Q2 09
12,543
23,450
Q2 09
Q1 10
4%
LTM
³
7%
YTD
13,568
7,084
7,444
3,551
1,908
3,974
Q2 10
Q2 10
1,830
1,911
1%
QTR
12,964
6,857
3,629
6,848
3,925
1,993
24,986
12,766
Q2 10
YTD 10
2%
QTR |
 15,896
16,245
30,990
31,799
17,181
19,476
8,419
8,048
Oncor Operational Results
Electric energy volumes; GWh
Q2 10
Q2 09
Q2 10
Volume
increases
due
to
weather
and
improved
economy
Growth
below ERCOT estimated CAGR of 2.5% Q2 10 Results
Higher residential energy volumes
due to marginally warmer weather
in Q2 10 compared to Q2 09
Higher SMB and LCI
¹
energy
volumes due to a slightly improved
economy
Execution of AMS plan –
~240,000
advanced meters installed during
Q2 10; over 1.1 million installed
through July 2010
9 of 14 CREZ-related Certificates of
Convenience and Necessity (CCN)
approved by the Public Utility
Commission of Texas
1
SMB
–
small
business;
LCI
–
large
commercial
and
industrial
2
Latest twelve months
Residential
SMB & LCI
23,944
3,137
3,159
1%
LTM
²
Electricity
distribution points of delivery
End of period, thousands of meters
Q2 10
Q1 10
3,154
3,159
24,664
48,171
51,275
3%
QTR
6%
YTD
Q2 09
YTD 09
YTD 10
10
¹ |
 11
1
2
Cash and Equivalents
TCEH Letter of Credit Facility
TCEH Revolving Credit Facility
EFH Corp. Liquidity Management
2,700
735
1,880
1,250
821
429
1,211
Facility Limit
LOCs/Cash Borrowings
Availability
3,520
1,556
3,950
EFH Corp. and TCEH have sufficient liquidity to meet their anticipated short-term
needs, but will continue to monitor market conditions to ensure 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.
2
Facility availability includes $144 million of undrawn commitments from a
subsidiary of Lehman Brothers that has filed for bankruptcy. These funds are only available
from the fronting banks and the swingline lender, and exclude $85 million of
requested draws not funded by the Lehman subsidiary. EFH Corp. (excluding
Oncor) available liquidity As of 6/30/10; $ millions
•
Liquidity reflected in the table
does not include the unlimited
capacity available under the
Commodity Collateral Posting
Facility for ~490 million MMBtu
of natural gas hedges. |
 12
Current Maturity Profile
EFH Corp. debt maturities
(excluding Oncor), 2010-2020 and thereafter
As of 6/30/10; $ millions
1
Includes amortization of the $4.1 billion Delayed Draw Term Loan.
2
Excludes
borrowings
under
the
TCEH
Revolving
Credit
Facility
maturing
in
2013,
the
Deposit
Letter
of
Credit
maturing
in
2014
and
unamortized
discounts
and
premiums.
3
Does not include the public exchange offer launched on July 16, 2010, which expires
on August 12, 2010. 19,317
2,007
1,029
4,689
4,575
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020+
122
669
20,348
4,713
2,028
4,614
11
TCEH-Secured
EFH Corp
EFCH
TCEH-Revolver
TCEH-Unsecured
2,106
3,149
2
266
EFH Corp. continues to explore opportunities to improve the
enterprise’s maturity profile.
440
EFIH
July 2010 transactions :
EFH Corp. repurchased $28 million of EFH PIK Toggle Notes and $8
million of TCEH 10.25% Notes for $24 million
EFH Corp. exchanged $455 million of EFH 10% Senior Secured
Notes for $549 million of EFH 5.55% Series P Notes, $25 million of
EFH PIK Toggle Notes, $25 million of EFH 10.875% Notes and $13
million of TCEH 10.25% Notes
Q2
10
exchanges
-
$72
million
of
EFH 10% Senior Secured Notes
were exchanged for $102 million of
EFH and TCEH PIK Toggle Notes
$1.25 billion LOC Facility
expires in 2014
$2.70 billion Revolving Credit
Facility expires in 2013
Q2 10 exchanges and
repurchases
-
reduced
2015,
2016 and 2017 maturities by $168
million, $25 million and $200
million, respectively
251
305
¹
³
2 |
 Today’s Agenda
Q&A
Financial and Operational
Overview
Q2 2010 Review
John Young
President & CEO
13 |
 Today’s Agenda
Q&A
Financial and Operational
Overview
Q2 2010 Review
EFH Corp. Senior Executive Team
14 |
 15
Questions & Answers |
 16
Appendix –
Additional Slides and
Regulation G Reconciliations
Appendix |
 17
17
Luminant Solid-Fuel Development Program
Sandow Power Plant Unit 5
Rockdale, Texas
Oak Grove
Power Plant
Robertson County, Texas
Unit 1
Unit 2
Estimated net capacity
~800 MW
~800 MW
Primary fuel
Texas lignite
Texas lignite
Initial synchronization
August 2009
January 2010
Substantial completion date
December 2009
June 2010
Estimated net capacity
~580 MW
Primary fuel
Texas lignite
Initial synchronization
July 2009
Substantial
completion
date
September 2009
•
Both Sandow 5 and Oak Grove 1 lignite-fueled generating units achieved 70%
average capacity factors during the first quarter of 2010.
•
Luminant’s
construction of the Oak Grove 2 lignite-fueled generating unit reached
substantial completion on June 1, 2010
1
Substantial completion date is the contractual milestone when Luminant takes over
operations of the unit from the EPC contractor. ¹
¹ |
 18
18
TCEH Natural Gas Exposure
TCEH Natural Gas Position
10-14 ; million MMBtu
Hedges Backed by Asset First Lien
Open Position
1
As of 6/30/10. Balance of 2010 is from August 1, 2010 to December 31,
2010. Assumes conversion of electricity positions based on a ~8.0 heat rate with natural gas 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.
2010
position
includes
~4
million
MMBtu
of
short
gas
positions
associated
with
proprietary
trading
positions;
excluding
these
positions,
2010 position is ~102% hedged.
157
35
26
102
360
298
270
115
55
83
497
584
593
125
11
3
105
88
294
230
603
605
BAL 10
2011
2012
2013
2014
100% Hedge Level
Factor
Measure
BAL 10
2011
2012
2013
2014
Total or
Average
Natural gas hedging program
million
MMBtu
~114
~372
~475
~298
~105
~1,364
TXUE and Luminant
net positions
million
MMBtu
~125
~157
~35
~11
~3
~331
Overall estimated percent of total
NG position hedged
percent
~104%
~91%
~86%
~51%
~18%
~65%
TXUE and Luminant
Net Positions
Hedges Backed by CCP
1
²
TCEH has hedged approximately 65% of its estimated Henry Hub-based natural gas price exposure
from August 1, 2010 through December 31, 2014. More than 95% of the NG Hedges are supported
directly by a first lien or by the TCEH Commodity Collateral Posting Facility.
|
 19
1
3
1
19
Unrealized Mark-To-Market Impact Of Hedging
Unrealized mark-to-market impact of hedging program
6/30/10 vs. 3/31/10; mixed measures, pre-tax
Factor
Measure
2010
2011
2012
2013
2014
Total or
Avg.
3/31/10
Natural gas hedges
mm MMBtu
~181
~424
~487
~300
~99
~1,491
Wtd. avg. hedge price
$/MMBtu
~$7.71
~$7.56
~$7.36
~$7.19
~$7.80
Natural gas prices
$/MMBtu
~$4.27
~$5.34
~$5.79
~$6.07
~$6.36
Cum. MtM
gain at 3/31/10
$ billions
~$0.8
~$0.9
~$0.8
~$0.3
~$0.3
~$3.1
6/30/10
Natural gas hedges
mm MMBtu
~126
~372
~475
~298
~105
~1,376
Wtd. avg. hedge price
$/MMBtu
~$7.75
~$7.53
~$7.34
~$7.18
~$7.80
Natural gas prices
$/MMBtu
~$4.82
~$5.34
~$5.68
~$5.89
~$6.10
Cum. MtM
gain at 6/30/10
$ billions
~$0.5
~$0.9
~$0.8
~$0.4
~$0.3
~$2.9
Q2 10 MtM
gain
$ billions
~($0.3)
~$0
~$0
~$0.1
~$0
~($0.2)
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. 6/30/10 prices for 2010 represent July 1, 2010 through
December 31, 2010 values.
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. As of 6/30/10. 2010
represents July 1, 2010 through December 31, 2010 volumes. Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity
(i.e., delta position) of the derivatives. The notional volumes for collars are approximately
150 million MMBtu, which corresponds to a delta position of approximately 105 million MMBtu in
2014. 1
2
2
2
Reversals of prior unrealized gains for positions settled during the second quarter of 2010 more
than offset gains in the forward years of the hedge program, resulting in a ~$170 million
(~$110 million after tax) unrealized mark-to-market net loss in GAAP income for Q2 10.
|
 20
20
Unrealized Mark-To-Market Impact Of Hedging
Unrealized mark-to-market impact of hedging program
6/30/10 vs. 12/31/09; mixed measures, pre-tax
Factor
Measure
2010
2011
2012
2013
2014
Total or
Avg.
12/31/09
Natural gas hedges
mm MMBtu
~240
~447
~490
~300
~97
~1,574
Wtd. avg. hedge price
¹
$/MMBtu
~$7.79
~$7.56
~$7.36
~$7.19
~$7.80
Natural gas prices
$/MMBtu
~$5.79
~$6.34
~$6.53
~$6.67
~$6.84
Cum. MtM
gain at 12/31/09
²
$ billions
~$0.8
~$0.4
~$0.4
~$0.2
~$0.2
~$2.0
6/30/10
Natural gas hedges
³
mm MMBtu
~126
~372
~475
~298
~105
~1,376
Wtd. avg. hedge price
¹
$/MMBtu
~$7.75
~$7.53
~$7.34
~$7.18
~$7.80
Natural gas prices
$/MMBtu
~$4.82
~$5.34
~$5.68
~$5.89
~$6.10
Cum. MtM
gain at 6/30/10
²
$ billions
~$0.5
~$0.9
~$0.8
~$0.4
~$0.3
~$2.9
YTD MtM
gain
$ billions
~(0.3)
~$0.5
~$0.4
~$0.2
~$0.1
~$0.9
Decreases in natural gas prices during the first six months of 2010 resulted in a
~$890 million (~$570 million after tax) unrealized mark-to-market net
gain in GAAP income for YTD 10. 1
2
3
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. 6/30/10 prices for 2010 represent July 1, 2010 through
December 31, 2010 values.
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. As of 6/30/10. 2010
represents July 1, 2010 through December 31, 2010 volumes. Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity
(i.e., delta position) of the derivatives. The notional volumes for collars are approximately
150 million MMBtu, which corresponds to a delta position of approximately 105 million MMBtu in
2014. |
 21
21
21
EFH Corp. Adjusted EBITDA Sensitivities
Commodity
Percent Hedged at
June 30, 2010
Change
BOY 10E
Impact
$ millions
7X24 market heat rate (MMBtu/MWh)
~85
0.1 MMBtu/MWh
~3
NYMEX gas price ($/MMBtu)
~100
$1/MMBtu
~9
Texas gas vs. NYMEX Henry Hub price ($/MMBtu)
3,4
>95
$0.10/MMBtu
~0
Diesel ($/gallon)
5
~100
$1/gallon
~1
Base coal ($/ton)
6
~100
$5/ton
~2
Generation operations
Baseload
generation (TWh)
n.a.
1 TWh
~25
Retail operations
Balance of 2010
Residential contribution margin ($/MWh)
14 TWh
$1/MWh
~14
Residential consumption
14 TWh
1%
~5
Business markets consumption
13 TWh
1%
~2
Impact on EFH Corp. Adjusted EBITDA
10E; mixed measures
The majority of 2010 commodity-related risks are significantly mitigated.
2010 estimate based on commodity positions as of 6/30/10, net of long-term hedges and
wholesale/retail effects, excludes gains and losses incurred prior to June 30, 2010. See
Appendix for definition. Simplified representation of heat rate position in a single TWh position. In reality, heat rate
impacts are differentiated across plants and respective pricing periods: baseload (linked
primarily to changes in North Zone 7x24), natural gas plants (primarily North Zone 5x16) and wind (primarily West Zone 7x8).
Assumes conversion of electricity positions based on a ~8.0 market heat rate with natural gas 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). 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.
Includes positions related to fuel surcharge on rail transportation.
Excludes fuel surcharge on rail
transportation.
1
2
3
4
5
6
3
2
1 |
 22
22
22
Commodity Prices
$7.75
$7.78
$7.51
$8.11
$/MMBtu
TCEH weighted avg. hedge price
4
Commodity
Units
Q2 09 Actual
Q2 10 Actual
YTD 10 Actual
BOY 10E
NYMEX gas price
$/MMBtu
$3.69
$4.30
$4.72
$4.82
HSC gas price
$/MMBtu
$3.57
$4.25
$4.67
$4.66
7x24 market heat rate (HSC)
MMBtu/MWh
8.08
8.17
7.93
8.16
North Zone 7x24 power price
$/MWh
$28.82
$34.85
$37.02
$37.99
Gulf Coast ultra-low sulfur diesel
$/gallon
$1.57
$2.14
$2.10
$2.09
PRB 8400 coal
$/ton
$7.61
$9.59
$8.84
$9.69
LIBOR interest rate
5
percent
1.39%
0.63%
0.51%
0.75%
Commodity prices
Q2 09, Q2 10, YTD 10 and BOY 10E; mixed measures
1
BOY
10
estimate
based
on
commodity
prices
as
of
6/30/10
for
July
1,
2010
through
December
31,
2010
2
Based on NYMEX forward curve
3
Based on market clearing price for power
4
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). 5
The index for the settled value is a 6 month LIBOR rate.
3
2
1 |
 23
Financial Definitions
Refers to the results of Oncor and the Oncor ring-fenced entities.
Regulated Business
Results
Refers to the combined results of the Competitive Electric segment and Corporate
& Other. Competitive Business
Results
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.
Contribution Margin (non-
GAAP)
Net income (loss) from continuing operations before interest expense and related
charges, and income tax expense (benefit) plus depreciation and
amortization. EBITDA
(non-GAAP)
Generally accepted accounting principles.
GAAP
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. Purchase Accounting
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 earnings 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 (non-GAAP)
Operating Results
EBITDA adjusted to exclude interest income, noncash items, unusual items, interest
income, income from discontinued operations and other adjustments allowable
under the EFH Corp. senior and senior secured notes indentures. Adjusted
EBITDA plays an important role in respect of certain covenants contained in these
indentures. 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.
Adjusted EBITDA
(non-GAAP)
Definition
Measure |
 24
Table 1: EFH Corp. Adjusted EBITDA Reconciliation
Three and Six Months Ended June 30, 2009 and 2010
$ millions
-
(5)
145
-
(59)
-
(129)
2
-
58
27
-
57
-
809
350
1,122
(237)
(426)
Q2 10
3
-
320
1
-
16
-
1
-
83
24
(11)
51
(338)
651
423
431
(48)
(155)
Q2 09
(122)
-
Equity in earnings of unconsolidated subsidiary
(11)
-
Amortization of ”day one”
net loss on Sandow 5 power purchase agreement
(143)
-
Net gain on debt exchange offers
-
28
Net income attributable to noncontrolling interests
-
2
EBITDA amount attributable to consolidated unrestricted subsidiaries
(848)
(710)
Unrealized net (gain) loss resulting from hedging transactions
7
2
90
180
48
(12)
75
(636)
2,498
830
1,096
285
287
YTD 09
-
Losses on sale of receivables
-
Impairment of goodwill
²
2
Impairment of assets and inventory write-down
114
Purchase accounting adjustments
¹
(9)
Interest income
64
Amortization of nuclear fuel
Adjustments to EBITDA (pre-tax):
-
Oncor EBITDA
87
Oncor distributions/dividends
2,074
Interest expense and related charges
2,660
692
(35)
(71)
YTD 10
Net income (loss) attributable to EFH Corp.
Income tax expense (benefit)
Depreciation and amortization
EBITDA
Factor
Note: Table and footnotes to this table continue on following page
|
 25
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 not recognized in net income due to purchase
accounting.
2
Reflects the completion in the first quarter of 2009 of the fair
value calculation supporting the goodwill impairment charge that was recorded in
the fourth quarter of 2008.
3
Accounted for under accounting standards related to stock compensation and excludes
capitalized amounts. 4
Includes amounts incurred related to outsourcing, restructuring and other amounts
deemed to be in excess of normal recurring amounts. 5
Includes professional fees primarily for retail billing and customer care systems
enhancements and certain incentive compensation. 6
Includes costs related to the Merger and abandoned strategic transactions,
outsourcing transition costs, administrative costs related to the cancelled program to
develop coal-fueled facilities, the Sponsor Group management fee, costs related
to certain growth initiatives and costs related to the Oncor sale of noncontrolling
interests.
7
Reflects noncapital outage costs.
1,303
300
1,003
77
6
11
-
-
4
Q2 10
1,192
279
913
66
6
25
8
1
6
Q2 09
2,566
632
1,934
100
-
24
-
3
13
YTD 10
2,307
542
1,765
100
12
42
19
8
12
YTD 09
Severance expense
4
Noncash compensation expense³
EFH Corp. Adjusted EBITDA per Incurrence Covenant
EFH Corp. Adjusted EBITDA per Restricted Payments Covenant
Expenses incurred to upgrade or expand a generation station
7
Add back Oncor adjustments
Transaction and merger expenses
6
Transition and business optimization costs
5
Restructuring and other
Factor
Table 1: EFH Adjusted EBITDA Reconciliation (continued from previous page)
Three and Six Months Ended June 30, 2009 and 2010
$ millions |
 26
Table 2: TCEH Adjusted EBITDA Reconciliation
Three and Six Months Ended June 30, 2009 and 2010
$ millions
1
-
1
-
Impairment of assets and inventory writedown
10
1
-
3
-
3
(5)
145
-
-
47
27
(21)
641
344
915
(212)
(406)
Q2 10
1
8
1
2
3
-
-
320
-
-
71
24
(12)
362
283
164
(26)
(59)
Q2 09
2
19
Transition and business optimization costs
3
8
Severance expense
2
4
7
-
-
(710)
2
70
157
48
(19)
1,979
559
562
341
517
YTD 09
5
Corp. depreciation, interest and income tax expense included in SG&A
-
Losses on sale of receivables
(11)
Amortization of ”day one”
net loss on Sandow 5 power purchase agreement
21
Transaction and merger expenses
10
Noncash compensation expense
-
Impairment
of
goodwill
-
EBITDA amount attributable to consolidated unrestricted subsidiaries
91
Purchase
accounting
adjustments
(42)
Interest income
64
Amortization of nuclear fuel
(848)
Unrealized net (gain) loss resulting from hedging transactions
Adjustments to EBITDA (pre-tax):
1,664
Interest expense and related charges
2,434
681
46
43
YTD 10
Net income (loss)
Income tax expense (benefit)
Depreciation and amortization
EBITDA
Factor
Note: Table and footnotes to this table continue on following page
1
2
3
4
5
6 |
 27
Table 2: TCEH Adjusted EBITDA Reconciliation (continued from previous page)
Three and Six Months Ended June 30, 2009 and 2010
$ millions
976
4
32
940
77
11
Q2 10
873
7
15
851
66
5
Q2 09
1
7
Restructuring and other
1,734
12
48
1,674
100
YTD 09
9
Other adjustments allowed to determine Adjusted EBITDA per Maintenance
Covenant
8
1,831
TCEH Adjusted EBITDA per Incurrence Covenant
1,931
TCEH Adjusted EBITDA per Maintenance Covenant
100
Expenses incurred to upgrade or expand a generation station
7
91
Expenses related to unplanned generation station outages
7
YTD 10
Factor
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 not recognized in net income due to
purchase accounting.
2
Reflects the completion in the first quarter of 2009 of the fair
value calculation supporting the goodwill impairment charge that was recorded in
the fourth quarter of 2008.
3
Excludes capitalized amounts.
4
Includes amounts incurred related to outsourcing, restructuring and other amounts
deemed to be in excess of normal recurring amounts. 5
Includes professional fees primarily for retail billing and customer care systems
enhancements and certain incentive compensation. 6
Includes costs related to the Merger, outsourcing transition costs and costs
related to certain growth initiatives. 7
Reflects noncapital outage costs.
8
Primarily pre-operating expenses related to Oak Grove and Sandow 5 generation
facilities. |
 28
1
1
Purchase accounting adjustments consist of amounts related to the accretion of an
adjustment (discount) to regulatory assets resulting from purchase accounting.
Table 3: Oncor Adjusted EBITDA Reconciliation
Three and Six Months Ended June 30, 2009 and 2010
$ millions
357
2
(9)
(9)
373
164
86
47
76
Q2 10
329
-
(10)
(10)
349
132
87
48
82
Q2 09
(19)
(19)
Interest income
617
2
(20)
654
258
171
85
140
YTD 09
(18)
Purchase accounting adjustments
752
EBITDA
719
Oncor Adjusted EBITDA
4
Restructuring and other
170
Interest expense and related charges
331
96
155
YTD 10
Net income
Income tax expense
Depreciation and amortization
Factor |