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. Q1 2011 Investor Call
April 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 unforeseen 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
Q1 2011 Review
Paul Keglevic
Executive Vice President & CFO |
 Consolidated: reconciliation of GAAP net income to adjusted (non-GAAP) operating
results Q1 10 vs. Q1 11 ; $ millions, after tax
1
Q1 10 reflects $9 million of debt extinguishment gains offset by an $8 million
deferred income tax charge recorded as a result of health care legislation passed in 2010 by the U.S. Congress.
EFH Corp.
Adjusted (Non-GAAP) Operating Results
3
Factor
Q1 10
Q1 11
Change
EFH Corp. GAAP net income (loss)
355
(362)
(717)
Items
excluded
from
adjusted
(non-GAAP)
operating
results
(after
tax)
-
noncash:
Unrealized commodity-related mark-to-market net (gains) losses
(639)
203
842
Unrealized mark-to-market net (gains) losses on interest rate swaps
70
(92)
(162)
Gain related to counterparty bankruptcy settlement
-
(14)
(14)
Other (noncash)
1
(1)
-
1
EFH Corp. adjusted (non-GAAP) operating loss
(215)
(265)
(50) |
 Description/Drivers
Better (Worse)
Than
Q1 10
Competitive business¹:
Lower net margin from commodity hedge prices, asset management and retail activities
(46)
Impact of winter weather event
(17)
Lower retail consumption primarily due to milder weather
(13)
(12)
Net lower production from legacy baseload generation units
(6)
Impact of new lignite-fueled generation units
18
Lower amortization of intangibles arising from purchase accounting
6
Contribution margin
(70)
Higher depreciation reflecting the placement in service of new lignite-fueled
generation units and ongoing investment in the existing generation fleet
(17)
Higher operating costs reflecting new lignite-fueled generation units
(6)
Lower net interest expense driven by liability management program
35
Lower retail bad debt expense
14
Lower accrued interest on uncertain income tax positions (included in income tax
expense) 8
All
other
-
net
(1)
Total
change
-
Competitive
business
(37)
Regulated business:
Lower consumption primarily due to milder weather
(10)
Higher depreciation reflecting infrastructure investment
(7)
Higher operating costs
(6)
Higher revenues from transmission rate and distribution tariff increases and growth
in points of delivery 13
All
other
-
net
(3)
(13)
Total change in EFH Corp. adjusted (non-GAAP) operating results
(50)
Consolidated key drivers of the change in (non-GAAP) operating results
Q1 10 vs. Q1 11; $ 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
Higher fuel costs at legacy baseload units due to increased coal transportation expenses and higher
uranium and conversion costs Total
change - Regulated business (~80% owned by EFH Corp.) |
 EFH
Corp. Adjusted EBITDA (Non-GAAP) 1
See
Appendix
for
Regulation
G
reconciliations
and
definition.
Includes
$10
million
and
$10million
in
Q1
10
and
Q1
11,
respectively,
of
Corp.
&
Other
Adjusted
EBITDA.
EFH
Corp.
Adjusted
EBITDA
(non-GAAP)
1
Q1
10 vs. Q1 11;
$ millions
Q1 11
Q1 10
1,166
1,263
805
891
351
362
TCEH
Oncor
5
8%
10%
3%
Q1 performance was largely driven by the same key drivers impacting adjusted (non-GAAP)
operating results.
|
 6
Luminant Operational Results
6
Nuclear-fueled generation; GWh
Coal-fueled generation; GWh
3,591
Q1 10
12,818
13,966
Sandow 5 & Oak Grove
Legacy coal-fueled plants
Q1 11
Q1 10
5,013
5,206
Q1 11
2%
1
Q1
2011
Nuclear
Plant
Results
Solid safety performance
Higher generation due to improved
reliability
Top decile industry performance for
reliability and cost
4%
2,223
Q1
2011
Coal-Fueled
Plant
Results
New plants collectively operated at ~75%
capacity factor
Lower legacy coal-fueled generation due
to increased economic backdown
partially offset by improved performance
Top quartile industry performance
10,595
10,375
1
Variance
does
not
include
generation
from
Sandow
5
and
Oak
Grove
1
&
2. |
  TXU
Energy Operational Results 7
Total residential customers
End of period, thousands
Retail electricity sales volumes by customer class;
GWh
1,771
1,739
1
SMB
–
small
business
2
LCI -
large commercial and industrial
3
Latest twelve months
SMB
1
LCI
2
Residential
Q1 10
12,220
Q1 10
Q4 10
6%
LTM
5,944
3,519
1,982
Q1 11
Q1 11
1,739
1,849
2%
QTR
6,719
3,259
1,766
10,969
Q1 11
Q1 2011 Results
Lower residential sales volumes
driven by lower customer counts and
milder weather
Customer counts and volumes reflect
competitive intensity and TXU Energy
focus on brand proposition and
margin discipline
Launch of Texas-based call center
locations and enhanced customer
experience utilizing online tools
10%
3 |
 8
15,555
16,500
10,217
11,057
Oncor Operational Results
Electric
energy
billed
volumes
3
;
GWh
Q1 11
Q1 10
Q1 11
1
AMS –
Advanced Metering System
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
SMB
–
small
business;
LCI
–
large
commercial
and
industrial
5
Latest twelve months
Residential
SMB & LCI
4
26,612
3,154
3,181
1%
LTM
5
Electricity distribution points of delivery
End of period, thousands of meters
Q1 11
Q4 10
3,171
3,181
26,717
Q1 10
Q1 2011 Results
Lower residential volumes principally due
to milder winter weather in Q1 11
compared to Q1 10
Higher SMB & LCI energy volumes due to
improved economy
Execution
of
AMS
1
plan
–
~121,000
advanced meters installed during Q1
11; over 1.6 million installed through
March 31, 2011
All 14 Certificates of Convenience and
Necessity (CCNs) approved by the
Public Utility Commission of Texas
(PUCT)
for
CREZ
2
transmission
projects
6%
8% |
 2,700
1,680
903
1,250
248
1,002
1,330
Facility Limit
LOCs/Cash Borrowings
Availability
EFH Corp. Liquidity Management
As of March 31, 2011
9
Cash and Equivalents
TCEH
Letter
of
Credit
Facility
1
TCEH
Revolving
Credit
Facility
2
1,905
3,950
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 $112 million of undrawn commitments from a
subsidiary of Lehman Brothers that is in bankruptcy. These funds are only available from the
fronting
banks
and
the
swingline
lender,
and
exclude
$117
million
of
requested
draws
not
funded
by
the
Lehman
subsidiary.
EFH Corp. (excluding Oncor) available liquidity
As of 3/31/11; $ millions
3,258
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. |
 657
1,397
2,054
914
336
1,250
955
Facility Limit
LOCs/Cash Borrowings
Availability
EFH Corp. Liquidity Management
As of April 19, 2011
10
Cash and Equivalents
TCEH
Letter
of
Credit
Facility
1
TCEH Revolving Credit Facility
1,571
3,304
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 4/19/11; $ millions
2,688
The decline in liquidity is largely driven by the fees for the amend and extend transaction which will
be largely offset by the prepayment of the TCEH term loan amortization for 2011 - 2014.
|
 11
11
11
Commodity Prices
Commodity
Units
Q1 11 Actual
Q1 10 Actual
BOY 11E¹
NYMEX gas price
$/MMBtu
$4.16
$5.15
$4.57
HSC gas price
$/MMBtu
$4.11
$5.09
$4.51
7x24 market heat rate (HSC)
3,6
MMBtu/MWh
9.36
7.70
8.51
North Hub 7x24 power price
6
$/MWh
$39.11
$39.22
$38.31
TCEH weighted avg. hedge price
4
$/MMBtu
$7.94
$8.06
$7.45
Gulf Coast ultra-low sulfur diesel
$/gallon
$2.82
$2.06
$3.18
PRB 8400 coal
$/ton
$11.46
$8.08
$11.06
LIBOR interest rate
5
percent
0.46%
0.40%
0.61%
Commodity prices
Q1 11, Q1 10 and BOY 11E; mixed measures
1
BOY 11 estimate based on commodity prices as of 03/31/11 for April 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
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.
6
Excluding
the
volatile
pricing
that
occurred
in
early
February
2011
(2
&
3
),
North
Hub
7X24
power
prices
averaged
approximately
$30.20/MWh
and
the
7X24
market
heat
rate
averaged 7.35 MMBtu/MWh during Q1 10.
2
nd
rd |
 12
12
Unrealized Mark-To-Market Impact Of Hedging
Unrealized mark-to-market impact of hedging program
03/31/11 vs. 12/31/10; mixed measures, pre-tax
Factor
Measure
2011
2012
2013
2014
2015
Total or
Avg.
12/31/10
Natural gas hedges
mm MMBtu
~220
~398
~282
~149
0
~1,050
Wtd. avg. hedge price
$/MMBtu
~$7.56
~$7.36
~$7.19
~$7.80
N/A
Natural gas prices
$/MMBtu
~$4.55
~$5.08
~$5.33
~$5.49
~$5.64
Cum. MtM
gain at 12/31/10
2
$ billions
~$1.2
~$1.1
~$0.5
~$0.4
N/A
~$3.2
03/31/11
Natural gas hedges
3
mm MMBtu
~150
~398
~274
~149
0
~971
Wtd. avg. hedge price
1
$/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 03/31/11
2
$ billions
~$0.8
~$1.1
~$0.5
~$0.4
N/A
~$2.8
Q1 11 MtM
(loss) gain
$ billions
~$(0.4)
~$0
~$0
~$0
N/A
~$(0.4)
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. 3/31/11 prices for 2011 represent April 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 rebalancing) and natural gas basis deals. 3
As of 3/31/11, 2011 represents April 1, 2011 through December 31, 2011 volumes. Where
collars are reflected, the volumes are estimated based on the notional position of the derivatives
that provide downside price protection. The notional volumes for collars are approximately 150
million MMBtu, which corresponds to a delta position of approximately 110 million MMBtu in
2014. TCEH has hedged approximately 48% of its estimated Henry Hub-based natural gas
price exposure from May 1, 2011 through December 31, 2015. More than 95% of the NG
Hedges are supported directly by a first lien or by the TCEH Commodity Collateral Posting
Facility. |
 223
131
35
8
0
127
108
290
274
149
10
70
305
445
610
360
599
614
602
610
BAL 11
2012
2013
2014
2015
13
13
TCEH Natural Gas Exposure
TCEH Natural Gas Position
11-14
1
; million MMBtu
Hedges Backed by Asset First Lien
Open Position
1
As
of
03/31/11.
Balance
of
2011
is
from
May
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 ~8
million MMBtu of short gas positions associated with proprietary trading positions; excluding these positions,
2011 position is ~95% hedged.
100% Hedge Level
Factor
Measure
BAL 11
2012
2013
2014
2015
Total or
Average
Natural gas hedging program
million
MMBtu
~127
~398
~274
~149
~0
~948
TXUE and Luminant net
positions
million
MMBtu
~223
~131
~35
~8
~2
~399
Overall estimated percent of
total NG position hedged
percent
~97%
~88%
~50%
~26%
~0%
~48%
TXUE and Luminant Net Positions
2
Hedges Backed by CCP
TCEH has hedged approximately 48% of its estimated Henry Hub-based natural gas price
exposure from May 1, 2011 through December 31, 2015. More than 95% of the NG Hedges are
supported directly by a first lien or by the TCEH Commodity Collateral Posting Facility. |
 14
14
14
EFH Corp. Adjusted EBITDA Sensitivities
Commodity
Percent Hedged at
March 31, 2011
Change
BOY 11E
Impact
$ millions
7X24 market heat rate (MMBtu/MWh)
2
>85
0.1 MMBtu/MWh
~4
NYMEX gas price ($/MMBtu)
3
>95
$1/MMBtu
~10
Texas gas vs. NYMEX Henry Hub price ($/MMBtu)
3,4
~95
$0.10/MMBtu
~2
Diesel ($/gallon)
5
>95
$1/gallon
~1
Base coal ($/ton)
6
>95
$2/ton
~1
Generation operations
Baseload generation (TWh)
n.a.
1 TWh
~15
Retail operations
FY 2011
Residential contribution margin ($/MWh)
20 TWh
$1/MWh
~20
Residential consumption
20 TWh
1%
~6
Business markets consumption
16 TWh
1%
~2
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 03/31/11, net of long-term
hedges and wholesale/retail effects, excludes gains and losses incurred prior to March 31, 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: baseload (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 |
 2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021+
Current EFH Maturity Profile
As of March 31, 2011
EFH Corp. debt maturities¹
(excluding Oncor), 2011-2021 and thereafter
As of 3/31/11; $ millions
1,209
19,313
11
4,104
267
3,165
1,406
935
3,250
1,067
2,180
1,029
1,494
1,571
15
251
903
3,189
1,428
975
19,800
2
594
1
Includes amortization of the $16.5 billion Initial Term Loan, $4.1 billion Delayed
Draw Term Loan and excludes unamortized discounts and premiums. 2
Excludes the Deposit Letter of Credit Facility maturing in 2014.
TCEH-1 Lien
EFH Corp
EFCH
TCEH-LBO
EFIH 1 Lien
TCEH-Revolver
TCEH-Other/PCRBs
TCEH-2 Lien
$1,250 million LOC Facility
expires in 2014
$2,700 million Revolving Credit
Facility expires in 2013
st
nd
st |
 EFH Maturity
Profile March 31, 2011 Pro Forma for Recent Transactions
EFH Corp. debt maturities¹
(excluding Oncor), 2011-2021 and thereafter
As of 3/31/11; $ millions (Pro Forma for Recent Transactions²)
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021+
4,267³
3,165
11
4,510
5,000
2,180
1,750
1,067
1,029
1,494
1,571
15,035
46
1,406
1,759
267
3,815
3,343
181
440
1
Includes amortization of the $15.4 billion Term Loan/DDTL facility beginning in Q4 2014 and excludes
unamortized discounts and premiums. 2
Includes
transactions
closed
through
4/25/11
:
(1)
TCEH
amendment
and
extension
of
a
portion
of
the
1
Lien
Secured
Credit
Facilities,
and
(2)
private
exchanges
of
EFIH
2
Lien Notes for EFH Cash Pay, PIK Toggle and 2014 Legacy Notes.
3
Excludes the Deposit Letter of Credit Facility maturing in 2014 and 2017.
543
15,617³
406
TCEH-1
Lien
EFH Corp
EFCH
TCEH-LBO
EFIH 1
Lien
TCEH-Revolver
TCEH-Other/PCRBs
TCEH-2
Lien
EFIH 2
Lien
April 2011 Amend & Extend Transaction:
•
of
$1,020
million
of
TCEH
Deposit
Letter
of
Credit Loans extended from October 2014 to October 2017
($42 million remains due in 2014)
•Maturity
of
$1,414
million
of
the
capacity
under
the
TCEH
Revolving Credit Facility extended from October 2013 to
October 2016 ($640 million remains due in October 2013)
April 2011 TCEH 1
Lien Issuance:
•
issued
$1,750
million
of
11.50%
Sr.
Secured
1
Lien
Notes due 2020, and used the majority of the proceeds to:
–
Repay $770 million of borrowings under the TCEH
Term Loan (inc. $51 million of March 31, 2011
amortization payment);
–
Repay $188 million of TCEH Deposit Letter of Credit
Loans;
–
Repay $646 million of borrowings under the TCEH
Revolving Credit Facility (with corresponding
commitment reduction)
April 2011 EFIH 2
Lien Issuance:
•
issued
$406
million
of
11.00%
Sr. Secured 2
Lien Notes due 2021 in
exchange for $163 million of EFH Cash Pay
Notes, $229 million of EFH Toggle Notes and
$36 million of EFH 5.55% Series P Senior
Notes
16
st
st
nd
nd
nd
nd
st
st
nd
st
Maturity
TCEH
EFIH |
 17
Today’s Agenda
John Young
President & CEO
Financial and Operational
Overview
Q1 2011 Review
Q&A |
 18
Today’s Agenda
EFH Corp. Senior Executive Team
Financial and Operational
Overview
Q1 2011 Review
Q&A |
 19
Questions & Answers |
 20
Appendix –
Additional Slides and
Regulation G Reconciliations
Appendix |
 21
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
Oak Grove 1
800
Oak Grove 2
800
Sandow 4
557
Sandow 5
580
Martin Lake 1
750
Martin Lake 2
750
Martin Lake 3
750
Monticello 1
565
Monticello 2
565
Monticello 3
750
Big Brown 1
575
Big Brown 2
575
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.
2
3 |
 22
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.
|
 23
Table 1: EFH Corp. Adjusted EBITDA Reconciliation
Three Months Ended March 31, 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 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 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
Q1 10
Q1 11
Net income (loss) attributable to EFH Corp.
355
(362)
Income tax (benefit) expense
203
(215)
Interest expense and related charges
954
643
Depreciation and amortization
342
369
EBITDA
1,854
435
Adjustments to EBITDA (pre-tax):
Oncor distributions/dividends
30
16
Interest income
(10)
(2)
Amortization of nuclear fuel
37
37
Purchase accounting adjustments
56
50
Impairment of assets and inventory write-down
1
-
Net gain on debt exchange offers
(14)
-
Equity in earnings of unconsolidated subsidiary
(63)
(50)
Unrealized net (gain) loss resulting from hedging transactions
(993)
316
Amortization
of
”day
one”
net
loss
on
Sandow
5
power
purchase
agreement
(5)
-
Noncash compensation expense
9
-
Severance expense
3
3
Transition
and
business
optimization
costs
4
-
5
Transaction
and
merger
expenses
5
13
9
Restructuring
and
other
6
(10)
(25)
Expenses
incurred
to
upgrade
or
expand
a
generation
station
7
23
36
EFH Corp. Adjusted EBITDA per Incurrence Covenant
931
830
Add back Oncor adjustments
332
336
EFH Corp. Adjusted EBITDA per Restricted Payments Covenant
1,263
1,166
1
2
3 |
 1
24
Table 2: TCEH Adjusted EBITDA Reconciliation
Three Months Ended March 31, 2010 and 2011
$ millions
Factor
Q1 10
Q1 11
Net income (loss)
450
(301)
Income tax expense (benefit)
258
(155)
Interest expense and related charges
749
498
Depreciation and amortization
337
362
EBITDA
1,794
404
Adjustments to EBITDA (pre-tax):
Interest income
(22)
(27)
Amortization of nuclear fuel
37
37
Purchase
accounting
adjustments
44
38
EBITDA amount attributable to consolidated unrestricted subsidiaries
-
(2)
Unrealized net (gain) loss resulting from hedging transactions
(993)
316
Amortization
of
”day
one”
net
loss
on
Sandow
5
power
purchase
agreement
(5)
-
Corp. depreciation, interest and income tax expense included in SG&A
2
3
Noncash
compensation
expense
7
-
Severance expense
3
-
Transition
and
business
optimization
costs
1
6
Transaction
and
merger
expenses
4
11
11
Restructuring and other
5
(11)
(17)
Expenses
incurred
to
upgrade
or
expand
a
generation
station
6
23
36
TCEH Adjusted EBITDA per Incurrence Covenant
891
805
Expenses related to unplanned generation station outages
59
58
Other
adjustments
allowed
to
determine
Adjusted
EBITDA
per
Maintenance
Covenant
7
3
8
TCEH Adjusted EBITDA per Maintenance Covenant
953
871
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
Impairment of assets includes impairment of land.
3
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, the Sponsor Group management fee,
outsourcing transition costs and costs related to certain growth initiatives.
6
Includes
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.
8
Primarily pre-operating expenses related to Oak Grove and Sandow 5 generation
facilities. 3
2 |
 25
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 March 31, 2010 and 2011
$ millions
Factor
Q1 10
Q1 11
Net income
79
65
Income tax expense
48
40
Interest expense and related charges
86
90
Depreciation and amortization
166
172
EBITDA
379
367
Interest income
(10)
(10)
Purchase accounting adjustments
1
(9)
(8)
Transition and business optimization costs and other
2
2
Oncor Adjusted EBITDA
362
351 |