Attached files
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| EX-99.1 - EX-99.1 - Energy Future Holdings Corp /TX/ | d576868dex991.htm |
| 8-K - 8-K - Energy Future Holdings Corp /TX/ | d576868d8k.htm |
 EFH
Corp. Q2 2013 Investor Call
August 2, 2013
Exhibit 99.2 |
 1
Safe Harbor Statement
Forward Looking Statements
This presentation contains forward-looking statements, which are subject to
various risks and uncertainties. A discussion of risks and uncertainties that could
cause actual results to differ materially from management's current projections,
forecasts, estimates and expectations is contained in EFH Corp.'s filings with the
Securities and Exchange Commission (SEC). In addition to the risks and
uncertainties set forth in EFH Corp.'s SEC filings, the forward-looking statements
in this presentation regarding the company’s natural gas hedging program could
be affected by, among other things: changes in the ERCOT electricity market,
including a regulatory or legislative change, that results in wholesale electricity
prices not generally moving with natural gas prices; any decrease in market heat
rates as the program generally does not mitigate exposure to changes in market
heat rates; the unwillingness or failure of any hedge counterparty to perform their
respective obligations; or any other event that results in the inability to continue to
use a first lien on TCEH’s assets to secure a substantial portion of the hedges
under the program.
Regulation G
This presentation includes certain non-GAAP financial measures. A reconciliation of
these measures to the most directly comparable GAAP measures is included in the
appendix to this presentation. |
 2
Today’s Agenda
Q&A
Financial and Operational
Overview
Q2 2013 Review
Paul Keglevic
Executive Vice President & CFO |
 Consolidated: Reconciliation of GAAP net loss to adjusted (non-GAAP) operating
results Q2
12 vs. Q2 13; $ millions, after tax
Three months ended June 30.
EFH Corp.
Adjusted
(Non-GAAP)
Operating
Results
-
QTR
3
Factor
Q2 12
Q2 13
Change
EFH Corp. GAAP net loss
(696)
(71)
625
Items
excluded
from
adjusted
(non-GAAP)
operating
results
(after
tax)
-
noncash:
Unrealized commodity-related mark-to-market net loss
395
27
(368)
Unrealized mark-to-market net (gain) loss on interest rate swaps
68
(220)
(288)
Effect
of
favorable
resolution
of
income
tax
positions
-
Competitive
Business
-
(183)
(183)
Effect
of
favorable
resolution
of
income
tax
positions
-
Oncor
-
(3)
(3)
EFH Corp. adjusted (non-GAAP) operating loss
(233)
(450)
(217)
1
1 |
 Consolidated: Key drivers of the change in adjusted (non-GAAP) operating
results Q2 12 vs. Q2 13; $ millions, after tax
EFH Corp.
Adjusted
(Non-GAAP)
Operating
Results
Key
Drivers
-
QTR
Better (Worse)
Than
Q2 12
Competitive Business :
Lower net margin from asset management and retail activities driven by lower natural gas hedge
volumes and prices (159)
Lower generation volumes reflecting nuclear refueling outage, partially offset by fewer
planned and unplanned outages at coal-fueled plants (5)
Lower coal and nuclear fuel costs reflecting lower prices
3
Lower amortization of intangibles arising from purchase accounting
3
Contribution margin
(158)
Higher operating costs driven by higher maintenance expense associated with nuclear unit
planned outage (24)
Higher net interest expense driven by higher average borrowings
(16)
Higher professional services fees for liability management program
(15)
Lower accrued interest on income tax positions
3
All
other -
net
5
Total
change -
Competitive Business
(205)
Regulated Business:
Lower average consumption driven by milder weather
(9)
Lower interest income driven by settlement of interest reimbursement agreement
(6)
Higher depreciation and amortization reflecting infrastructure investment
(5)
Higher revenues reflecting transmission rate increases
5
Higher revenues from growth in points of delivery
3
Change in Regulated Business (~80% owned by EFH Corp.)
(12)
Total change in EFH Corp. adjusted (non-GAAP) operating results
(217)
Competitive
Business
consists
of
Competitive Electric segment and Corp. & Other.
4
1
1 |
 Consolidated: Reconciliation of GAAP net loss to adjusted (non-GAAP) operating
results YTD 12 vs. YTD 13; $ millions, after tax
Six months ended June 30.
EFH Corp.
Adjusted
(Non-GAAP)
Operating
Results
-
YTD
5
Factor
YTD 12
YTD 13
Change
EFH Corp. GAAP net loss
(1,000)
(640)
360
Items
excluded
from
adjusted
(non-GAAP)
operating
results
(after
tax)
-
noncash:
Unrealized commodity-related mark-to-market net loss
493
341
(152)
Unrealized mark-to-market net gain on interest rate swaps
(6)
(318)
(312)
Effect
of
favorable
resolution
of
income
tax
positions
-
Competitive
Business
-
(267)
(267)
Effect
of
favorable
resolution
of
income
tax
positions
-
Oncor
-
(11)
(11)
EFH Corp. adjusted (non-GAAP) operating loss
(513)
(895)
(382)
1
1 |
 Consolidated: Key drivers of the change in adjusted (non-GAAP) operating
results YTD 12 vs. YTD 13; $ millions, after tax
EFH Corp.
Adjusted
(Non-GAAP)
Operating
Results
Key
Drivers
(after
tax)
-
YTD
6
1
Competitive business consists of Competitive Electric segment and Corp. &
Other. Description / Drivers
Better
(Worse)
Than
YTD 12
Competitive Business¹:
Lower net margin from asset management and retail activities driven by lower natural
gas hedge volumes and prices (299)
Higher generation volumes reflecting fewer unplanned outage days at coal plants,
partially offset by nuclear refueling outage
8
Lower amortization of intangibles arising from purchase accounting
6
All other –
net
(2)
Contribution margin
(287)
Higher operating costs driven by higher maintenance expense associated with outages
at nuclear and coal generating units (39)
Higher net interest expense driven by higher average borrowings
(38)
Higher professional services fees for liability management program
(23)
Lower accrued interest on income tax positions
12
All other –
net
4
Total change -
Competitive Business
(371)
Regulated Business:
Higher depreciation and amortization reflecting infrastructure investment
(13)
Lower interest income driven by settlement of interest reimbursement agreement
(10)
Lower average consumption driven by milder weather
(6)
Higher revenues reflecting transmission rate increases
9
Higher revenues from growth in points of delivery
5
All other –
net
4
Total change -
Regulated Business (~80% owned by EFH Corp.)
(11)
Total change in EFH Corp. adjusted (non-GAAP) operating results
(382) |
 EFH
Corp. Adjusted EBITDA (Non-GAAP) EFH Corp. Adjusted EBITDA
(non-GAAP) Q2
12
vs.
Q2
13
and
YTD
12
vs.
YTD
13;
$
millions
Q2 13
Q2 12
1,074
617
450
TCEH
Oncor
7
1
See Appendix for Regulation G reconciliations and definition. Includes $6
million, $7 million, $16 million and $6 million in Q2 12, Q2 13, YTD 12 and YTD 13, respectively, of Corp. &
Other Adjusted EBITDA.
YTD 13
YTD 12
2,125
1,254
865
900
447
1,353
1,734
833
2,583
28%
31%
21%
1%
4%
18%
1
Q2 and YTD performance was largely driven by the same key drivers impacting adjusted (non-
GAAP) operating results. |
 Luminant Operational Results
8
Nuclear-fueled generation; GWh
Coal-fueled generation; GWh
Q2 13
Q2 12
5,159
10,497
YTD 12
YTD 13
9,897
4,666
10%
QTR
YTD 12
Q2 12
12,244
10,057
23,530
20,750
Q2 13
YTD 13
13%
YTD
22%
QTR
6%
YTD
Solid safety performance
0.5 TWh lower generation due to refueling
outage in spring 2013 vs. fall 2012
Top decile industry performance for
reliability and cost
2.7 TWh higher generation due to fewer
outage days
0.5 TWh lower generation due to seasonal
operations of 2 units at Monticello, net of
lower economic backdown
Q2
2013
Nuclear-Fueled Plant Results
Q2
2013
Coal-Fueled Plant Results |
 9
TXU Energy Operational Results
Retail electricity sales volumes by customer class;
GWh
1,540
1,525
1
SMB –
small business.
2
LCI –
large commercial and industrial.
3
Includes December 2012 acquisition of customers.
Last twelve months.
YTD 12
SMB
LCI
Residential
Q2 12
18,774
Q2 12
Q1 13
10,032
4,799
2,522
Q2 13
Q2 13
1,525
1,578
10,791
5,046
2,937
5,444
2,481
1,332
17,353
9,257
Q2 13
YTD 13
3%
LTM
1%
QTR
10%
QTR
8%
YTD
1
2
Total residential customers
End of period, thousands
3
1
2
4
Sales volumes declined 10% driven by
mild weather, business volumes and
residential customer counts
Residential attrition rates improved 33%
compared to 2012
Q2
2013
Results
YTD
2013
Results
Reduced PUC complaints to record low,
continuing top tier PUC complaint
performance
Last twelve month residential attrition rate
improved 55% compared to 2012
6,131
2,596
1,599
10,326
Lower SMB and LCI volumes reflect
competitive intensity and a focus on
margin discipline
4 |
 10
Oncor Operational Results
Electric energy billed volumes
4
; GWh
Q2 12
Q2 13
1
SMB –
small business.
2
LCI –
large commercial and industrial.
3
CREZ –
Competitive Renewable Energy Zone.
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
3,225
3,266
1%
LTM
5
Electricity distribution points of delivery
End of period, thousands of meters
Q2 13
Q1 13
3,253
3,266
Lower Q2 2013 and YTD 2013
volumes principally due to
decreased consumption as a result
of milder weather, partially offset by
customer growth
Slightly lower SMB
& LCI
energy
volumes principally due to milder
weather, offset by customer growth
$1.772 billion spent on CREZ
through June 30, 2013; $312 million
spent YTD 2013
7%
QTR
Q2 13
25,749
51,373
51,245
Q2 12
YTD 12
YTD 13
1%
QTR
Q2 2013 Results
1
2
3
1
2
17,457
17,203
33,354
33,244
9,146
8,546
18,019
18,001
26,603
4 |
 EFH Corp. Liquidity
Management As of June 30, 2013
11
Cash and Equivalents
TCEH Letter of Credit Facility
TCEH Revolving Credit Facility
3,116
EFH Corp., TCEH and EFIH continue to monitor near-term liquidity needs and opportunities
for liability management.
EFH Corp. (excluding Oncor) available liquidity
As of 6/30/13; $ millions
1,696
1
At June 30, 2013, restricted cash totaled $947 million, after reduction for a $115 million letter of
credit drawn in 2009 related to a building financing. The restricted cash supports letters
of credit, of which $814 million are outstanding, leaving $133 million available.
2,868
1,062
2,054
2,054
814
1,563
133
Facility Limit
LOCs/Cash Borrowings
Availability
1 |
 12
Commodity Prices
Commodity
Units
Q2 13
Actual
Q2 12
Actual
FY 12
1
Actual
13E
2
NYMEX gas price
3
$/MMBtu
4.02
2.27
2.75
3.64
HSC gas price
3
$/MMBtu
4.00
2.23
2.71
3.61
7x24 market heat rate (HSC)
4
MMBtu/MWh
7.79
10.93
9.53
10.75
North Hub 7x24 power price
$/MWh
31.11
24.31
25.17
38.81
TCEH weighted avg. hedge price
5
$/MMBtu
6.89
7.32
7.36
6.89
Gulf Coast ultra-low sulfur diesel
$/gallon
2.86
2.94
3.05
2.83
PRB 8400 coal
$/ton
9.63
6.67
7.57
9.65
LIBOR interest rate
6
percent
0.42%
0.73%
0.69%
0.41%
Commodity prices
Q2 13, Q2 12, FY 12 and 13E; mixed measures
2
13E: 2013 estimate based on average of monthly commodity prices as of June 28, 2013 for July
2013 through December 2013. 3
The
actual
prices
are computed based on settled Gas Daily prices for Henry Hub or Houston Ship Channel (HSC)
respectively. 4
Based on ERCOT Nodal market clearing price for North Hub.
5
Weighted average prices in the TCEH natural gas hedging program.
Based on NYMEX Henry Hub prices of forward natural gas sales positions in the hedging
program (excluding the impact of offsetting purchases for rebalancing and pricing
point basis
transactions).
6
The index for the settled value is a 6-month LIBOR rate. LIBOR interest rate for
13E is based on 6-month LIBOR rate. 1
FY 2012: Year ended December 31, 2012. |
 13
Factor
Measure
2013
2014
Total
03/31/13
Natural gas hedges
mm MMBtu
~163
~146
~309
Wtd. avg. hedge price
$/MMBtu
~$6.89
~$7.80
Natural gas prices
$/MMBtu
~$4.12
~$4.23
Cum. MtM gain at 03/31/13
$ billions
~$0.7
~$0.5
~$1.2
06/30/13
Natural gas hedges
mm MMBtu
~123
~146
~269
Wtd. avg. hedge price
$/MMBtu
~$6.89
~$7.80
Natural gas prices
4
$/MMBtu
~$3.64
~$3.91
Cum. MtM gain at 06/30/13
$ billions
~$0.5
~$0.6
~$1.1
Q2 13 MtM (loss) gain
$ billions
~(0.2)
~0.1
~(0.1)
Unrealized Mark-To-Market Impact Of Hedging
Unrealized mark-to-market impact of hedging program
06/30/13 vs. 03/31/13; mixed measures, pre-tax
1
2
3
1
2
Weighted average prices are based on forward natural gas sales positions in the natural gas
hedging program (excluding the impact of offsetting purchases for rebalancing). Where collars are
reflected, sales price represents the approximate collar floor price. March 31, 2013 prices
for 2013 represent April 1, 2013 through December 31, 2013 values and June 30, 2013 prices for 2013
represent July 1, 2013 through December 31, 2013 values.
MtM values include the effects of all transactions in the natural gas hedging program
including offsetting purchases (for re-balancing). June 30, 2013 prices for 2013 represent July 1, 2013 through December 31, 2013 volumes.
Where collars are reflected, the volumes are estimated based on the notional position of the
derivatives to provide protection against downward price movements. The notional
volumes for collars are approximately 150 million MMBtu, which correspond to a delta position of
approximately 150 million MMBtu in 2014.
2013 represents the average of monthly forward prices for July 1, 2013 though December 31,
2013. Decreased impact of hedge program is due to settlement of Q2 position slightly offset by decreasing
gas prices.
2
1
3
4 |
 14
TCEH Natural Gas Exposure
TCEH Natural Gas Position
13-15
1
; million MMBtu
Hedges Backed by Asset First Lien
Open Position
Factor
Measure
2013
2014
2015
Natural gas hedging program
million MMBtu
~104
~146
0
TXUE and LUME net positions
million MMBtu
~89
~87
~23
Overall estimated percent of
total NG position hedged
percent
~94%
~51%
~5%
1
As of June 30, 2013. Balance of 2013 is from August 1, 2013 to December 31,
2013. Assumes conversion of electricity positions based on a ~8.5 heat rate with natural gas generally
being
on
the
margin
~70-90%
of
the
time
(i.e.
when
other
technologies
are
forecast
to
be
on
the
margin,
no
natural
gas
position
is
assumed
to
be
generated).
Does
not
include
impacts
of
economic backdown or reliability (~9 M MMBtu for balance of 2013).
2
Includes estimated forward net wholesale and retail sales. Excludes any
transactions associated with proprietary trading positions. 3
The 2014 position includes notional volume of approximately 150 million MMBtu
costless collar with strikes of ~$7.80/MMBtu and ~$11.75/MMBtu for puts and calls, respectively. The delta
equivalent short position is ~150 million MMBtu.
205
104
89
12
2013
2014
2015
456
223
467
146
87
490
23
TXUE and Luminant Net Positions
2
TCEH has hedged approximately 94% of its estimated natural gas price exposure for
2013. 3 |
 15
EFH Corp. Adjusted EBITDA Sensitivities
Impact on EFH Corp. Adjusted EBITDA
13E
1
; mixed measures
The majority of 2013 commodity-related risks are significantly mitigated.
1
2013 estimate based on commodity positions as of June 30, 2013 and reflects the existing
regulatory environment under the Clean Air Interstate Rule, net of natural gas hedges and net
wholesale and retail sales. Excludes gains and losses incurred prior to June 30,
2013. Simplified
representation
of
heat
rate
position
in
a
single
TWh
position.
Heat
rate
impacts
are
typically
differentiated
across
plants
and
respective
pricing
periods:
nuclear
and
coal-fueled
plants generation (linked primarily to changes in North Hub 7x24), natural gas plants
(primarily North Hub 5x16) and wind (primarily West Hub 7x8). Assumes conversion of electricity
positions based on a ~8.5 market heat rate with natural gas generally being on the margin
~70-90% of the time (i.e., when coal is forecast to be on the margin, no natural gas position is
assumed to be generated).
3
Includes positions related to fuel surcharge on rail transportation.
4
Excludes fuel surcharge on rail transportation.
Commodity
Percent Hedged at
June 30, 2013
Change
BOY 13E Impact
$ millions
7X24
market
heat
rate
(MMBtu/MWh)
2
~88
0.1 MMBtu/MWh
~2
NYMEX gas price ($/MMBtu)
~94
$1/MMBtu
~12
Diesel
($/gallon)
3
~85
$1/gallon
~3
Base coal ($/ton)
4
~94
$2/ton
~1
Generation operations
Nuclear-
and coal / lignite-fueled generation (TWh)
N/A
1 TWh
~15
Retail operations
BOY 2013
Residential contribution margin ($/MWh)
11 TWh
$1/MWh
~11
Residential consumption
11 TWh
1%
~3
Business markets consumption
8 TWh
1%
~1
2 |
 $0.41
$1.88
2
Estimate as of June 30, 2013; $ billions
EFH / EFIH
TCEH
1
1st Lien
-
$0.41
2
2nd Lien
$0.25
$1.88
3
Total
$0.25
$2.29
Estimated Secured Debt Capacity at EFH / EFIH and TCEH
16
1
The
debt
capacity
numbers
presented
above
are
for
informational
purposes
only
and
should
not
be
relied
upon
in
connection
with
any
investment
decision
regarding
the
securities
of
EFH
Corp. or its subsidiaries. All of these amounts are estimates based on EFH Corp.'s current
interpretation of the covenants set forth in its and its subsidiaries' applicable debt agreements and
do not take into account exceptions in the agreements that may allow for the incurrence of
additional secured debt, including, but not limited to, acquisition debt, coverage ratio debt,
refinancing
debt,
capital
leases
and
hedging
obligations.
Moreover,
such
amounts
could
change
from
time
to
time
as
a
result
of,
among
other
things,
the
termination
of
any
debt
agreement
(or specific terms therein) or a change in the debt agreement that results from negotiations
with new or existing lenders. In addition, covenants included in agreements governing additional,
future debt may impose greater or lesser restrictions on the incurrence of secured debt by
EFH Corp. and its subsidiaries. Consequently, the actual amount of senior secured debt that EFH
Corp. and its subsidiaries are permitted to incur under their respective debt agreements
could be materially different than the amounts provided above. In addition, notwithstanding available
debt
capacity,
EFH
Corp.,
EFIH
and
TCEH
may
not
be
able
to
incur
additional debt due to their financial condition, market conditions or other reasons. EFH
Corp. encourages you to review, in
consultation
with
your
own
advisors,
its
and
its
subsidiaries’
various
debt
agreements,
which
are
on
file
with
the
SEC,
in
order
to
assess
the
ability
and
capacity
of
EFH
Corp.
and
its
subsidiaries
to
incur
additional
debt
(secured
and
unsecured)
in
the
future.
2
Of this amount, $1.0B is permitted to be issued for cash (entire amount is permitted to be
issued for exchanges). 3
TCEH is permitted to issue an unlimited amount of additional first-priority debt in
order to refinance the first-priority debt outstanding under the TCEH Senior Secured Facilities.
3
1
2nd Lien
1st Lien
$0.25
$0.25
$2.29 |
    17
Today’s Agenda
John Young
President & CEO
Q&A
Financial and Operational
Overview
Q2 2013 Review |
 ERCOT North Hub ATC (7x24) Heat Rate
MMBtu/MWh
1
2
18
1
Forward Natural Gas Prices and Heat Rates
HSC Natural Gas Prices
$/MMBtu
2015 HR
10.00
Forward gas prices have shown some indications of stabilizing.
Forward heat rate markets continue to show volatility.
$3.00
$3.50
$4.00
$4.50
$5.00
$5.50
$6.00
$6.50
$7.00
$7.50
$8.00
Cal 2013
Cal 2014
Cal 2015
7.00
7.50
8.00
8.50
9.00
9.50
10.00
10.50
11.00
11.50
12.00
Cal 2013
Cal 2014
Cal 2015
2
2015
heat
rate
represents
observable
market
data
as
of
06/28/2013.
1
Calendar
2013
represents
market
price
for
the
balance
of
the
year.
For
example,
as
of
June
30,
2013,
the
market
price
is
for
July
to
December
2013. |
 19
Today’s Agenda
Q&A
Financial and Operational
Overview
Q2 2013 Review
EFH Corp. Senior Executive Team |
 20
Questions & Answers |
 21
Appendix –
Additional Slides and
Regulation G Reconciliations
Appendix |
 Financial
Definitions Measure
Definition
Adjusted (non-GAAP)
Operating Results
Net income (loss) adjusted for items representing income or losses that are not reflective of
underlying operating results. These items include unrealized
mark-to-market gains and losses, noncash impairment charges and other charges, credits or gains that
are unusual or nonrecurring. EFH Corp. uses adjusted (non-GAAP) operating results
as a measure of performance and believes that analysis of its business by external
users is enhanced by visibility to both net income (loss) prepared in accordance with
GAAP and adjusted (non-GAAP) operating earnings (losses).
Adjusted EBITDA
(non-GAAP)
EBITDA adjusted to exclude interest income, noncash items, unusual items, results of
discontinued operations and other adjustments. Adjusted EBITDA is not intended to be
an alternative to GAAP results as a measure of operating performance or an
alternative
to
cash
flows
from
operating
activities
as
a
measure
of
liquidity
or
an
alternative
to
any
other
measure
of
financial
performance presented in accordance with GAAP, nor is it intended to be used as a measure of
free cash flow available for EFH Corp.’s discretionary use, as the measure
excludes certain cash requirements such as interest payments, tax payments and other
debt service requirements. Because not all companies use identical calculations,
Adjusted EBITDA may not be comparable to similarly titled measures of other
companies. See EFH Corp.’s filings with the SEC for a detailed reconciliation of EFH Corp.’s net
income prepared in accordance with GAAP to Adjusted EBITDA.
Competitive Business
Results
Refers to the combined results of the Competitive Electric segment and Corporate &
Other. Competitive Electric segment refers to the EFH Corp. business segment
that consists principally of TCEH. Contribution Margin (non-
GAAP)
Operating revenues less fuel, purchased power costs, and delivery fees, plus or minus net
gain (loss) from commodity hedging and trading activities, which on an adjusted
(non-GAAP) basis, exclude unrealized gains and losses. EBITDA
(non-GAAP)
Net income (loss) before interest expense and related charges, income tax expense (benefit)
and depreciation and amortization. GAAP
Generally accepted accounting principles.
Purchase Accounting
The purchase method of accounting for a business combination as prescribed by GAAP, whereby
the purchase price of a business combination
is
allocated
to
identifiable
assets
and
liabilities
(including
intangible
assets)
based
upon
their
fair
values.
The
excess
of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
Depreciation and amortization due to purchase accounting represents the net increase
in such noncash expenses due to recording the fair market values of property, plant
and equipment, debt and other assets and liabilities, including intangible assets such as emission allowances, customer
relationships and sales and purchase contracts with pricing favorable to market prices at the
date of the Merger. Amortization is reflected in revenues, fuel, purchased power
costs and delivery fees, depreciation and amortization and interest expense in the
income statement.
Regulated Business Results
Refers to the results of the Regulated Delivery segment, which consists largely of EFH
Corp.’s investment in Oncor. 22 |
 23
Table 1: EFH Corp. Adjusted EBITDA Reconciliation
Three and Six Months Ended June 30, 2012 and 2013
$ 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
Represents
amounts
recorded
under
stock-based
compensation
accounting
standards
and
excludes
capitalized
amounts.
3
Includes certain incentive compensation expenses as well as professional fees and other costs related
to generation plant reliability and supply chain and information technology efficiency
initiatives.
Primarily represents Sponsor Group management fees.
5
2013 includes costs associated with EFH Corp.’s liability management program.
6
Reflects noncapital outage costs.
Factor
Q2 12
Q2 13
YTD 12
YTD 13
Net loss
(696)
(71)
(1,000)
(640)
Income tax benefit
(403)
(350)
(583)
(825)
Interest expense and related charges
1,019
598
1,804
1,382
Depreciation and amortization
342
344
679
695
EBITDA
262
521
900
612
Adjustments to EBITDA (pre-tax):
Oncor Holdings distributions of earnings
33
49
69
80
Interest income
1
(1)
(1)
(1)
Amortization of nuclear fuel
41
35
83
74
Purchase accounting adjustments
20
6
41
11
Impairment and write-down of other assets
-
1
1
1
Equity in earnings of unconsolidated subsidiary (net of tax)
(84)
(74)
(141)
(141)
Unrealized net loss resulting from hedging and trading transactions
613
42
765
529
Noncash compensation expense
3
-
7
3
Transition and business optimization costs
10
7
19
13
Transaction and merger expenses
9
9
19
19
Restructuring and other
(3)
24
(3)
40
Expenses incurred to upgrade or expand a generation station
34
54
60
100
Subtotal
939
673
1,819
1,340
Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)
414
401
764
785
EFH Corp. Adjusted EBITDA per Restricted Payments Covenant
1,353
1,074
2,583
2,125
1
2
3
4
5
6
4 |
 24
Table 2: TCEH Adjusted EBITDA Reconciliation
Three and Six Months Ended June 30, 2012 and 2013
$ millions
Factor
Q2 12
Q2 13
YTD 12
YTD 13
Net loss
(645)
(215)
(883)
(739)
Income tax benefit
(334)
(74)
(449)
(452)
Interest expense and related charges
831
404
1,453
989
Depreciation and amortization
333
337
663
681
EBITDA
185
452
784
479
Adjustments to EBITDA (pre-tax):
Interest income
(9)
(1)
(26)
(5)
Amortization of nuclear fuel
41
35
83
74
Purchase accounting adjustments
1
12
6
21
11
Unrealized net loss resulting from hedging and trading transactions
613
42
765
529
Net loss attributable to non-controlling interests
1
-
1
-
EBITDA amount attributable to consolidated unrestricted subsidiaries and other equity interests
(2)
(9)
(4)
(9)
Corp. depreciation, interest and income tax expense included in SG&A
5
3
9
7
Noncash compensation expense
2
2
-
5
2
Severance expense
-
-
1
-
Transition and business optimization costs
3
10
6
19
11
Transaction and merger expenses
4
9
9
19
19
Restructuring and other
5
(1)
20
(3)
36
Expenses incurred to upgrade or expand a generation station
6
34
54
60
100
TCEH Adjusted EBITDA per Incurrence Covenant
900
617
1,734
1,254
Expenses related to unplanned generation station outages
23
9
49
19
TCEH Adjusted EBITDA per Maintenance Covenant
923
626
1,783
1,273
1
Includes amortization of the intangible net asset value of retail and wholesale power sales
agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power
purchase agreements and the stepped-up value of nuclear fuel. Also includes certain
credits and gains on asset sales not recognized in net income due to purchase accounting. 2
Represents amounts recorded under stock-based compensation accounting standards and excludes
capitalized amounts.
3
Includes certain incentive compensation expenses as well as professional fees and other costs related
to generation plant reliability and supply chain and information technology efficiency
initiatives.
Primarily represents Sponsor Group management fees.
5
2013 includes costs associated with EFH Corp.’s liability management program.
6
Reflects noncapital outage costs.
4 |
 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 and Six Months Ended June 30, 2012 and 2013
$ millions
Factor
Q2 12
Q2 13
YTD 12
YTD 13
Net income
107
96
182
183
Income tax expense
72
58
121
97
Interest expense and related charges
92
95
183
189
Depreciation and amortization
192
202
376
401
EBITDA
463
451
862
870
Interest income
(12)
(1)
(21)
(2)
Purchase accounting adjustments
(6)
(5)
(12)
(10)
Transition and business optimization costs and other
2
5
4
7
Oncor Adjusted EBITDA
447
450
833
865
1 |