EFH Corp.

Q1 2013 Investor Call

May 2, 2013

Exhibit 99.2

1

Safe Harbor Statement

Forward Looking Statements

This

presentation

contains

forward-looking

statements,

which

are

subject

to

various

risks

and

uncertainties.

A

discussion

of

risks

and

uncertainties

that

could

cause

actual

results

to

differ

materially

from

management's

current

projections,

forecasts,

estimates

and

expectations

is

contained

in

EFH

Corp.'s

filings

with

the

Securities

and

Exchange

Commission

(SEC).

In

addition

to

the

risks

and

uncertainties

set

forth

in

EFH

Corp.'s

SEC

filings,

the

forward-looking

statements

in

this

presentation

regarding

the

company’s

natural

gas

hedging

program

could

be

affected

by,

among

other

things:

changes

in

the

ERCOT

electricity

market,

including

a

regulatory

or

legislative

change,

that

results

in

wholesale

electricity

prices

not

generally

moving

with

natural

gas

prices;

any

decrease

in

market

heat

rates

as

the

program

generally

does

not

mitigate

exposure

to

changes

in

market

heat

rates;

the

unwillingness

or

failure

of

any

hedge

counterparty

to

perform

their

respective

obligations;

or

any

other

event

that

results

in

the

inability

to

continue

to

use

a

first

lien

on

TCEH’s

assets

to

secure

a

substantial

portion

of

the

hedges

under

the

program.

Regulation

G

This

presentation

includes

certain

non-GAAP

financial

measures.

A

reconciliation

of

these

measures

to

the

most

directly

comparable

GAAP

measures

is

included

in

the

appendix

to

this

presentation.

2

Today’s Agenda

Q&A

Financial and Operational

Overview

Q1 2013 Review

Paul Keglevic

Executive Vice President & CFO

Consolidated: reconciliation of GAAP net loss to adjusted (non-GAAP) operating results

Q1 12 vs. Q1 13

1

; $ millions, after tax

EFH Corp.

Adjusted (Non-GAAP) Operating Results

3

1

Three months ended March 31.

Factor

Q1 12

Q1 13

Change

EFH Corp. GAAP net loss

(304)

(569)

(265)

Items excluded from adjusted (non-GAAP) operating results (after tax) –

noncash:

Unrealized commodity-related mark-to-market net losses

98

314

216

Unrealized mark-to-market net gains on interest rate swaps

(74)

(98)

(24)

Effect of favorable resolution of income tax positions –

Competitive business

-

(84)

(84)

Effect of favorable resolution of income tax positions –

Oncor

-

(8)

(8)

EFH Corp. adjusted (non-GAAP) operating loss

(280)

(445)

(165)

Consolidated key drivers of the change in (non-GAAP) operating results

Q1 12 vs. Q1 13; $ millions, after tax

EFH Corp.

Adjusted (Non-GAAP) Operating Results Key Drivers (after tax)

1

Competitive business consists of Competitive Electric segment and Corp. & Other.

4

Description/Drivers

Better (Worse) 

Than

Q1 12

Competitive business¹:

Lower net margin from asset management driven by lower natural gas hedge volumes and prices

(139)

Higher net fuel expense driven by lower lignite blend at coal plants

(6)

Higher net generation due to reduced unplanned outage days at coal plants

14

Lower amortization of intangibles arising from purchase accounting

2

Contribution margin    

(129)

Higher net interest expense driven by higher average borrowings

(24)

Higher operating costs reflecting planned outages at coal and nuclear generation units

(14)

Higher depreciation reflecting accelerated depreciation primarily associated with asset retirements during planned outages at three coal units

(9)

Lower effective tax rate reflecting lower accrued interest

8

All other -

net

1

Total change -

Competitive business

(167)

Regulated business:

Higher net revenues reflecting transmission tariff increases, automated meter surcharges, colder (more normal) weather, and growth in points of delivery

17

Higher revenues from transmission and other cost recovery (reconcilable rate) charges

5

Lower third party transmission fees

1

Higher depreciation and amortization reflecting infrastructure investment

(10)

Higher net interest expense driven by settlement of TCEH transition bond interest reimbursement agreement in 2012

(6)

Higher operations and maintenance expense due to energy efficiency programs and advanced metering

(2)

All other –

net

(3)

Change in Regulated business (~80% owned by EFH Corp.)

2

Total change in EFH Corp. adjusted (non-GAAP) operating results

(165)

EFH Corp. Adjusted EBITDA (Non-GAAP)

EFH Corp. Adjusted EBITDA (non-GAAP)

1

Q1

12 vs. Q1 13;

$ millions

Q1 13

Q1 12

1,051

1,230

638

834

415

386

TCEH 

Oncor

Q1 13 performance was largely driven by the same key drivers impacting adjusted (non-

GAAP) operating results.

8%

1

See Appendix for Regulation G reconciliations and definition.  Includes  $10 million and $(2) million of Corp. & Other Adjusted EBITDA in Q1 12 and Q1 13, respectively.

5

24%

15%

Luminant Operational Results

6

Q1 2013 Nuclear Plant Results

Solid safety performance

2 fewer generation days in Q1 2013

Top decile industry performance for

reliability and cost

Q1 2013 Coal-Fueled Plant Results

Higher generation due to improved

reliability -

fewer unplanned outages

Higher planned outage days due to

maintenance

~4.3 TWh of available generation was

uneconomic resulting in seasonal

operations and backdown of higher

cost units

Q1 2013 Results

Sales volumes declined 4% driven

by business volumes

Residential attrition rates

improved over 25% compared to

Q1 2012.  Q1 2013 attrition was

1.0% vs. 1.4% in Q1 2012

Lower SMB

1

and LCI

2

volumes

reflect competitive intensity and a

focus on margin discipline

TXU Energy Operational Results

Total residential customers3

End of period, thousands

Retail electricity sales volumes by customer class;

GWh

1

SMB –

small business.             

2

LCI –

large commercial and industrial.

3

Includes December 2012 acquisition of customers.

4

Last  twelve months.

7

8

Oncor Operational Results

Electric energy billed volumes

3

; GWh

1

SMB –

small business; LCI –

large commercial and industrial.

2

CREZ –

Competitive Renewable Energy Zone.

3

On average, billed volumes are on an approximate 17-day calendar lag; therefore, amounts shown reflect

partial impacts from prior quarters.

4

Last twelve months.

Electricity distribution points of delivery

End of period, thousands of meters

Q1 2013 Results

Higher residential volumes

principally due to more normal

weather and premise growth 

Higher SMB & LCI

1

energy volumes

due to economic growth

$1.6 billion spent on CREZ

2

through

March 31, 2013; $167 million spent in

2013

EFH Corp. Liquidity Management

As of March 31, 2013

9

Cash and Equivalents

TCEH Letter of Credit Facility¹

TCEH Revolving Credit Facility

EFH

Corp.

and

TCEH

continue

to

monitor

capital

market

conditions

for

opportunities

to

ensure

liquidity

needs

are

met

and

to

improve

financial

flexibility.

EFH Corp. (excluding Oncor) available liquidity

As of 3/31/13; $ millions

1

At March 31, 2013, restricted cash totaled $947 million, after reduction for a $115 million letter of credit drawn in 2009 related to a building financing.  The restricted cash supports letters

of credit, of which $735 million are outstanding, leaving $212 million available.

10

10

10

Commodity Prices

Commodity

Units

Q1 13

Actual

Q1 12

Actual

FY 12

1

Actual

13E

1

NYMEX gas price

2

$/MMBtu

3.48

2.46

2.75

4.12

HSC gas price

2

$/MMBtu

3.43

2.41

2.71

4.08

7x24 market heat rate (HSC)

3

MMBtu/MWh

7.69

10.00

9.53

10.16

North Hub 7x24 power price

$/MWh

26.45

23.46

25.17

41.47

TCEH weighted avg. hedge price

4

$/MMBtu

6.89

7.46

7.36

6.89

Gulf Coast ultra-low sulfur diesel

$/gallon

3.09

3.17

3.05

2.99

PRB 8400 coal

$/ton

9.17

8.28

7.57

9.62

LIBOR interest rate

5

percent

0.47%

0.76%

0.69%

0.59%

Commodity prices

Q1 13, Q1 12, FY 12 and 13E; mixed measures

1

FY

2012:

Year

ended

December

31,

2012;

13E:

2013

estimate

based

on

average

of

monthly

commodity

prices

as

of

March

28,

2013

for

April

2013

through

December

2013.

2

The

actual

prices

are

computed

based

on

settled

Gas

Daily

prices

for

Henry

Hub

or

Houston

Ship

Channel

(HSC)

respectively.

3

Based

on

ERCOT

Nodal

market

clearing

price

for

North

Hub.

4

Weighted

average

prices

in

the

TCEH

natural

gas

hedging

program.

Based

on

NYMEX

Henry

Hub

prices

of

forward

natural

gas

sales

positions

in

the

hedging

program

(excluding

the

impact

of

offsetting

purchases

for

rebalancing

and

pricing

point

basis

transactions).

5

The

index

for

the

settled

value

is

a

6-month

LIBOR

rate.

LIBOR

interest

rate

for

13E

is

based

on

9

month

LIBOR

rate.

11

Factor

Measure

2013

2014

Total

12/31/12

Natural gas hedges

mm MMBtu

~211

~146

~357

Wtd. avg. hedge price¹

$/MMBtu

~$6.89

~$7.80

Natural gas prices

$/MMBtu

~$3.54

~4.03

Cum. MtM gain at 12/31/12²

$ billions

~$1.0

~$0.6

~$1.6

03/31/13

Natural gas hedges³

mm MMBtu

~163

~146

~309

Wtd. avg. hedge price¹

$/MMBtu

~$6.89

~$7.80

Natural gas prices

4

$/MMBtu

~$4.12

~$4.23

Cum. MtM gain at 03/31/13²

$ billions

~$0.7

~$0.5

~$1.2

Q1 13 MtM (loss) gain

$ billions

~(0.3)

~(0.1)

~(0.4)

11

Unrealized Mark-To-Market Impact Of Hedging

Unrealized mark-to-market impact of hedging program

03/31/13 vs. 12/31/12; mixed measures, pre-tax

Hedge program decrease is due to settlement of Q1 position, as well as rising gas prices.

1

Weighted

average

prices

are

based

on

forward

natural

gas

sales

positions

in

the

natural

gas

hedging

program

(excluding

the

impact

of

offsetting

purchases

for

rebalancing

and

pricing

point

basis

transactions).

Where

collars

are

reflected,

sales

price

represents

the

approximate

collar

floor

price.

December

31,

2012

prices

for

2013

represent

January

1,

2013

through

December

31,

2013

values

and

March

31,

2013

prices

for

2013

represent

April

1,

2013

through

December

31,

2013

values.

2

MtM

values

include

the

effects

of

all

transactions

in

the

natural

gas

hedging

program

including

offsetting

purchases

(for

re-balancing)

and

natural

gas

basis

deals.

3

As

of

March

31,

2013.

2013

represents

April

1,

2013

through

December

31,

2013

volumes.

Where

collars

are

reflected,

the

volumes

are

estimated

based

on

the

notional

position

of

the

derivatives

to

provide

protection

against

downward

price

movements.

The

notional

volumes

for

collars

are

approximately

150

million

MMBtu,

which

correspond

to

a

delta

position

of

approximately

146

million

MMBtu

in

2014.

4

2013

represents

the

average

of

monthly

forward

prices

for

April

1,

2013

though

December

31,

2013.

12

12

TCEH Natural Gas Exposure

TCEH Natural Gas Position

13-15¹; million MMBtu

Hedges Backed by Asset First Lien

Open Position

Factor

Measure

2013

2014

2015

Natural gas hedging program

million MMBtu

~152            

~146

0

TXUE and LUME net positions

million MMBtu

~166

~51

~16

Overall estimated percent of

total NG position hedged

percent

~94%

~43%

~3%

TXUE and Luminant Net Positions2

TCEH has hedged approximately 94% of its estimated natural gas price exposure for 2013

1

As

of

March

31,

2013.

Balance

of

2013

is

from

May

1,

2013

to

December

31,

2013.

Assumes

conversion

of

electricity

positions

based

on

a

~8.5

heat

rate

with

natural

gas

generally

being

on

the

margin

~70-90%

of

the

time

(i.e.

when

other

technologies

are

forecast

to

be

on

the

margin,

no

natural

gas

position

is

assumed

to

be

generated).

2

Includes

estimated

forward

net

wholesale

and

retail

sales.

Excludes

any

transactions

associated

with

proprietary

trading

positions.

3

The

2014

position

includes

notional

volume

of

approximately

150

million

MMBtu

costless

collar

with

strikes

of

~$7.80/MMBtu

and

~$11.75/MMBtu

for

puts

and

calls,

respectively.

The

delta

equivalent

short

position

is

~146

million

MMBtu.

3

2013 estimate based on commodity positions as of March 31, 2013 and reflects the existing regulatory environment under the Clean Air Interstate Rule, net of

natural gas hedges and net wholesale and retail sales.  Excludes gains and losses incurred prior to March 31, 2013.

Simplified representation of heat rate position in a single TWh position.  Heat rate impacts are typically differentiated across plants and respective pricing

periods: nuclear and coal-fueled plants generation (linked primarily to changes in North Hub 7x24), natural gas plants (primarily North Hub 5x16) and wind

(primarily West Hub7x8).  Assumes conversion of electricity positions based on a ~8.5 market heat rate with natural gas generally being on the margin ~70-90%

of the time (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated).

Includes positions related to fuel surcharge on rail transportation.

Excludes fuel surcharge on rail transportation. 

13

13

13

EFH Corp. Adjusted EBITDA Sensitivities

Commodity

Percent Hedged at

March 31, 2013

Change

BOY 13E Impact

$ millions

7X24 market heat rate (MMBtu/MWh)2

~85

0.1 MMBtu/MWh

~4

NYMEX gas price ($/MMBtu)

~94

$1/MMBtu

~20

Diesel ($/gallon)3

~80

$1/gallon

~6

Base coal ($/ton)

4

~92

$2/ton

~2

Generation operations

Nuclear-

and coal / lignite-fueled generation (TWh)

N/A

1 TWh

~15

Retail operations

BOY  2013

Residential contribution margin ($/MWh)

17 TWh

$1/MWh

~17

Residential consumption

17 TWh

1%

~5

Business markets consumption

12 TWh

1%

~1

Impact on EFH Corp. Adjusted EBITDA

13E¹; mixed measures

The majority of 2013 commodity-related risks are significantly mitigated

1

2

3

4

Estimate as of March 31, 2013; $ billions

EFH / EFIH

TCEH

1

1st Lien

$0.02

$0.41

2

2nd Lien

$0.23

$1.88

3

Total

$0.25

$2.29

Estimated Secured Debt Capacity at EFH / EFIH and TCEH

1

14

1

The

debt

capacity

numbers

presented

above

are

for

informational

purposes

only

and

should

not

be

relied

upon

in

connection

with

any

investment

decision

regarding

the

securities

of

EFH

Corp.

or

its

subsidiaries.

All

of

these

amounts

are

estimates

based

on

EFH

Corp.'s

current

interpretation

of

the

covenants

set

forth

in

its

and

its

subsidiaries'

applicable

debt

agreements

and

do

not

take

into

account

exceptions

in

the

agreements

that

may

allow

for

the

incurrence

of

additional

secured

debt,

including,

but

not

limited

to,

acquisition

debt,

coverage

ratio

debt,

refinancing

debt,

capital

leases

and

hedging

obligations.

Moreover,

such

amounts

could

change

from

time

to

time

as

a

result

of,

among

other

things,

the

termination

of

any

debt

agreement

(or

specific

terms

therein)

or

a

change

in

the

debt

agreement

that

results

from

negotiations

with

new

or

existing

lenders.

In

addition,

covenants

included

in

agreements

governing

additional,

future

debt

may

impose

greater

or

lesser

restrictions

on

the

incurrence

of

secured

debt

by

EFH

Corp.

and

its

subsidiaries.

Consequently,

the

actual

amount

of

senior

secured

debt

that

EFH

Corp.

and

its

subsidiaries

are

permitted

to

incur

under

their

respective

debt

agreements

could

be

materially

different

than

the

amounts

provided

above.

EFH

Corp.

encourages

you

to

review,

in

consultation

with

your

own

advisors,

its

and

its

subsidiaries’

various

debt

agreements,

which

are

on

file

with

the

SEC,

in

order

to

assess

the

ability

and

capacity

of

EFH

Corp.

and

its

subsidiaries

to

incur

additional

debt

(secured

and

unsecured)

in

the

future.

2

Of

this

amount,

$1.0B

is

permitted

to

be

issued

for

cash

(entire

amount

is

permitted

to

be

issued

for

exchanges).

3

TCEH

is

permitted

to

issue

an

unlimited

amount

of

additional

first-priority

debt

in

order

to

refinance

the

first-priority

debt

outstanding

under

the

TCEH

Senior

Secured

Facilities.

15

Today’s Agenda

Q&A

Financial and Operational

Overview

Q1 2013 Review

John Young

President & CEO

Forward Natural Gas Prices and Heat Rates

Forward gas prices have shown some indications of stabilizing, 

Heat rate markets continue to show volatility.

1

Calendar

2013

represents

market

price

for

the

balance

of

the

year.

For

example,

as

of

March

31,

2013,

the

market

price

is

for

April

to

December

2013.

2

2015

is

not

considered

liquid.

The

heat

rate

represents

indicative

pricing

from

limited

brokers.

16

17

1

ERCOT Capacity, Demand and Reserve (CDR) Summary, December 2012.

2

ERCOT Capacity, Demand and Reserve (CDR) Summary, May 2013.

ERCOT reserve margin

2013E-2018E; percent

December 2012 CDR

1

May 2013 CDR

2

Resource Adequacy in ERCOT

13.75% target

reserve margin

–

–

–

–

13.2

13.8

11.6

10.4

10.5

9.4

'13

'14

'15

'16

'17

'18

ERCOT Loss of Load Probability

(LOLP) study results indicate a higher

target reserve margin is likely (i.e.,

15%-16%); final decision pending at

ERCOT

Stakeholders and PUCT continue

reviewing inputs to the ERCOT

reserve margin methodology (CDR)

PUCT considering additional market

design changes, such as an operating

reserve demand curve

Yesterday ERCOT issued the May

2013 CDR, which increased the 2014

planning reserve margin to 13.8

percent versus 10.9 in the December

2012 CDR.  The increase is primarily

driven by higher expected generation

resources

Recent and pending PUCT/ERCOT

actions and potential deliberations:

18

Today’s Agenda

Q&A

Financial and Operational

Overview

Q1 2013 Review

EFH Corp. Senior Executive Team

19

Questions & Answers

20

Appendix –

Additional Slides and

Regulation G Reconciliations

Appendix

Financial Definitions

Measure

Definition

Adjusted (non-GAAP)

Operating Results

Net

income

(loss)

adjusted

for

items

representing

income

or

losses

that

are

not

reflective

of

underlying

operating

results.

These

items

include

unrealized

mark-to-market

gains

and

losses,

noncash

impairment

charges

and

other

charges,

credits

or

gains

that

are

unusual

or

nonrecurring.

EFH

Corp.

uses

adjusted

(non-GAAP)

operating

results

as

a

measure

of

performance

and

believes

that

analysis

of

its

business

by

external

users

is

enhanced

by

visibility

to

both

net

income

(loss)

prepared

in

accordance

with

GAAP

and

adjusted

(non-GAAP)

operating

earnings

(losses).

Adjusted EBITDA

(non-GAAP)

EBITDA

adjusted

to

exclude

interest

income,

noncash

items,

unusual

items,

results

of

discontinued

operations

and

other

adjustments.

Adjusted

EBITDA

is

not

intended

to

be

an

alternative

to

GAAP

results

as

a

measure

of

operating

performance

or

an

alternative

to

cash

flows

from

operating

activities

as

a

measure

of

liquidity

or

an

alternative

to

any

other

measure

of

financial

performance

presented

in

accordance

with

GAAP,

nor

is

it

intended

to

be

used

as

a

measure

of

free

cash

flow

available

for

EFH

Corp.’s

discretionary

use,

as

the

measure

excludes

certain

cash

requirements

such

as

interest

payments,

tax

payments

and

other

debt

service

requirements.

Because

not

all

companies

use

identical

calculations,

Adjusted

EBITDA

may

not

be

comparable

to

similarly

titled

measures

of

other

companies.

See

EFH

Corp.’s

filings

with

the

SEC

for

a

detailed

reconciliation

of

EFH

Corp.’s

net

income

prepared

in

accordance

with

GAAP

to

Adjusted

EBITDA.

Competitive Business

Results

Refers

to

the

combined

results

of

the

Competitive

Electric

segment

and

Corporate

&

Other.

Competitive

Electric

segment

refers

to

the

EFH

Corp.

business

segment

that

consists

principally

of

TCEH.

Contribution Margin (non-

GAAP)

Operating

revenues

less

fuel,

purchased

power

costs,

and

delivery

fees,

plus

or

minus

net

gain

(loss)

from

commodity

hedging

and

trading

activities,

which

on

an

adjusted

(non-GAAP)

basis,

exclude

unrealized

gains

and

losses.

EBITDA

(non-GAAP)

Net

income

(loss)

before

interest

expense

and

related

charges,

income

tax

expense

(benefit)

and

depreciation

and

amortization.

GAAP

Generally

accepted

accounting

principles.

Purchase Accounting

The

purchase

method

of

accounting

for

a

business

combination

as

prescribed

by

GAAP,

whereby

the

purchase

price

of

a

business

combination

is

allocated

to

identifiable

assets

and

liabilities

(including

intangible

assets)

based

upon

their

fair

values.

The

excess

of

the

purchase

price

over

the

fair

values

of

assets

and

liabilities

is

recorded

as

goodwill.

Depreciation

and

amortization

due

to

purchase

accounting

represents

the

net

increase

in

such

noncash

expenses

due

to

recording

the

fair

market

values

of

property,

plant

and

equipment,

debt

and

other

assets

and

liabilities,

including

intangible

assets

such

as

emission

allowances,

customer

relationships

and

sales

and

purchase

contracts

with

pricing

favorable

to

market

prices

at

the

date

of

the

Merger.

Amortization

is

reflected

in

revenues,

fuel,

purchased

power

costs

and

delivery

fees,

depreciation

and

amortization

and

interest

expense

in

the

income

statement.

Regulated Business Results

Refers

to

the

results

of

the

Regulated

Delivery

segment,

which

consists

largely

of

EFH

Corp.’s

investment

in

Oncor.

21

Table 1: EFH Corp. Adjusted EBITDA Reconciliation

Three Months Ended March 31, 2012 and 2013

$ millions

Factor

Q1 12

Q1 13

Net loss

(304)

(569)

Income tax benefit

(180)

(475)

Interest expense and related charges

785

784

Depreciation and amortization

337

351

EBITDA

638

91

Adjustments to EBITDA (pre-tax):

Oncor Holdings distributions of earnings

36

31

Interest income

(2)

-

Amortization of nuclear fuel

42

39

Purchase accounting adjustments

1

21

5

Impairment and write-down of assets

1

-

Equity in earnings of unconsolidated subsidiary (net of tax)

(57)

(67)

Unrealized net loss resulting from commodity hedging and trading

transactions

152

487

Noncash compensation expense

2

4

3

Transition and business optimization costs

3

9

6

Transaction and merger expenses

4

10

10

Restructuring and other

5

-

16

Expenses incurred to upgrade or expand a generation station

6

26

46

Subtotal

880

667

Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)

350

384

EFH Corp. Adjusted EBITDA per Restricted Payments Covenant

1,230

1,051

1

Includes

amortization

of

the

intangible

net

asset

value

of

retail

and

wholesale

power

sales

agreements,

environmental

credits,

coal

purchase

contracts,

nuclear

fuel

contracts

and

power

purchase

agreements

and

the

stepped-up

value

of

nuclear

fuel.

Also

includes

certain

credits

and

gains

on

asset

sales

not

recognized

in

net

income

due

to

purchase

accounting.

2

Represents

amounts

recorded

under

stock-based

compensation

accounting

standards

and

excludes

capitalized

amounts.

3

Includes

certain

incentive

compensation

expenses

as

well

as

professional

fees

and

other

costs

related

to

generation

plant

reliability

and

supply

chain

efficiency

initiatives.

4

Primarily

represents

Sponsor

Group

management

fees.

5

Includes

costs

associated

with

liability

management

program.

6

Represents

noncapital

outage

costs.

22

Table 2: TCEH Adjusted EBITDA Reconciliation

Three Months Ended March 31, 2012 and 2013

$ millions

Factor

Q1 12

Q1 13

Net loss

(238)

(524)

Income tax benefit

(115)

(378)

Interest expense and related charges

622

586

Depreciation and amortization

330

344

EBITDA

599

28

Adjustments to EBITDA (pre-tax):

Interest income

(17)

(4)

Amortization of nuclear fuel

42

39

Purchase accounting adjustments

1

9

5

Unrealized net loss resulting from commodity hedging and trading

transactions

152

487

EBITDA amount attributable to consolidated unrestricted subsidiaries

(2)

-

Corporate depreciation, interest and income tax expenses included in SG&A expense

4

4

Noncash compensation expense

2

3

2

Transition and business optimization costs

3

9

5

Transaction and merger expenses

4

10

10

Restructuring and other

5

(1)

16

Expenses incurred to upgrade or expand a generation station

6

26

46

TCEH Adjusted EBITDA per Incurrence Covenant

834

638

Expenses related to unplanned generation station outages

26

10

TCEH Adjusted EBITDA per Maintenance Covenant

860

648

23

1

2

3

4

5

6

Includes amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power

purchase agreements and the stepped up value of nuclear fuel.  Also includes certain credits  and gains on asset sales not recognized in net income due to purchase accounting.

Includes expenses recorded under stock-based compensation accounting standards and excludes capitalized amounts.

Includes certain incentive compensation expenses as well as professional fees and other costs related to generation plant reliability and supply chain efficiency initiatives.

Primarily represents Sponsor Group management fees.

Includes costs associated with liability management program.

Represents noncapital outage costs. 

Table 3: Oncor Adjusted EBITDA Reconciliation

Three Months Ended March 31, 2012 and 2013

$ millions

Factor

Q1 12

Q1 13

Net income

75

87

Income tax expense

49

39

Interest expense and related charges

91

94

Depreciation and amortization

184

199

EBITDA

399

419

Interest income

(8)

(1)

Purchase accounting adjustments1

(6)

(5)

Noncash compensation expense

1

1

Settlement of management incentive pay plan

-

1

Oncor Adjusted EBITDA

386

415

1

Purchase

accounting

adjustments

consist

of

amounts

related

to

the

accretion

of

an

adjustment

(discount)

to

regulatory

assets.

24