Energy Future (TXU) 8-K Energy Future Holdings Reports Fourth Quarter and Full Year 2010 Results

EFH Corp.

Q4 2010 Investor Call

February 18, 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

Q4 2010 Review

Paul Keglevic

Executive Vice President & CFO

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

Q4

1

09

vs.

Q4

10

;

$

millions,

after

tax

1

Three months ended December 31

2

Q4 09 reflects $22 million of land impairment partially offset by $14 million of reversal of purchase accounting reserves.

EFH Corp.

Adjusted (Non-GAAP) Operating Results -

QTR

3

Factor

Q4 09

Q4 10

Change

EFH Corp. GAAP net income

137

161

24

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

noncash:

Unrealized commodity-related mark-to-market net (gains) losses

(330)

254

584

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

(110)

(218)

(108)

Debt extinguishment gains –

debt exchanges and repurchases

(56)

(417)

(361)

Gain on termination of long-term power sales contract

-

(75)

(75)

Other (noncash)²

8

-

(8)

EFH Corp. adjusted (non-GAAP) operating loss

(351)

(295)

56

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

Q4

1

10 vs. Q4 09; $ millions, after tax

EFH Corp.

Adjusted

(Non-GAAP)

Operating

Results

Key

Drivers

(after

tax)

-

QTR

1

Three months ended December 31

2

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

4

Description/Drivers

Better

(Worse) 

Than

Q4 09

Competitive

business²:

Impact of new lignite-fueled generation units

35

Higher production from legacy baseload generation units

26

Lower amortization of intangibles arising from purchase accounting

21

Lower net margin from asset management and retail activities

(22)

Higher fuel costs at legacy baseload units due to increased coal

transportation expenses and higher uranium and conversion costs

(19)

Lower retail volumes primarily due to weather

(17)

All other -

net

(3)

Contribution margin    

21

Lower net interest expense driven by liability management program and lower noncash amortization of swap losses

36

Improvement in effective tax rate due primarily to lower accrued

interest on uncertain tax positions

25

Lower costs related to outsourcing transition and other SG&A reductions

13

Lower retail bad debt expense

6

Higher depreciation reflecting the new lignite-fueled generation units and mining facilities and ongoing investment in the generation fleet

(31)

Higher operating costs related to the new and legacy baseload generation units  

(12)

All other -

net

(7)

Total improvement -

Competitive business

51

Regulated business:

Higher revenues from transmission rate increases, distribution tariffs approved in the September 2009 rate order and AMS surcharge

18

Higher depreciation reflecting infrastructure investment and higher depreciation rates approved in the September 2009 rate order

(9)

Lower volumes primarily due to weather

(4)

Total improvement –

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

5

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

56

Factor

FY 09

FY 10

Change

EFH Corp. GAAP net income (loss)

344

(2,812)

(3,156)

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

noncash:

Unrealized commodity-related mark-to-market net gains

(788)

(786)

2

Unrealized mark-to-market net (gains) losses on interest rate swaps

(452)

134

586

Goodwill impairment

90

4,100

4,010

Debt extinguishment gains –

debt exchanges and repurchases

(56)

(1,168)

(1,112)

Reduction of income tax expense due to expected resolution of

IRS tax audit for 1997-

2002

-

(146)

(146)

Gain on termination of long-term power sales contract

-

(75)

(75)

Income tax charge recorded as a result of health care legislation

-

8

8

Other (noncash)

2

10

-

(10)

EFH Corp. adjusted (non-GAAP) operating loss

(852)

(745)

107

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

FY

1

09

vs.

FY

10;

$

millions,

after

tax

1  

Full year ended December 31

2

Full

year

09

reflects,

after

tax,

$22

million

of

land

impairment

and

$16

million

of

write-off

of

rate

case

disallowed

regulatory

assets,

partially

offset

by

$14

million

of

reversal

of

purchase

accounting

reserves

and

$14

million

arising

from

the

reversal

of

a

use

tax

accrual

recorded

in

purchase

accounting

related

to

periods

prior

to

the

October

2007

merger.

EFH Corp.

Adjusted (Non-GAAP) Operating Results –

Full Year

5

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

FY

1

10

vs.

FY

09;

$

millions,

after

tax

1

Full year ended December 31

2

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

EFH Corp.

Adjusted

(Non-GAAP)

Operating

Results

Key

Drivers

(after

tax)

–

FY

6

Description/Drivers

Better

(Worse) 

Than

FY 09

Competitive business²:

Impact of new lignite-fueled generation units

255

Lower amortization of intangibles arising from purchase accounting

87

Higher retail volumes primarily due to weather

8

Higher fuel costs at legacy baseload units due to increased coal

transportation expenses and higher uranium and conversion costs

(106)

Lower net margin from asset management  and retail activities

(37)

All other -

net

(4)

Contribution margin    

203

Lower costs related to outsourcing transition,  new retail customer care system and other SG&A reductions

75

Gains on sales of assets (reported in other income)

57

Improvement in effective tax rate due primarily to lower accrued

interest on uncertain tax positions

37

Lower retail bad debt expense

5

Higher depreciation reflecting the new lignite-fueled generation units and mining facilities and ongoing investment in the generation fleet

(135)

Higher operating costs related to the new and legacy baseload generation units  

(95)

Higher net interest expense driven by lower capitalized interest

due to completion of the new generation units

(51)

Total improvement -

Competitive business

96

Regulated business:

Higher distribution tariffs, including the rates approved in the

September 2009 rate review order

62

Higher volumes primarily driven by the effects of weather

31

Surcharge to recover AMS deployment costs

30

Higher transmission revenues primarily due to a rate increase to

recover ongoing investment

17

Higher depreciation reflecting higher depreciation rates approved in the September rate review order and infrastructure investment

(75)

Higher costs reflecting amortization of regulatory assets approved for recovery, AMS implementation and higher transmission fees

(52)

Change in effective tax rate due to accrued interest adjustment in 2009 and tax on Medicare subsidy

(21)

All other –

net primarily includes noncontrolling interests and lower contractor, professional and outsourced services

19

Total improvement –

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

11

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

107

EFH Corp. Adjusted EBITDA (Non-GAAP)

FY 10

FY 09

5,240

4,857

1

See Appendix for Regulation G reconciliations and definition.  Includes $(2) million, $5 million, $13 million and $28 million in Q4 09, Q4 10, FY 09 and FY 10, respectively, of Corp. &

Other Adjusted EBITDA.

2

Three months ended December 31

3

Full year ended December 31

EFH Corp. Adjusted EBITDA (non-GAAP)

1

Q4

2

09

vs.

Q4

10

and

FY

3

09

vs.

FY

10;

$

millions

Q4 10

Q4 09

1,083

1,038

749

745

329

295

3,689

3,505

1,523

1,339

4%

12%

1%

14%

8%

5%

TCEH 

Oncor

Q4 and FY 10 performance was largely driven by the same key drivers impacting adjusted (non-

GAAP) operating results.

7

8

Luminant Operational Results

8

Nuclear-fueled generation; GWh

Coal-fueled generation; GWh

2,891

FY 10

Solid Nuclear performance

Q4 09

12,769 

14,032

1

Variance does not include generation from Sandow 5 and Oak Grove

1 & 2.

Sandow 5 & Oak Grove

Legacy coal-fueled plants

Coal-fueled fleet benefiting from new units

Q4 10

Q4 09

4,592

20,104

FY 09

FY 10

20,208

5,368

11,384

54,775

Q4 10

FY 09

2%¹

QTR

2%¹

FY

45,684

17%

QTR

FY 2010  Nuclear Plant Results

Solid safety performance

3

rd

shortest Spring 2010 outage in the industry

Top decile industry performance for reliability

and cost

1%

FY

1,348

1,443

FY 2010  Coal-fueled Plant Results

New plants collectively operated at ~70%

capacity factor

Lower generation due to higher planned

outages and increased economic backdown

partially offset by improved performance

Top quartile industry performance

Q4 2010 Results

New plants generated 2.9 TWh

Nuclear performance 17% higher than Q4 2009

due to outage timing; 2010 outage in Q2, 2009

outage in Q4

Improved legacy coal-fueled plant performance

offset by higher economic backdown

11,421

11,141

44,241

43,391

TXU Energy Operational Results

9

FY 2010 Results

Lower residential sales volumes

driven by lower customer counts

partially offset by favorable weather

Lower residential customer counts

reflect competitive activity in the

marketplace

Business load growth attributable to

new customers and improved

economy

Continued strong competitive activity

FY volume increases due to weather and improved economy

Total residential customers

End of period, thousands

Retail electricity sales volumes by customer class;

GWh

1,800

1,771

1

SMB –

small business

2

LCI -

large commercial and industrial

3

Latest twelve months

FY 09

SMB¹

LCI²

Residential

Q4 09

11,136

50,581

Q4 09

Q3 10

5% 3

LTM

2%

FY

28,208

5,734

15,339

3,668

1,734

8,042

Q4 10

Q4 10

1,771

1,862

2%

QTR

28,046

14,573

7,962

5,168

3,600

1,651

51,589

10,419

Q4 10

FY 10

6%

QTR

Q4 2010 Results

Lower residential sales volumes

driven by lower customer counts and

unfavorable weather

10

15,483

16,355

65,077

67,500

38,299

41,823

8,213

7,704

Oncor Operational Results

Billed electric energy volumes³; GWh

Q4 10

Q4 09

Q4 10

Volume increases due to weather and improved economy

Demand

growth

below

ERCOT

estimated

CAGR

of

1.9%

5

FY 2010 Results

Higher billed residential energy volumes due to

warmer weather in Q4 10 and colder weather in

Q1 10 compared to 2009 and premise growth

Higher SMB and LCI

2

energy volumes due to a

slightly improved economy

Execution of AMS

1

plan –

~854,000 advanced

meters installed during 2010; over 1.5 million

installed through December 2010

All CCNs filed with the PUCT; 13 of 14 CCNs

approved through December 2010

1

AMS –

Advanced Metering System

2

SMB –

small business; LCI –

large commercial and industrial

3

Billed volumes are on a 15-day lag therefore include impacts from the prior quarter

4

Latest twelve months

5

ERCOT’s peak demand growth per May CDR for the period of 2010 to 2015

Residential

SMB & LCI²

23,187

3,145

3,171

1%

LTM

4

Electricity distribution points of delivery

End of period, thousands of meters

Q4 10

Q3 10

3,167

3,171

24,568

103,376

109,323

9%

FY

Q4 09

FY 09

FY 10

Q4 2010 Results

Higher SMB & LCI energy volumes due to

improved economy

Execution of AMS

1

plan –

~171,000 advanced

meters installed during Q4 10

2 Certificates of Convenience and Necessity

(CCNs) approved by the Public Utility

Commission of Texas (PUCT)

6%

QTR

4%

FY

11

Ending Liquidity Walkforward

1

($ in billions)

2010 Ending Liquidity Walkforward

2009A –

2010A

3.7

3.2

1

Values may not foot due to rounding.

2

Free

Cash

Flow

defined

as

Operating

activities

plus

Investing

activities

excluding

changes

in

restricted

cash,

plus

Financing

activities

excluding

issuances

and

repayments

of

debt

and

changes

in

short

term

borrowings.

See

Table

4

for

Free

Cash

Flow

reconciliation.

Under liability

management

program: cash

repurchases net of

issuances

Amortization /

Maturities

Dec -

09

Dec -

10

LC Requirements

Free Cash Flow

2

Repayment of AR

12

12

12

Commodity Prices

Commodity

Units

Q4 09 Actual

Q4 10 Actual

YTD 10 Actual

11E

1

NYMEX gas price

2

$/MMBtu

$4.26

$3.78

$4.37

$4.55

HSC gas price

$/MMBtu

$4.25

$3.75

$4.34

$4.49

7x24 market heat rate (HSC)

3

MMBtu/MWh

7.52

7.70

8.34

7.93

North Hub 7x24 power price

$/MWh

$31.68

$28.64

$36.07

$35.59

TCEH weighted avg. hedge price

4

$/MMBtu

$8.07

$7.81

$7.80

$7.56

Gulf Coast ultra-low sulfur diesel

$/gallon

$1.96

$2.34

$2.15

$2.59

PRB 8400 coal

$/ton

$7.18

$9.80

$9.76

$11.03

LIBOR interest rate

5

percent

0.52%

0.45%

0.52%

0.78%

Commodity prices

Q4 09, Q4 10, YTD 10 and 11E; mixed measures

1

BOY 11 estimate based on commodity prices as of 12/31/10 for January 1, 2011 through December 31, 2011

2

Based on NYMEX forward curve

3

Based on ERCOT market clearing price for North Hub 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.

13

13

Unrealized Mark-To-Market Impact Of Hedging

Unrealized mark-to-market impact of hedging program

12/31/10 vs. 9/30/10; mixed measures, pre-tax

Factor

Measure

2010

2011

2012

2013

2014

Total or

Avg.

9/30/10

Natural gas hedges

mm MMBtu

~84

~315

~454

~285

~112

~1,250

Wtd. avg. hedge price¹

$/MMBtu

~$7.82

~$7.56

~$7.36

~$7.19

~$7.80

Natural gas prices

$/MMBtu

~$3.94

~$4.44

~$5.07

~$5.29

~$5.42

Cum. MtM gain at 9/30/10²

$ billions

~$0.4

~$1.2

~$1.1

~$0.5

~$0.4

~$3.6

12/31/10

Natural gas hedges³

mm MMBtu

-

~220

~398

~282

~110

~1,010

Wtd. avg. hedge price¹

$/MMBtu

-

~$7.56

~$7.36

~$7.19

~$7.80

Natural gas prices

$/MMBtu

-

~$4.55

~$5.08

~$5.33

~$5.49

Cum. MtM gain at 12/31/10²

$ billions

~$0

~$1.2

~$1.1

~$0.5

~$0.4

~$3.2

Q4 10 MtM (loss) gain

$ billions

~$(0.4)

~$0.0

~$0.0

~$0.0

~$0.0

~$(0.4)

Forward positions in the hedge program slightly lost value due to higher natural gas prices at the end of

Q4, while additional losses resulted  from the reversal of previously recognized gains in the current

period, resulting in a ~$400 million (~$260 million after tax) unrealized net loss.

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.

12/31/10

prices

for

2011

represent

January

1,

2011

through

December

31,

2011

values.

2

MtM

values

include

the

effects

of

all

transactions

in

the

long-term

hedging

program

including

offsetting

purchases

(for

re-balancing)

and

natural

gas

basis

deals.

3

As

of

12/31/10.

2011

represents

January

1,

2011

through

December

31,

2011

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

110

million

MMBtu

in

2014.

14

14

TCEH Natural Gas Exposure

TCEH Natural Gas Position

11-14

1

; million MMBtu

Hedges Backed by Asset First Lien

Open Position

1

As

of

12/31/10.

Balance

of

2011

is

from

February

1,

2011

to

December

31,

2011.

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.

2011

position

includes

~8

million

MMBtu

of

short

gas

positions

associated

with

proprietary

trading

positions;

excluding

these

positions,

2011

position

is

~97%

hedged.

295

117

27

5

290

282

110

198

108

7

80

303

488

500

595

612

603

BAL 11

2012

2013

2014

Factor

Measure

BAL 11

2012

2013

2014

Total or

Average

Natural gas hedging program

million

MMBtu

~198

~398

~282

~110

~988

TXUE and Luminant net positions

million

MMBtu

~295

~117

~27

~5

~444

Overall estimated percent of total NG

position hedged

percent

~99%

~87%

~51%

~19%

~62%

TXUE and Luminant Net Positions²

TCEH

has

hedged

approximately

62%

of

its

estimated

Henry

Hub-based

natural

gas

price

exposure

from

February

1,

2011

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.

Hedges Backed by CCP

15

15

15

EFH Corp. Adjusted EBITDA Sensitivities

Commodity

Percent Hedged at

December 31, 2010

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

~5

Texas gas vs. NYMEX Henry Hub price ($/MMBtu)

3,4

>95

$0.10/MMBtu

~1

Diesel ($/gallon)

5

~100

$1/gallon

~0

Base coal ($/ton)

6

>95

$5/ton

~2

Generation operations

Baseload generation (TWh)

n.a.

1 TWh

~15

Retail operations

FY 2011

Residential contribution margin ($/MWh)

26 TWh

$1/MWh

~25

Residential consumption

26 TWh

1%

~11

Business markets consumption

24 TWh

1%

~4

Impact on EFH Corp. Adjusted EBITDA

1

11E; mixed measures

The majority of 2011 commodity-related risks are significantly mitigated.

1

2011

estimate

based

on

commodity

positions

as

of

12/31/10,

net

of

long-term

hedges

and

wholesale/retail

effects,

excludes

gains

and

losses

incurred

prior

to

December

31,

2010.

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

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.

Current Maturity Profile

EFH Corp. debt maturities

1

(excluding Oncor), 2011-2021 and thereafter

As of 12/31/10; $ millions

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.

16

17

Today’s Agenda

Q&A

Financial and Operational

Overview

Q4 2010 Review

John Young

President & CEO

18

Today’s Agenda

Q&A

Financial and Operational

Overview

Q4 2010 Review

EFH Corp. Senior Executive Team

19

Questions & Answers

20

Appendix –

Additional Slides and

Regulation G Reconciliations

Appendix

2,700

1,440

1,125

1,250

261

989

1,534

Facility Limit

LOCs/Cash Borrowings

Availability

EFH Corp. Liquidity Management

21

Cash and Equivalents

TCEH

Letter

of

Credit

Facility

TCEH

Revolving

Credit

Facility

2,114

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

$94

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

$135

million

of

requested

draws

not

funded

by

the

Lehman

subsidiary.

3

Total

capacity

remaining

for

natural

gas

hedges

under

the

CCP

facility

is

~420

million

MMBtu

of

which

TCEH

currently

has

~329

million

MMBtu

of

hedges

outstanding.

EFH Corp. (excluding Oncor) available liquidity

As of 12/31/10; $ millions

Liquidity reflected in the table

does not include the unlimited

capacity available under the

Commodity Collateral Posting

Facility

for

~329

million

MMBtu³

of

natural gas hedges outstanding.

1

2

3,235

Historical 2014 Forward Natural Gas Prices

Historical 2014 Forward Houston Ship Channel (HSC) Gas Prices

Q1’07-Q4’10; $/MMBtu

$7.18

$7.37

$7.10

$8.12

$8.71

$10.92

$8.09

$6.96

$6.95

$7.23

$7.05

$6.73

$6.27

$5.97

$5.28

$5.36

$4

$5

$6

$7

$8

$9

$10

$11

$12

Q1'07

Q2'07

Q3'07

Q4'07

Q1'08

Q2'08

Q3'08

Q4'08

Q1'09

Q2'09

Q3'09

Q4'09

Q1'10

Q2'10

Q3'10

Q4'10

22

23

23

Unrealized Mark-To-Market Impact Of Hedging

Unrealized mark-to-market impact of hedging program

12/31/10 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 price¹

$/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 12/31/09²

$ billions

~$0.8

~$0.4

~$0.4

~$0.2

~$0.2

~$2.0

12/31/10

Natural gas hedges³

mm MMBtu

-

~220

~398

~282

~110

~1,010

Wtd. avg. hedge price¹

$/MMBtu

-

~$7.56

~$7.36

~$7.19

~$7.80

Natural gas prices

$/MMBtu

-

~$4.55

~$5.08

~$5.33

~$5.49

Cum. MtM gain at 12/31/10²

$ billions

~$0

~$1.2

~$1.1

~$0.5

~$0.4

~$3.2

YTD10 MtM (loss) gain

$ billions

~($0.8)

~$0.8

~$0.7

~$0.3

~$0.2

~$1.2

Forward positions in the hedge program gained value due to lower natural gas prices as of the end of

2010, partially offset by losses resulting from the reversal of previously recognized gains during the year. 

Overall result for the year was a ~$1.2 billion (~$780 million after tax) unrealized net gain.

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.

12/31/10

prices

for

2011

represent

January

1,

2011

through

December

31,

2011

values.

2

MtM

values

include

the

effects

of

all

transactions

in

the

long-term

hedging

program

including

offsetting

purchases

(for

re-balancing)

and

natural

gas

basis

deals.

3

As

of

12/31/10.

2011

represents

January

1,

2011

through

December

31,

2011

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

110

million

MMBtu

in

2014.

24

Currently Installed

1

Environmental Control Equipment At

Luminant Coal Units

Coal Unit

Capacity

(MW)

FGD

(Scrubber)

2

Activated

Carbon

Injection³

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. 

Key Drivers

2011 Est. Impact vs

2010 (millions)

Assumptions

Higher Baseload

Generation

$50 -

$60

3 –

4 incremental TWh from new lignite units

~$15 / MWh average incremental margin¹

Nuclear Outage

$50 -

$60

2 refueling outages in 2011 vs 1 in 2010 and

related outage expenses 

Mining / Expenses

$60 -

$70

Higher emissions control costs (~$25mm)

Higher lignite costs driven by aging deposits

Higher healthcare, pension/OPEB expenses

Commodity

$200 -

$300

Lower

weighted

average

NG

hedge

price²

of

~$0.22 -

$0.25/mmbtu for ~540 mm mmbtu

Higher

heat

rate

of

~0.10

–

0.15

on

~73

-

75

TWh³

Impact of normal weather & load related costs on

2011 asset management margins relative to 2010

Delivered PRB prices up ~$4/ton on ~14 mm tons

Retail

$25 -

$125

Potential decline driven by lower customer count,

price environment and normal weather in 2011

Development

$50 -

$70

Reduced non-core asset sales in 2011

2010 TCEH

Adjusted EBITDA

$3,689

FY

12/31/10

2011 TCEH Adjusted EBITDA (non-GAAP) Key Drivers

1

Based on ERCOT North Hub 7X24 HSC power prices for 2011 of ~$33/MWh as of 9/30/10.

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).

3

Excludes volume committed under a long term purchase contract.

25

Illustrative for discussion purposes

2011 TCEH Open EBITDA (non-GAAP) Estimate

$800 - $1,400

2011E

1

Open

EBITDA

estimates

assume

generation

is

sold

at

market

observed

forward

prices

less

production

costs

and

retail

volumes

are

sold

at

market

observed

retail

rates

and

historical

retail

profitability

percentage.

Estimates

exclude

all

impacts

of

natural

gas

and

power

hedging

activities,

specifically

the

impacts

of

the

TCEH

Long-Term

Hedging

Program

and

any

heat

rate

hedges.

Additionally,

this

calculation

includes

provisions

for

fuel

expense

and

O&M

based

on

expected

power

generation

output

along

with

purchased

power

for

sales

to

retail

customers,

and

SG&A

based

on

the

generation

output

and

sales

to

retail

customers.

See

Appendix

for

Regulation

G

definition.

2

Estimated

wholesale

power

prices

for

2011

is

based

on

average

ERCOT

North

Hub

prices

as

of

9/30/10.

3

Includes

fuel

(excluding

nuclear

fuel

amortization),

O&M

and

SG&A

expenses

4

Based

on

an

10¢

/

kWh

average

residential

new

offer

pricing

as

reflected

on

thewww.powertochoose.org

and

$

2.3

billion

of

small

and

large

business

revenue

based

on

trailing

12

months.

5

Calculation

assumes

a

35%

overall

tax

rate

Assumptions

Units

2011E

Wholesale

Total baseload generation

TWh

78 –

81

Estimated

power

price

2

$/MWh

$32 -

$34

Average

baseload

cost

3

$/MWh

$26 -

$28

Retail

Revenues

4

$

$4.8 -

$5.2B

Profitability

percentage

(after

tax)

5

%

5-10%

TCEH Open EBITDA (non-GAAP)¹

Estimate

11E: $ millions

Open EBITDA does not

include:

•

TXU Energy value

proposition relative to

competitors

•

Asset management results

•

Long-term wholesale

contracts with load serving

entities

26

27

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.

28

Table 1: EFH Corp. Adjusted EBITDA Reconciliation

Three and Twelve Months Ended December 31, 2009 and 2010

$ millions

Note: Table and footnotes to this table continue on following page  

Factor

Q4 09

Q4 10

FY 09

FY 10

Net income (loss) attributable to EFH Corp.

137

161

344

(2,812)

Income tax expense

113

54

367

389

Interest expense and related charges

776

465

2,912

3,554

Depreciation and amortization

467

363

1,754

1,407

EBITDA

1,493

1,043

5,377

2,538

Adjustments to EBITDA (pre-tax):

-

Oncor EBITDA

(310)

-

(1,354)

-

Oncor distributions

99

28

216

169

Interest income

(15)

(2)

(45)

(10)

Amortization of nuclear fuel

28

38

101

140

Purchase accounting adjustments¹

83

51

340

210

Impairment of goodwill²

-

-

90

4,100

Impairment of assets and inventory write-down

37

12

42

15

Net gain on debt exchange offers

(87)

(648)

(87)

(1,814)

Net income attributable to noncontrolling interests

10

-

64

-

Equity in earnings of unconsolidated subsidiary

-

(37)

-

(277)

EBITDA amount attributable to consolidated unrestricted

subsidiaries

-

1

3

1

Unrealized net (gain) loss resulting from hedging transactions

(513)

394

(1,225)

(1,221)

Amortization of ”day one”

net loss on Sandow 5 power purchase

agreement

(3)

(3)

(10)

(22)

Losses on sale of receivables

3

-

12

-

29

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

noncash

goodwill

impairment

recorded

in

the

third

quarter

of

2010

and

the

completion

in

the

first

quarter

of

2009

of

the

fair

value

calculation

supporting

the noncash 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

2007

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

2010

includes

a

gain

on

termination

of

a

long-term

power

sales

contract.

2009

includes

reversal

of

certain

liabilities

accrued

in

purchase

accounting.

8

Reflects noncapital outage costs.

Table 1: EFH Adjusted EBITDA Reconciliation (continued from previous page)

Three and Twelve Months Ended December 31, 2009 and 2010

$ millions

Factor

Q4 09

Q4 10

FY 09

FY 10

Noncash compensation expense³

2

5

11

18

Severance expense

4

1

1

10

4

Transition and business optimization costs

5

-

6

22

4

Transaction and merger expenses

6

16

11

81

48

Restructuring and other

7

(3)

(118)

(14)

(117)

Expenses incurred to upgrade or expand a generation station

8

-

-

100

100

EFH Corp. Adjusted EBITDA per Incurrence Covenant

841

782

3,734

3,886

Add Oncor Adjusted EBITDA (reduced by Oncor distributions)

197

301

1,123

1,354

EFH Corp. Adjusted EBITDA per Restricted Payments Covenant

1,038

1,083

4,857

5,240

30

Table 2: TCEH Adjusted EBITDA Reconciliation

Three and Twelve Months Ended December 31, 2009 and 2010

$ millions

Note: Table and footnotes continue on following page  

Factor

Q4 09

Q4 10

FY 09

FY 10

Net income (loss)

216

263

709

(3,383)

Income tax expense

117

142

447

402

Interest expense and related charges

502

320

1,833

2,837

Depreciation and amortization

310

353

1,172

1,380

EBITDA

1,145

1,078

4,161

1,236

Adjustments to EBITDA (pre-tax):

Interest income

(24)

(26)

(64)

(91)

Amortization of nuclear fuel

28

38

101

140

Purchase accounting adjustments¹

71

39

293

163

Impairment of goodwill²

-

-

70

13

Impairment of assets and inventory writedown

34

12

36

4,100

Net gain on debt exchange offers

-

(687)

-

(687)

EBITDA amount attributable to consolidated unrestricted subsidiaries

-

1

3

1

Unrealized net (gain) loss resulting from hedging transactions

(513)

394

(1,225)

(1,221)

Amortization of ”day one”

net loss on Sandow 5 power purchase

agreement

(3)

(3)

(10)

(22)

Corp. depreciation, interest and income tax expense included in SG&A

1

-

6

9

Losses on sale of receivables

3

-

12

-

Noncash compensation expense³

-

3

1

14

Severance expense

4

1

-

10

3

Transition and business optimization costs

5

3

7

25

9

Transaction and merger expenses

6

2

9

5

38

31

Table 2: TCEH Adjusted EBITDA Reconciliation (continued from previous page)

Three and Twelve Months Ended December 31, 2009 and 2010

$ 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

Reflects

the

noncash

goodwill

impairment

recorded

in

the

third

quarter

of

2010

and

the

completion

in

the

first

quarter

of

2009

of

the

fair

value

calculation

supporting

the noncash 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 2007 merger, outsourcing transition costs and costs related to certain growth initiatives.

7

2010 includes a gain on termination of a long-term power sales contract. 2009 includes reversal of certain liabilities accrued in purchase accounting.

8

Reflects noncapital outage costs.

9

Primarily pre-operating expenses related to Oak Grove and Sandow 5 generation facilities.

Factor

Q4 09

Q4 10

FY 09

FY 10

Restructuring and other

7

(3)

(116)

(19)

(116)

Expenses incurred to upgrade or expand a generation station

8

-

-

100

100

TCEH Adjusted EBITDA per Incurrence Covenant

745

749

3,505

3,689

Expenses related to unplanned generation station outages

30

10

91

132

Other adjustments allowed to determine Adjusted EBITDA per

Maintenance Covenant

9

17

10

38

29

TCEH Adjusted EBITDA per Maintenance Covenant

792

769

3,634

3,850

32

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 Twelve Months Ended December 31, 2009 and 2010

$ millions

Factor

Q4 09

Q4 10

FY 09

FY 10

Net income

48

48

320

352

Income tax expense

33

41

173

215

Interest expense and related charges

88

88

346

347

Depreciation and amortization

152

166

557

673

EBITDA

321

343

1,396

1,587

Interest income

(11)

(9)

(43)

(38)

Purchase accounting adjustments¹

(9)

(8)

(39)

(34)

Transition and business optimization costs

(6)

3

25

8

Oncor Adjusted EBITDA

295

329

1,339

1,523

33

Table 4: EFH Free Cash Flow

1

Reconciliation

Twelve Months Ended December 31, 2010

$ millions

Factor

FY 10

Cash provided by operating activities

1,106

Cash used in investing activities

(468)

Other changes in restricted cash

33

Cash used in financing activities

(264)

Issuances of long-term debt

(853)

Repayments of long-term debt

1,351

Net short-term borrowings under accounts receivable securitization program

(96)

Increase (decrease) in other short-term borrowings

(172)

Free Cash Flow

637

1

Free Cash Flow defined as Operating activities plus Investing activities excluding changes in restricted cash, plus Financing activities excluding issuances and

repayments of debt and changes in short term borrowings.