EFH Corp.

Q4 2012 Investor Call

February 19, 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.  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

Paul Keglevic

Executive Vice President & CFO

Financial and Operational

Overview

Q4 2012 Review

Q&A

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

Q4

1

11 vs. Q4 12; $ millions, after tax

1

Three months ended December 31.

2

Items are noncash except settlement of Oncor management incentive pay plan.

3

Charges reflect reversal of $32 million of severance accruals due to judicial stay of CSAPR recorded in other deductions and $14 million of incremental depreciation expense.

EFH Corp.

3

Factor

Q4 11

Q4 12

Change

EFH Corp. GAAP net income (loss)

(136)

(1,952)

(1,816)

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

Unrealized commodity-related mark-to-market net (gain) loss

(196)

152

348

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

(44)

(120)

(76)

Net credit related to EPA Cross State Air Pollution Rule

(18)

-

18

Debt extinguishment gains –

debt exchanges and repurchases

(17)

-

17

Goodwill impairment

-

1,200

1,200

Charges related to pension plan actions

-

183

183

Writedown of equipment from cancelled generation projects

-

23

23

Oncor inventory write off

4

-

(4)

Settlement of Oncor management incentive pay plan

-

31

31

EFH Corp. adjusted (non-GAAP) operating loss

(407)

(483)

(76)

2

3

Adjusted (Non-GAAP) Operating Results - QTR

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

Q4 11 vs. Q4 12; $ millions, after tax

EFH Corp.

Adjusted

(Non-GAAP)

Operating

Results

Key

Drivers

(after

tax)

-

QTR

Description/Drivers

Better (Worse)  

Than 

Q4 11

Competitive Business

:

Lower net margin from asset management and retail activities, including the effects of milder weather

(22)

Higher coal generation partially offset by lower nuclear generation both due to the effects of planned and unplanned outages

5

All

other

-

net

(1)

Contribution margin    

(18)

Lower income tax benefit due to true-up to filed returns

(41)

Higher net interest expense driven by higher average rates

(33)

Lower SG&A driven by employee-related costs and retail marketing and related expenses

9

Lower retail bad debt expense reflecting improved customer care processes and customer mix

5

All

other

-

net

6

Total

change

-

Competitive Business

(72)

Regulated Business:

Higher net revenues reflecting transmission and distribution tariff increases, automated meter surcharges and growth in points of delivery

17

Higher revenues from transmission cost recovery charges

10

Higher depreciation and amortization reflecting infrastructure investment

(10)

Lower revenues primarily due to milder weather

(6)

Higher 3rd party transmission fees

(5)

Higher net interest expense driven by increased borrowings

(5)

All

other

-

net

(5)

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

(4)

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

(76)

1

Competitive Business consists of Competitive Electric segment and Corporate and Other.

4

1

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

FY

1

11

vs.

FY

12;

$

millions,

after

tax

EFH Corp.

Adjusted (Non-GAAP) Operating Results -

FY

5

Factor

FY 11

FY 12

Change

EFH Corp. GAAP net loss

(1,913)

(3,360)

(1,447)

Items

excluded

from

adjusted

(non-GAAP)

operating

results

(after

tax)

2

Unrealized commodity-related mark-to-market net (gain) loss

(37)

983

1,020

Unrealized mark-to-market net (gain) loss on interest rate swaps

528

(112)

(640)

Charges

related

to

EPA

Cross

State

Air

Pollution

Rule

3

304

-

(304)

Third-party fees associated with April 2011 TCEH debt amendment and extension transactions

64

-

(64)

Debt extinguishment gains –

debt exchanges and repurchases

(33)

-

33

Gain related to counterparty bankruptcy settlement

(14)

-

14

Goodwill impairment

-

1,200

1,200

Charges related to pension plan actions

-

183

183

Writedown of equipment from cancelled generation projects and mineral interest assets

-

43

43

Settlement of Oncor management incentive pay plan

-

31

31

Oncor inventory write off

4

-

(4)

Income tax charges

4

13

-

(13)

EFH Corp. adjusted (non-GAAP) operating loss

(1,084)

(1,032)

52

1

2

3

4

Full year ended December 31.

Items are noncash except for fees associated with TCEH amendment and extension debt transactions, gain related to counterparty bankruptcy settlement, Oncor management

incentive pay plan settlement, and the 2011 state income tax charge associated with TCEH amendment and extension debt transactions.

Includes, net of tax, $269 million of emission allowances impairments and $6 million of mining asset impairments recorded in other deductions, and $28 million of incremental

FY 2011 state income tax charges recorded as a result of TCEH amendment and extension transaction.

depreciation expense.

Description/Drivers

Better (Worse) 

Than

FY 11

Competitive Business:

Higher net margin from asset management and retail activities, net of effects of milder weather

52

Lower amortization of intangibles arising from purchase accounting

43

Lower results from coal generation driven by higher fuel prices

(10)

All

other

-

net

4

Contribution margin    

89

Lower depreciation reflecting increased useful lives and retirements of certain generation assets

53

Lower SG&A driven by employee-related costs and retail marketing and related expenses

25

Lower operating costs reflecting one nuclear unit refueling outage in 2012 vs. two units in 2011 and lower systems and process improvement costs

23

Lower retail bad debt expense reflecting improved customer care processes and customer mix

19

Higher net interest expense driven by higher average rates

(129)

Lower income tax benefit due to true-up to filed returns

(37)

All

other

-

net

(2)        

Total

change

-

Competitive

Business

41

Regulated Business:

114

Higher revenues from transmission cost recovery charges

70

Lower consumption primarily due to weather

(50)

Higher 3rd party transmission fees

(41)

Higher depreciation and amortization reflecting infrastructure investment

(33)

Higher net interest expense driven by increased borrowings

(15)

(12)

Higher taxes other than income driven by higher franchise fees and property tax rates

(10)

All

other

–

net,

primarily

driven

by

change

in

effective

tax

rate

(12)

Total

change

-

Regulated

Business

(~80%

owned

by

EFH

Corp.)

11

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

52

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

FY 11 vs. FY 12; $ millions, after tax

EFH Corp.

Adjusted

(Non-GAAP)

Operating

Results

Key

Drivers

(after

tax)

-

FY

6

Higher operation and maintenance expense due to regulatory asset amortization and outside services and vegetation management costs

Higher net revenues reflecting transmission and distribution tariff increases, including advanced meter surcharges and growth in points of delivery

EFH Corp. Adjusted EBITDA (Non-GAAP)

EFH

Corp.

Adjusted

EBITDA

(non-GAAP)

1

Q4

2

11 vs. Q4 12 and FY

3

11 vs. FY 12;

$ millions

Q4 12

Q4 11

1,035

1,005

642

629

393

369

TCEH 

Oncor

7

7%

FY 12

FY 11

5,257

5,036

3,496

3,368

1,747

1,639

2%

4%

4%

7%

3%

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

operating results

1

See Appendix for Regulation G reconciliations and definition. Includes $7 million, $29 million and $14 million in Q4 11, FY 11 and FY 12, respectively, of Corp. & Other

Adjusted EBITDA.

2

Three months ended December 31.

3

Full year ended December 31.

Luminant Operational Results

8

Nuclear-fueled generation; GWh

Coal-fueled generation; GWh

Q4 and FY12 Nuclear Plant Results

Solid safety performance

Q4 –

lower generation with extended

refueling outage and unplanned outage

FY –

higher generation due to one less

refueling outage in 2012

Top decile industry performance for

reliability and cost

Q4 12

Q4 11

4,736

19,283

FY 11

FY 12

19,897

4,125

FY 11

Q4 11

13,368

13,070

49,298

58,165

Q4 12

FY 12

3%

FY

15%

FY

Q4 and FY 12 Coal-Fueled Plant Results

Q4 –

1.2 TWh higher generation due to less

planned outages and improved reliability,

partially offset by 0.9 TWh of lower

generation due to seasonal operations at

Monticello units

FY –

8.9 TWh lower generation as a result

of 5.3 TWh of higher economic backdown

and 3.6 TWh from more outage days and

seasonal operations at Monticello units

13%

QTR

2%

QTR

9

Q4 2012 Results

Sales volumes declined 10% reflecting a

decline in business volumes, lower

residential customer counts and milder

weather

Residential attrition rates improved 48%

compared to Q4 2011.  Best performance

since 2009

TXU Energy Operational Results

Total residential customers

End of period, thousands

Retail electricity sales volumes by customer class;

GWh

1,563

1,547

FY 11

SMB

LCI

Residential

Q4 11

9,219

47,224

Q4 11

Q3 12

5%

LTM

4

23,267

4,974

10,373

2,873

1,372

5,913

Q4 12

Q4 12

1,547

1,625

1%

QTR

27,337

12,828

7,059

4,591

2,480

1,220

39,553

8,291

Q4 12

FY 12

10%

QTR

16%

FY

FY 2012 Results

Residential attrition rate slowed to 4.8%,

a 42% improvement from 8.2% in 2011

Bad debt expense decreased by 53%

due to improved collection initiatives,

customer mix and lower revenues

Reduced PUC complaints to record low

levels, continuing top tier PUC complaint

performance

3

1

2

SMB

–

small

business.

LCI -

large commercial and industrial.

Excludes December 2012 acquisition of customers.

Last twelve months.

1

2

3

4

10

Oncor Operational Results

Electric energy billed volumes

4

; GWh

Q4 11

Q4 12

1

SMB –

small business; LCI –

large commercial and industrial.

2

AMS –

Advanced Metering System.

3

CREZ –

Competitive Renewable Energy Zone.

4

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

shown reflect partial impacts from prior quarters.

5

Last twelve months.

Residential

SMB & LCI

3,203

3,242

1%

LTM

5

Electricity distribution points of delivery

End of period, thousands of meters

Q4 12

Q3 12

3,232

3,242

Q4 2012 Results

Lower Q4 and FY 2012 Residential 

volumes principally due to milder

weather

Higher

Q4

2012

SMB

&

LCI

energy

volumes primarily due to customer

growth

Completed planned deployment of

AMS

plan

in

Q4

2012

–

~159,000

advanced meters installed during Q4

2012; over 3.2 million installed

through December 31, 2012

$1.460

billion

spent

on

CREZ

through December 31, 2012; $561

million spent in 2012

8%

FY

Q4 12

25,211

24,905

113,837

110,371

Q4 11

FY 11

FY 12

5%

QTR

1%

QTR

1

1

2

3

16,705

16,806

69,949

69,994

8,506

8,099

43,888

40,377

EFH Corp. Liquidity Management

As of January 31, 2013

11

Cash and Equivalents

TCEH Letter of Credit Facility

TCEH Revolving Credit Facility

3,116

EFH Corp. and TCEH continue to monitor capital market conditions

for opportunities to

maximize liquidity and financial flexibility

EFH Corp. (excluding Oncor) available liquidity

As of 1/31/13; $ millions

2,859

2,828

1,062

2,054

774

2,686

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

supports letters of credit, of which $774 million are outstanding, leaving $173 million available.

173

2,054

Facilities Limit

LOCs/Cash Borrowings

Availability

1

1

12

12

12

Commodity Prices

Commodity

Units

Q4 12

Actual

Q4 11

Actual

FY 12  

Actual

FY 11

Actual

13E

NYMEX gas price

$/MMBtu

3.39

3.31

2.75

3.98

3.54

HSC gas price

$/MMBtu

3.33

3.26

2.71

3.94

3.48

7x24 market heat rate (HSC)

MMBtu/MWh

7.89

8.27

9.53

10.62

9.83

North Hub 7x24 power price

$/MWh

26.19

27.04

25.17

42.44

34.28

TCEH weighted avg. hedge price

4

$/MMBtu

7.35

7.60

7.36

7.57

6.89

Gulf Coast ultra-low sulfur diesel

$/gallon

3.04

2.96

3.05

2.97

2.96

PRB 8400 coal

$/ton

8.68

10.97

7.57

11.00

9.41

LIBOR interest rate

5

percent

0.54%

0.68%

0.69%

0.51%

0.51%

Commodity prices

Q4 12, Q4 11, FY 12, FY 11 and 13E; mixed measures

2

3

1

1

1

FY 2012: Year ended December 31, 2012; FY 2011: Year ended December 31, 2011; 13E: 2013 estimate based on average of monthly commodity prices as of December 31, 2012

for January 2013 through December 2013.

The actual prices are computed based on settled Gas Daily prices for Henry Hub.

Daily average based on ERCOT Nodal market clearing price for North Hub.

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).

  

The index for the settled value is a 6-month LIBOR rate.

1

2

3

4

5

13

13

Unrealized Mark-To-Market Impact Of Hedging

Unrealized mark-to-market impact of hedging program

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

Factor

9/30/12

Natural gas hedges

Wtd. avg. hedge price

Natural gas prices

Cum. MtM gain at 9/30/12

12/31/12

Natural gas hedges

Wtd. avg. hedge price

Natural gas prices

Cum. MtM gain at 12/31/12

Q4 12 change in unrealized MtM (loss) gain

Measure

MM MMBtu

$/MMBtu

$/MMBtu

$ billions

MM MMBtu

$/MMBtu

$/MMBtu

$ billions

$ billions

2012

~74

~$7.35

~$3.32

~$0.4

-

-

-

-

~($0.4)

2013

~211

~$6.89

~$3.84

~$0.9

~211

~$6.89

~$3.54

~$1.0

~$0.1

2014

Total

~146

~431

~$7.80

~$4.18

~$0.6

~$1.9

~146

~357

~$7.80

~$4.03

~$0.6

~$0.0

1

2

3

1

4

2

~$1.6

~($0.3)

1

Weighted

average

prices

are

based

on

prices

of

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.

Prices

for

2013

represent

January

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

December

31,

2012.

2013

represents

January

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 January 1, 2013 through December 31, 2013.

Hedge program decrease is due to settlement of Q4 positions.  The forward value of the program

increased due to lower natural gas prices

14

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

~194            

~146

0

TXUE and LUME net positions

million MMBtu

~216

~43

~14

Overall estimated percent of

total NG position hedged

percent

~96%

~41%

~3%

TXUE and Luminant Net Positions

2

1

As of December 31, 2012. Balance of 2013 is from February 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

216

43

14

194

146

18

266

479

428

455

493

2014

2015

2013

TCEH has hedged approximately 96% of its estimated natural gas price exposure for 2013

15

15

15

EFH Corp. Adjusted EBITDA Sensitivities

Commodity

Percent Hedged at

December 31, 2012

Change

BOY 13E Impact

$ millions

7X24 market heat rate (MMBtu/MWh)

~84

0.1 MMBtu/MWh

~5

NYMEX gas price ($/MMBtu)

~96

$1/MMBtu

~18

Diesel ($/gallon)

~73

$1/gallon

~13

Base coal ($/ton)

4

~72

$2/ton

~6

Generation operations

Nuclear-

and coal / lignite-fueled generation (TWh)

N/A

1 TWh

~15

Retail operations

FY  2013

Residential contribution margin ($/MWh)

22 TWh

$1/MWh

~22

Residential consumption

22 TWh

1%

~8

Business markets consumption

17 TWh

1%

~2

Impact on EFH Corp. Adjusted EBITDA

1

13E; mixed measures

The majority of 2013 commodity-related risks are significantly mitigated

3

2

1

2013 estimate based on commodity positions as of December 31, 2012 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 December 31, 2012.

2

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).

3

Includes positions related to fuel surcharge on rail transportation.

4

Excludes fuel surcharge on rail transportation.

Estimate as of December 31, 2012; $ billions

(pro forma for January 2013 Revolver Extension and January 2013 Exchanges)

EFH / EFIH

TCEH

1

1st Lien

-

$0.41

2

2nd Lien

$0.25

$1.88

4

Total

$0.25

$2.29

Estimated Secured Debt Capacity at EFH / EFIH and TCEH

1

16

$0.25

$0.25

$2.29

$1.88

$0.41

2nd Lien

1st Lien

2

3

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.

17

Today’s Agenda

John Young

President & CEO

Financial and Operational

Overview

Q4 2012 Review

Q&A

HSC Natural Gas Futures

$/MMBtu

ERCOT North Hub ATC (7x24) Heat Rate

MMBtu/MWh

18

Forward Natural Gas Prices and Heat Rates

Forward gas prices have shown some indications of stabilizing. 

Near term heat rates have stabilized since Q2 2012

1

2014 prices became observable at year-end 2011.

2

2015 heat rate is an estimate based on limited broker quotes.

2015 HR

9.61

19

1

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

2

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

Resource Adequacy in ERCOT

ERCOT reserve margin

2013E-2018E; percent

December

2012

CDR

May

2012

CDR

13.75% target

reserve margin

Drivers of ERCOT December 2012 CDR

Report versus the May 2012 CDR Report

–

Reduced load growth rate based on Moody’s

“Low”

economic growth forecast

•

Increased 2013 load forecast by ~300

MW, but lowered 2014 load forecast by

~800 MW (~1.2% lower)

•

Reduced annual load growth rate for

the period 2013-2018 by ~1%

–

Reduced total resources by ~400 MW in 2013

(0.5%), with larger reductions after 2015

Recent and pending PUCT/ERCOT actions

and potential deliberations:

–

Increased system-wide offer cap to $5,000

effective June 1, 2013; $7,000 effective   

June1, 2014; and $9,000 effective June 1,

2015

–

ERCOT review of whether 13.75% is the

appropriate target reserve margin

–

Continued PUCT evaluation of long-term  

solution

14.3

9.8

6.9

6.5

5.8

5.8

13.2

10.9

10.5

8.5

8.4

7.1

'13

'14

'15

'16

'17

'18

1

2

EFH Corp.

$0.7B debt

Energy Future

Intermediate Holding

$7.5B debt

$6.3B debt

TCEH

$32.0B debt

Approx. 80% Ownership

$46.6B total gross debt

$43.0B total net debt

Ring-fenced entities

Texas

Transmission

Investment

LLC

Approx. 20%

Ownership

1

Gross debt excludes unamortized debt discounts and premiums, fair value discounts and premiums, and A/R securitization.

2

Total net debt equals total gross debt less total cash & cash equivalents and restricted cash of ~$3.6 billion (including adjustment for $13 million accrued interest paid in connection with the January 2013 exchange).

3

Excludes $82 million from A/R securitization.

4   

Excludes intercompany note balances.

5   

EFCH guarantees all of TCEH’s debt (other than Pollution Control Revenue Bonds).

EFH Capital Structure Overview

20

$4.0B

EFIH

6.875%

1

Lien

due

2017

EFIH

10.00%

1

Lien

due

2020

$0.4B

EFIH

11.00%

2

Lien

due

2021

$1.7B

EFIH

11.75%

2

Lien

due

2022

$1.4B

Unsecured

EFIH

11.25%/12.25%

Toggle

due

2018

$0.06B

EFH 10.875% LBO due 2017

EFH 11.25%  LBO due 2017

$0.6B

EFH 5.55% Series P due 2014

EFH 6.50% Series Q due 2024

EFH 6.55% Series R due 2034

$0.06B

EFH/EFIH Other Unsecured

$16.7B

1

Lien

Term

Loans

due

2017

$3.85B

1

Lien

Term

Loans

due

2014

$2.05B

1

Lien

Revolver

due

2016

$1.75B

11.5%

1

Lien

Notes

due

2020

$1.57B

15.0%

2

Lien

Notes

due

2021

$4.9B

10.25%

LBO

due

in

2015

10.50%

LBO

due

in

2016

$1.2B

Unsecured

PCRBs/Other

$0.74B

Revolver  @ L+125 bps due 2016

$5.12B

Long Term Debt @ avg. 6.1%

$0.44B

Securitization Debt @ avg. 5.3%

Energy Future

Competitive Holdings

5

$0.1B debt

1

2

3

4

st

st

nd

nd

st

st

st

st

nd

Balances

as

of

12/31/2012

Pro Forma for January 2013 Revolver

Extension and Debt Exchanges

21

Today’s Agenda

EFH Corp. Senior Executive Team

Financial and Operational

Overview

Q4 2012 Review

Q&A

22

Questions & Answers

23

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.

24

25

Table 1: EFH Corp. Adjusted EBITDA Reconciliation

Three and 12 Months Ended December 31, 2011 and 2012

$ millions

Factor

Q4 11

Q4 12

FY 11

FY 12

Net income (loss)

(136)

(1,952)

(1,913)

(3,360)

Income tax (benefit) expense

(92)

(353)

(1,134)

(1,232)

Interest expense and related charges

826

760

4,294

3,508

Depreciation and amortization

381

358

1,499

1,373

EBITDA

979

(1,187)

2,746

289

Adjustments to EBITDA (pre-tax):

Oncor Holdings distributions of earnings

52

47

116

147

Interest income

-

-

(2)

(2)

Amortization of nuclear fuel

38

32

142

156

Purchase

accounting

adjustments

22

-

204

74

Impairment of goodwill

-

1,200

-

1,200

Impairment

and

writedown

of

other

assets

4

39

433

48

Debt extinguishment gains

(26)

-

(51)

-

Equity in earnings of unconsolidated subsidiary

(51)

(20)

(286)

(270)

Unrealized net (gain) loss resulting from commodity hedging and trading transactions

(305)

236

(58)

1,526

EBITDA amount attributable to consolidated unrestricted subsidiaries

-

4

-

4

Noncash

compensation

expense

5

-

13

11

Transition and business optimization costs

4

9

4

39

35

Transaction and merger expenses

5

10

10

37

39

Restructuring and other

6

(49)

8

80

15

Charges related to pension plan actions

7

-

285

-

285

Expenses incurred to upgrade or expand a generation station

8

-

31

100

100

EFH Corp. Adjusted EBITDA per Incurrence Covenant

688

689

3,513

3,657

Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)

317

346

1,523

1,600

EFH Corp. Adjusted EBITDA per Restricted Payments Covenant

1,005

1,035

5,036

5,257

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.  2011

includes $46 million related to an asset sale.

2

Includes impairment of emissions allowances and certain mining assets due to EPA rule issued in July 2011.

3

Represents

amounts

recorded

under

stock-based

compensation

accounting

standards

and

excludes

capitalized

amounts.

4

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

5

Primarily represents Sponsor Group management fees.

6

Restructuring and other in 2011 includes gains on termination of

a long-term power sales contract and settlement of amounts due from a hedging/trading counterparty, fees related to the

amendment and extension of TCEH’s senior secured credit facilities and reversal of certain liabilities accrued in purchase accounting.

7

Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employees of EFH Corp’s competitive businesses and the

assumption

by

Oncor

under

a

new

Oncor

pension

plan

of

all

of

EFH

Corp’s

pension

obligations

to

retirees

and

terminated

vested

participants.

The

charges

represent

actuarial

losses

previously recorded as other comprehensive income.

8

Reflects noncapital costs related to planned outages.

1

2

3

26

Table 2: TCEH Adjusted EBITDA Reconciliation

Three and 12 Months Ended December 31, 2011 and 2012

$ millions

Factor

Q4 11

Q4 12

FY 11

FY 12

Net income (loss)

(80)

(1,695)

(1,740)

(2,948)

Income tax expense (benefit)

(43)

(224)

(917)

(894)

Interest expense and related charges

679

552

3,699

2,752

Depreciation and amortization

373

352

1,470

1,343

EBITDA

929

(1,015)

2,512

253

Adjustments to EBITDA (pre-tax):

Interest income

(21)

(10)

(87)

(46)

Amortization of nuclear fuel

38

32

142

156

Purchase

accounting

adjustments

10

1

157

55

Impairment of goodwill

-

1,200

-

1,200

Impairment

and

writedown

of

other

assets

3

5

430

6

Unrealized net (gain) loss resulting from commodity hedging and trading transactions

(305)

236

(58)

1,526

EBITDA amount attributable to consolidated unrestricted subsidiaries

(2)

2

(7)

(4)

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

5

4

16

17

Noncash

compensation

expense

4

(1)

12

7

Transition

and

business

optimization

costs

4

9

3

42

33

Transaction

and

merger

expenses

5

9

9

37

38

Restructuring

and

other

6

(50)

4

72

14

Charges

related

to

pension

plan

actions

7

-

141

-

141

Expenses

incurred

to

upgrade

or

expand

a

generation

station

8

-

31

100

100

TCEH Adjusted EBITDA per Incurrence Covenant

629

642

3,368

3,496

Expenses related to unplanned generation station outages

19

18

181

78

Pro

forma

adjustment

for

Oak

Grove

2

reaching

70%

capacity

in

Q2

2011

9

(5)

-

27

-

Other

adjustments

allowed

to

determine

Adjusted

EBITDA

per

Maintenance

Covenant

10

-

-

8

-

TCEH Adjusted EBITDA per Maintenance Covenant

643

660

3,584

3,574

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.

2011

includes $46 million related to an asset sale.

2

Includes impairment of emissions allowances and certain mining assets due to EPA rule issued in July 2011.

3

Includes

expenses

recorded

under

stock-based

compensation

accounting

standards

and

excludes

capitalized

amounts.

4

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

5

Primarily represents Sponsor Group management fees.

6

Restructuring

and

other

in

2011

includes

gains

on

termination

of

a

long-term

power

sales

contract

and

settlement

of

amounts

due

from

a

hedging/trading

counterparty,

fees

related

to

the

amendment and extension of TCEH’s senior secured credit facilities and reversal of certain liabilities accrued in purchase accounting.

7

Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employees of EFH Corp’s competitive businesses and the

assumption

by

Oncor

under

a

new

Oncor

pension

plan

of

all

of

EFH

Corp’s

pension

obligations

to

retirees

and

terminated

vested

participants.

The

charges

represent

actuarial

losses

previously recorded as other comprehensive income.

8

Reflects noncapital costs related to planned outages.

9

Represents the annualization of the of the actual nine months ended December 31, 2011 EBITDA results for Oak Grove 2, which achieved the requisite 70% average capacity factor in the

second quarter 2011.

10

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

1

2

3

27

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 12 Months Ended December 31, 2011 and 2012

$ millions

Factor

Q4 11

Q4 12

FY 11

FY 12

Net income

65

28

367

349

Income tax expense

32

21

229

234

Interest expense and related charges

94

95

359

374

Depreciation and amortization

179

194

719

771

EBITDA

370

338

1,674

1,728

Interest income

(7)

-

(32)

(24)

Purchase accounting adjustments

(7)

(5)

(29)

(23)

Noncash compensation expense

1

-

7

2

Transition and business optimization costs and other

4

1

11

5

Inventory write-down

8

-

8

-

Settlement of management incentive pay plan

-

59

-

59

Oncor Adjusted EBITDA

369

393

1,639

1,747

1

28

Table 4: EFH Corp. Adjusted EBITDA Reconciliation

Year

Ended

December

31,

2008

-

2012

$ 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

2008 and 2011 include impairment of emissions allowances. 2008 also includes impairment of trade name intangible assets, land and the natural gas-fueled generation fleet and charges related to cancelled

development of coal-fueled generation facilities.

3

Represents

amounts

recorded

under

stock-based

compensation

accounting

standards

and

excludes

capitalized

amounts.

4

Includes

professional

fees

and

other

costs

related

to

retail

billing

and

customer

care

systems,

generation

plant

reliability

and

supply

chain

efficiency

initiatives

as

well

as

incentive

compensation

expenses.

5

Includes

costs

related

to

the

Merger,

abandoned

strategic

transactions,

certain

growth

initiatives

and

Oncor’s

sale

of

noncontrolling

interests,

outsourcing

transition

costs

and

Sponsor

Group

management

fees.

6

2008 includes litigation accrual, charge related to a counterparty bankruptcy and losses on sale of receivables, net of insurance settlement proceeds. 2009 includes reversal of certain liabilities accrued in purchase

accounting, partially offset by restructuring and nonrecurring activities and losses on sale of receivables. 2010 includes a gain on termination of a long-term power sales contract. 2011 includes settlement of amounts

due

from

counterparty

bankruptcy,

fees

related

to

the

amendment

and

extension

of

the

TCEH

Senior

Secured

Facilities

and

reversal

of

certain

liabilities

accrued

in

purchase

accounting. 

7

Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employees of EFH Corp’s competitive businesses and the assumption by Oncor under a new

Oncor pension plan of all of EFH Corp’s pension obligations to retirees and terminated vested participants.  The charges represent actuarial losses previously recorded as other comprehensive income.

8

Reflects noncapital costs related to planned outages.

Factor

2008

2009

2010

2011

2012

Net income (loss)

(9,838)

344

(2,812)

(1,913)

(3,360)

Income tax (benefit) expense

(471)

367

389

(1,134)

(1,232)

Interest expense and related charges

4,935

2,912

3,554

4,294

3,508

Depreciation and amortization

1,610

1,754

1,407

1,499

1,373

EBITDA

(3,764)

5,377

2,538

2,746

289

Oncor EBITDA

(496)

(1,354)

-

-

-

Oncor Holdings distributions (2008 includes $1.253 billion sale of Oncor equity)

1,582

216

169

116

147

Interest income

(27)

(45)

(10)

(2)

(2)

Amortization of nuclear fuel

76

101

140

142

156

Purchase accounting adjustments

460

340

210

204

74

Impairment of goodwill

8,000

90

4,100

-

1,200

Impairment and writedown of other assets

1,221

42

15

433

48

Debt extinguishment gains

-

(87)

(1,814)

(51)

-

Net income (loss) attributable to noncontrolling interests

(160)

64

-

-

-

Equity in earnings of unconsolidated subsidiary

-

-

(277)

(286)

(270)

Unrealized net (gain) loss resulting from commodity hedging and trading transactions

(2,329)

(1,225)

(1,221)

(58)

1,526

EBITDA amount attributable to consolidated unrestricted subsidiaries

-

-

-

-

4

Amortization of “day one”

net loss on Sandow power purchase agreement

-

(10)

(22)

-

-

Noncash compensation expense

27

11

18

13

11

Transition and business optimization costs

4

45

22

4

39

35

Transaction and merger expenses

5

64

81

48

37

39

Restructuring and other

6

46

11

(112)

80

15

Charges related to pension plan actions

7

-

-

-

-

285

Expenses incurred to upgrade or expand a generation station

8

100

100

100

100

100

EFH Corp. Adjusted EBITDA per Incurrence Covenant

4,845

3,734

3,886

3,513

3,657

Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)

(267)

1,123

1,354

1,523

1,600

EFH Corp. Adjusted EBITDA per Restricted Payments Covenant

4,578

4,857

5,240

5,036

5,257

1

2

3

EFH Has Made Significant Accomplishments Despite Lower

Commodity Prices

29

Historical NYMEX spot natural gas prices

2007-2012; $/MMBtu

EFH sells

~20% interest

in Oncor

Sandow 5

complete

TXU Energy begins

customer care system

implementation

Oak Grove 2

complete

TCEH Amend

and Extend 

Oak Grove

1 complete

Merger

closes

Debt

Exchanges

Oncor

awarded

CREZ project

Oncor begins

AMS rollout

CSAPR

vacated

Revolver

Extension /

Exchanges

2007

2008

2009

2010

2011

2012

0

2

4

6

8

10

12

14

EFH Has Invested Over $10 Billion

And Added Nearly 1,900 Positions

Capital Investment

Amount

TCEH and Corporate

>$5

Oncor

>$5

Grand Total

>$10

Jobs

New employee positions added

~1,900

30

Capital investment and jobs

2008-2012; $ billions, positions added

Source: EFH 2012 and 2009 10K, Oncor 2012 10-K.

Luminant

invested

$3.25

billion

to

build

2,200 MWs

of

new

units

TXU

Energy

has

invested

$100 million

in

new

tools

and

products

for

customers

to

manage

their

own

electricity

usage

Oncor

has

invested

$1.46

billion

on

CREZ

and

$660 million

on

AMS

through

2012

31

Commitment

Fulfilled

Reorganize the company into three business units with separate boards, management teams and

headquarters.

Maintain headquarters for each business in the DFW area.

Hold

majority

ownership

in

EFH

Corp.

and

Oncor

for

at

least

five

years.

Create a Sustainable Energy Advisory Board (SEAB) to provide input from environmental, economic,

customer, reliability and technology viewpoints.

Ensure employee compensation, health benefits and retirement programs.

Deliver a 15% residential price cut to legacy PTB customers.

Guarantee price protection against changing market conditions through December 2008 for legacy PTB

customers.

Provide $150 million in low-income customer assistance over five years, through 2012 ($125 million, ~10%

discount for qualifying customers and $25 million in bill payment assistance).

Waive deposits for certain residential customers.

Form a new Low Income Advisory Committee (LIAC) comprising of leaders in the social service delivery

sector.

Invest $100 million over five years through 2012 in new tools for customers to manage their own electricity

usage through innovative energy efficiency and conservation approaches.

Merger

Commitments

Fulfilled

1

Refer to http://www.energyfutureholdings.com/responsibility/promises.aspx for further details.

1

Commitment

Fulfilled

Terminate eight planned coal units.

Provide increased investment in alternative energy.

Start planning process for two IGCC commercial demonstration plants to be located in Texas.

Offset 100% of key emissions from new coal-fueled power plants and reduce nitrogen oxide, sulfur dioxide

and mercury emissions by 20% from 2005 total levels from coal-fueled power plants through nation’s largest

voluntary emissions reduction program.

Double wind energy purchases to 1500 MW, maintaining status as the largest buyer of wind power in Texas.

Join the FutureGen Alliance.

Join USCAP.

Expedite voluntarily the company’s 14.101 filing.

Make minimum capital spend of $3.6 billion for five years, through 2012.

Implement aggressive demand-reduction program including an additional five-year, $100 million investment

in conservation and energy efficiency.

Implement no rate increases as a result of the transaction.

File no system-wide rate case until 2008.

Generate no new debt as a result of the transaction.

Limit debt so that Oncor’s debt-to-equity ratio is at or below the assumed debt-to-equity ratio established by

the PUC.

Agree to resolve all outstanding 14.101 issues.

Issue one-time, $72 million retail customer credit.

Provide annual reports to the PUC regarding commitments.

32

Merger Commitments Fulfilled (continued)

We Continue To Focus On Operational Excellence

33

Sustainable, Flexible, Dynamic Organization

Operational Excellence

Financial Optimization

Strategic Growth

Prudent financial

management

Optimize balance sheet

Optimize hedge platform

Identify and execute

internal / organic

opportunities

Seek external

opportunities

Maintain competitive

intelligence

Engage in key public

and governmental

affairs issues

Execute an aggressive

operational plan

Deliver top decile

results

Maintain a competitive

position in marketplace

Build infrastructure

Maintain and enhance

TXU brand

Identify and mitigate

operational risks

Which Has Generated Strong Corporate Earnings

EFH Adjusted EBITDA

2008-2012; $ millions

34

1 

See above for Regulation G reconciliations and definition.

4,578

4,857

5,240

5,036

5,257

2008

2009

2010

2011

2012

1

1 

2009-2011 average.

2 

Includes four mothballed units (1,655 MW) not currently available for dispatch and two units (1,130 MW) for which operations have been suspended until June 2013.

3 

For the year ended December 31, 2012 (excludes purchased power).

Business Profile

Generation

Largest coal & nuclear generation fleet in ERCOT

Top

decile

nuclear

plant

production

and

cost

performance

1

Top

quartile

coal

fleet

production

and

cost

performance

1

Largest mine-mouth coal operator in Texas

Gas

plant

operations

-

high

availability

to

meet

peak

demand

Active asset management and hedging program to maintain

value in volatile commodity market

Coal

Gas

Nuclear

Generating Capacity   as of

December 31, 2012

Total Net Generation for the year ended

December 31, 2012

15,427 MW

70,490 GWh

Safety

Wholesale power prices

Natural gas hedge program

Coal / Nuclear plant reliability

Mining operations / lignite cost

Fuel / O&M / SG&A costs

Peaking gas assets

Operational excellence / continuous improvement

Competitive market

Value Drivers

Luminant Is The Largest Power Generator In Texas

35

2%

70%

28%

52%

33%

15%

2

3

1

Benchmarking net capacity factors based on GADS. Luminant is legacy lignite/coal fleet only and based on net GADS capacity.

Source: GKS

Top decile

79.7%

Top quartile

73.8%

Top decile

$3.63

Top quartile 

$4.36

Luminant 09–11 fleet avg. = 79.9%

Luminant 09–11 fleet avg. = $3.87

Luminant

vs.

US

coal

fleet

net

capacity

factors

1

Percent

Luminant vs. US coal fleet O&M

$/MWh

Luminant Is A High-Performing Coal Operator

36

%

%

%

%

%

%

%

40

50

60

70

80

90

100

$0

$2

$4

$6

$8

$10

$12

Comanche Peak Plant Is One Of Highest-Performing

Nuclear Plants In The Country

09-11 Capability Factor / O&M

$/MWh

1

Benchmarking peer set defined as 18 month fuel cycle U.S. nuclear plants.

Source: EUCG May, 2012 Comprehensive Data Release for Cost and WANO for Capability Factors

CPNPP

Decile

Quartile

Median

Decile

Quartile

Median

37

75

80

85

90

95

10.00

15.00

20.00

25.00

30.00

35.00

40.00

O&M costs ($/MWh)

1

TXU Energy Is The Largest Retail Electricity

Provider In Texas

Strong customer value proposition

•

High brand recognition in Texas competitive areas

•

Competitive retail prices

•

Innovative products and services

•

Committed to low-income customer assistance

•

Improved customer care delivery capabilities

Balance Sheet

•

Combined TCEH risk management and liquidity efficient capital

structure

Expected margins (5–10% net)

Source: KEMA Retailer Landscape Report dated 9/28/12; As of June

2012

Source: NERC 2012 Long-Term Reliability Assessment (Summer Demand)

Residential Customers / Meters

(in thousands)

End of Year Residential Customer Counts

(in thousands)

Projected Annual Demand Growth

CAGR (2013E-2022E; percent)

Value Drivers

64%

38

1,914

1,862

1,771

1,625

1,547

2008

2009

2010

2011

2012

Year over Year Customer Attrition

3.1%

(2.7)%

(4.9)%

(8.2)%

(4.8)%

1

Excludes December 2012 acquisition of customers

1.4%

2.3%

US

ERCOT

1

1,578

1,414

775

374

332

294

230

TXUE

Reliant

Direct

Ambit

Stream

Just

Energy

Green

Mountain

Executing A Marketing Strategy Balancing Value And Price

39

Price Orientation

Value Orientation

New offers are reinforcing TXU Energy’s value proposition

And Incorporating Technological Solutions

Innovations

TXU Energy MyEnergy Dashboard

TXU Energy Electricity Usage Report

Brighten      iThermostat

TXU Energy’s iPhone and Android Apps

40

SM

41

While Managing Expenses And Improving Cash Flow

Bad debt expense

2008 -

2012; $ millions

Days sales outstanding

2008 –

2012; Days

TXU Energy has continued to

lower bad debt over time….

…and generate cash flow by

reducing days sales outstanding

81

117

108

56

26

2008

2009

2010

2011

2012

2008

2009

2010

2011

2012

48

50

49

43

40

FY 2012 Bad Debt expense was $26 million, one of the lowest totals in TXUE recent history

Days Sales Outstanding have improved significantly due to collection initiatives, customer

mix and credit policy improvements

And Providing A Strong Customer Experience

% Chg

Since 1/09

% Chg

Since 1/09

42

86%

17%

50%

55%

60%

65%

70%

75%

80%

First Call Resolution

0

100

200

300

400

500

PUC Complaints

Enhanced Customer Experience and Product Innovation:

•

Record

performance

-

first

call

resolution,

customer

satisfaction,

PUC

complaints

•

Lower

operating

costs

through

gains

in

technology

and

self

service

•

First

to

market

with

innovations

leveraging

Smart

Grid

–

Free

Nights,

iPhone

app,

etc.

•

Reduced customer net attrition in 2012; a 42% improvement from 2011

•

Proven

risk

management

strategies

delivering

more

predictable

pricing

to

customers

FCR

FCR Trend

PUC

CSAT Trend

43

New Oncor Infrastructure

…to support the continued buildout of

wind capacity in Texas

Oncor’s investment in CREZ will receive accelerated recovery,

consistent with other transmission investment, mitigating regulatory delay

Oncor has invested $1.46 billion cumulatively

on CREZ projects as of December 31, 2012

Oncor expects to invest ~$2.0 billion on

CREZ-related transmission lines…

44

Oncor Demand-Side Management

Oncor recovers its investment through a

PUCT

-approved

surcharge

Customer monitoring of consumption

“Smart”

appliances

Dynamic pricing

Oncor’s

energy

efficiency

filing

has

been

approved

and

is

reflected

in

rates

1

Public Utility Commission of Texas.

Oncor has deployed ~$660 million of

capital for advanced metering

initiatives…

…that will enable key DSM initiatives

Oncor has completed its planned deployment of 3.26 million

meters, including 961,000 in 2012

1

45

EFH Transformed Business Services To Focus on Service,

Excellence and Governance

Before July 2008

Establish

Service,

Excellence &

Governance

Model

Governance over shared

services and alignment

with businesses needed to

be enhanced

Transparency to Business

Services cost needed to be

improved

Service Level Agreements

(SLA)  were not in place

Business Services costs

were not fully categorized

or allocated

The objective was to create a  cost-effective shared services group that provided

service levels consistent with a large scale competitive / regulated energy company

To Create Value For The Rest Of The Enterprise

46

Enhanced liquidity through balance sheet and tax initiatives

Implemented cost controls

Enhanced enterprise-wide risk management policies and procedures 

Streamlined corporate governance and developed policies and

procedures consistent with strategic goals and objectives

Recruited and retained key leadership talent and created programs to

identify and develop in-house talent

Formed and maintained key stakeholder relationships with industry

participants and other nongovernmental organizations (NGOs)

Strengthened IT infrastructure

Implemented new TXU Energy customer care and billing system

Invested in upgrading aging infrastructure

And Drive Down Consolidated SG&A Over Time

47

Consolidated SG&A

2009-2012; $ millions

1 

Pro-forma for the deconsolidation of Oncor that occurred prospectively in 2010.

875

751

742

674

1

2009

2010

2011

2012

SG&A has declined over $200MM from 2009 to 2012 

Key Takeaways –

Maximizing Enterprise Value

48

Improved the company’s reputation and met merger commitments

–

Engaged company stakeholders including legislators and NGOs

–

Invested in the surrounding communities

Invested in Texas -

$10+ billion in capital and added ~1,900 positions

Maintained focus on Operational Excellence

–

Safe and reliable operating performance at Luminant

–

TXU Energy managing margins and controlling costs amidst increased competition

–

Business Services restructured operations, strengthened infrastructure and

controlled costs

A keen focus on operational excellence has resulted in strong operating and

financial performance amidst depressed commodity prices