Excerpts from slide presentation

Transaction Overview

On October 10, 2007, an investor group comprised of Kohlberg Kravis Roberts & Co. (“KKR”), TPG

Capital, L.P. (“TPG”), and certain other co-investors (together, the “Investor Group”) acquired TXU Corp.

in a transaction valued at approximately $49 billion

–

In conjunction with the transaction, TXU Corp. was renamed Energy Future Holdings Corp. (“EFH”)

EFH manages a portfolio of three functionally separate energy businesses located primarily in Texas

Texas

Competitive

Electric

Holdings

Company

LLC

(“TCEH”

and

formerly

TXU

Energy

Company

LLC),

subsidiary

EFH,

the

holding

company

for

the

company's

competitive

businesses,

Luminant

and

TXU

Energy

–

Luminant

(formerly TXU Power, TXU Wholesale and TXU DevCo) has 18,365 MW of generation in

Texas,

including

2,300

nuclear

and

5,837

lignite-fueled

baseload

generation

capacity

and is currently building 3 lignite-fueled units at 2 sites that will add over 2,200 MW of baseload

capacity

–

TXU Energy is the largest retail electric provider in Texas, with over 1.8 million residential customers

The Investor Group funded the merger with:

–

$30.5

(1)

billion of new funded debt at EFH and TCEH

–

$8.3 billion of new and roll-over equitys

(1) Pro Forma as of 6/30/07. Includes estimated $687 million draw on Commodity Collateral Revolver (based on natural forward gas curve as of 6/30/07).

Exhibit 99.1

($ in millions)

TCEH

EFH

Revolver

- -

Commodity Collateral Revolver

$687

- -

Term Loan B

16,450

- -

Delayed Draw Term Loan

2,150

- -

Cash Pay Bridges

5,000

$2,000

PIK Toggle Bridges

1,750

2,500

Total

$26,037

$4,500

Revolver

$2,700

- -

Deposit LC Facility

1,250

- -

Delayed Draw Term Loan

1,950

- -

Total

$5,900

- -

Total Committed Financing

$31,937

$4,500

Committed Financing

The

Investor

Group

has

secured

approximately

$36.4

billion

new,

committed

debt

financing,

$30.5

(1)

billion of which was funded as of the transaction close.

(2)

Note:

Excludes

refinancing

existing

Accounts

Receivable

Securitization

TXU

Receivables

Co.

and

existing

Transition

Bonds

Oncor

Electric

Delivery.

(1)

Pro Forma as of 6/30/07. Includes estimated $687 million draw on Commodity Collateral Revolver (based on natural forward gas curve as of 6/30/07). Actual drawn amount at

closing was ~$380 million.

(2)

Commodity

Collateral

Revolver

will

drawn

needed

provide

cash

collateral

for

certain

natural

gas

hedges.

capacity

limit

such

revolver.

Pro Forma Capitalization as of 6/30/07

TCEH

EFH

(1)

Revolver commitment of $2,700 million.

(2)

Deposit

Facility

$1,250

million

that

will

shown

debt

TCEH’s

balance

sheet

offset

$1,250

million

restricted

cash.

(3)

Commodity

Collateral

Revolver

will

drawn

needed

provide

cash

collateral

for

certain

natural

gas

hedges.

capacity

limit

such

revolver.

(4)

Includes amounts related to securitization bonds; excludes $113 million related to repurchasing receivables from the accounts receivables facility.

(5)

Building Lease secured by a Letter of Credit issued by TCEH.

Excludes borrowings related to new plants not

yet in service

Multiple of

Funded

PF Adjusted

Funded

PF Adjusted

($ in millions)

Amount

LTM EBITDA

Amount

LTM EBITDA

Revolving Credit Facility

(1)

Deposit LC Facility

(2)

Commodity Collateral Revolver

(3)

$687

Term Loan B

16,450

Delayed Draw Term Loan

2,150

Capital Leases

Total Senior Secured Debt

19,379

4.8x

17,229

4.3x

Senior Unsecured Bridge Facility

6,750

Pollution Control Revenue Bonds

1,535

Total Debt

27,664

6.9x

25,514

6.4x

LTM 06/30/07 Pro Forma Adjusted EBITDA

$3,999

Multiple of

Funded

PF Adjusted

% of

Funded

PF Adjusted

($ in millions)

Amount

LTM EBITDA

Capitalization

Amount

LTM EBITDA

Debt at Subsidiaries

Oncor

(4)

$5,015

TCEH

27,664

25,514

Energy Future Competitive Holdings

217

Other

(5)

Total

32,989

30,839

Senior Unsecured Bridge Facility

4,500

Total Debt with Subsidiary Guarantees

37,489

7.2x

35,339

6.8x

Existing Indebtedness

2,700

Total Debt

40,189

7.7x

82.9%

38,039

7.3x

Common Equity

8,300

17.1%

8,300

Total Capitalization

48,489

9.3x

46,339

8.9x

LTM 06/30/07 Pro Forma Adjusted EBITDA

$5,235

Investment Rationale

TCEH is well positioned to capitalize on the strong underlying fundamentals in the Texas electricity markets.

Attractive Generation Supply / Demand Outlook

Strong regional demand growth of 2.0% to 2.5% per year

Further tightening of reserve margins, requiring completion of

pending facilities and further development of alternative

solutions such as DSM and new generation technologies

–

Coal and nuclear capacity additions impacted by long

development lead times and siting, permitting and

environmental issues

Gas generation expected to remain on the margin

Attractive Underlying Commodity Outlook (i.e., Natural Gas)

Marginal North American gas expected from Rockies and

Appalachia; not LNG

Substantial escalation of E&P drilling and services costs

continues to increase cost of marginal North American gas

supply

Political and environmental forces increasing demand for

natural gas fueled power generation

Attractive Retail Market Dynamics

Long-term demand growth of 2.0% to 2.5%

Competitive pricing and differentiated service expected to

improve customer retention

Luminant

Largest

baseload

generator

Texas

Additional baseload units currently under construction

will

add

over

2,200

low-cost

baseload

capacity

Substantial hedging program (~75% of natural gas

position

hedged

through

2013

(1)

)

expected

enhance

cash flow stability

Track record of top decile performance and reliability

on a national basis

A wholesale business supporting the largest

generation

fleet in ERCOT

TXU Energy

Large scale competitive retailer with strong incumbent

position in the Dallas / Ft. Worth market

Strong brand recognition and superior service

Constructive market fundamentals driven by population

growth in key markets

Opportunity for significant out-of-territory growth

(primarily in Houston and South Texas)

(1) Includes impact of estimated short position associated with fixed price contracts and other retail activities.

EFH: Three Separately Operated Businesses

Independent Board

New Brand

Former Brand

TXU Power / Wholesale / DevCo

TXU Energy

TXU Electric Delivery

Business

Description

2 largest deregulated output in US

Top decile performance

64 TWh per year of existing baseload

production in gas-on-the-margin market

18 TWh per year of new baseload capacity

under construction

Low-cost lignite reserves

Largest wind energy buyer in Texas and

developing new sustainable energy

opportunities

Largest competitive retailer in high

growth ERCOT market

Loyal customers

Strong brand recognition

Strong service orientation

Investing in demand-side

management

Innovative products

Attractive prices

Sixth largest T&D company in US

High growth region (ERCOT)

Efficient capital recovery

Top quartile costs and reliability

No commodity position

No end-user risk

Separate Board

Senior Leadership

Michael Greene, Mike McCall, Chuck Enze

Jim Burke

Bob Shapard

Ring-fenced

1.5

0.9

0.8

0.6

0.5

0.4

0.3

0.4

ERCOT Is a Large, Diversified and Growing Market

2.3

2.2

2.1

1.9

1.7

1.4

1.1

0.9

FRCC

MRO

ERCOT

SERC

SPP

WECC

NPCC

RFC

4.1

3.8

3.7

1.6

1.3

0.9

0.7

0.6

0.7

Strong Population Growth …

2005–2015E; Growth in Millions of People

…

Driving Strong Power Demand Growth

2006–2016E; Percent

…

One of the Largest Economies …

2005–2015E; Growth in Gross State Product in $ Trillions

…

With the Same Resiliency as the Overall US …

2005; $ Trillions

26%

25%

19%

22%

16%

19%

11%

10%

Texas

Trade, Transportation

& Utilities

Government

Manufacturing

Leisure & Hospitality

Other

Professional, Business,

Education &Health Services

Natural Resources, Mining

100%=

Financial

12.4

0.8

Source: US Census Bureau, Population Division, Interim State Population Projections, 2005.

(1) ERCOT figure represents 2007-2017 data per ERCOT.

Source: NERC.

Source: US Census Bureau, Population Division, Interim State Population Projections, 2005.

Projected demand growth is supported by strong and resilient economic growth in Texas.

(1)

The ERCOT Generation Mix Is Relatively Unique In The US…

Coal

Gas/Oil

Nuclear

Other

Coal

Nuclear

Gas/Oil

US Fuel Mix by Capacity

2005; Percent of Total GW

(100% = 938 GW)

ERCOT (TX) Fuel Mix by Capacity

2005; Percent of Total GW

(100% = 83 GW)

ERCOT has a substantially higher proportion of natural gas-fueled capacity than the overall US market and

more gas-fueled capacity than any other NERC region in the US.

Source: Energy Velocity.

100

200

300

400

500

600

700

800

900

1000

Cumulative Capacity (GW)

Non gas/oil

Gas/oil

Coal

Gas/oil

Internal combustion

CCGT

Nuclear

Wind,

Hydro and Other

…Resulting in Gas Generation Setting the Marginal Price in ERCOT

Gas sets the marginal price of power over 90% of the time in ERCOT versus about 50% of the time across

the US.

ERCOT

Generation

Portfolio:

Gas

Equivalent

Heat

Rate

(1)

MMBtu/MWh

Cumulative Capacity (GW)

Non gas/oil

Gas/oil

Nuclear

Coal

Gas/oil

Internal combustion

CCGT

Wind

US Generation Portfolio: Gas Equivalent Heat Rate

MMBtu/MWh

(1) Based on gas price of $7.50/MMBtu.

Peak Load:

62,339 MW

Peak Load + 12%:

69,820 MW

2.3

2.2

2.1

1.9

1.7

1.4

1.1

0.9

FRCC

MRO

ERCOT

SERC

SPP

WECC

NPCC

RFC

17.4

16.4

14.6

12.6

10.1

8.3

6.7

5.9

2005

2006

2007E

2008E

2009E

2010E

2011E

2012E

ERCOT Fundamentals Reflect Growing Demand

ERCOT comprises ~85% of Texas market, which is one of the largest power markets in the world.

985

962

685

305

299

227

217

202

RFC

SERC

WECC

NPCC

ERCOT

FRCC

MRO

SPP

Electricity Consumption 2005

(Twh)

Projected Annual Electricity Demand Growth

2006–2016E

(Percent)

Source: NERC.

Decreasing Reserve Margins 2005–2012E

(Percent)

(1) ERCOT figure represents 2007-2017 data per ERCOT.

Source: NERC.

Source: ERCOT.

Minimum ERCOT Reserve

Margin: 12.5%

At current forward gas price and $710/kW capital cost, the breakeven heat rate for a

new CCGT facility would be ~9.0 MMBtu/MWh

New Build Economics

(1)

Units

Values

HSC Gas Price

$/MMBtu

$7.20

Advanced CCGT Heat Rate

MMBtu/MWh

6.8

Construction Cost

$/KW

$710

Capacity Factor

Percent

85.0%

Total Required Capacity Payment

$/KW-year

$129

Breakeven Heat Rate Calculator

Total Breakeven Revenue

$/MWh

$67.4

Equivalent Heat Rate When Earning Return

MMBtu/MWh

9.4

Power Price When Not Earning Return

$/MWh

$50.0

Equivalent Heat Rate When Not Earning Return

MMBtu/MWh

6.9

7x24 Price

$/MWh

$64.8

Implied 7X24 Heat Rate

MMBtu/MWh

9.0

Breakeven Spark Spread

$/MWh

$15.8

Note: EVA and EFH assumptions / analysis.

65%

29%

Luminant Overview

Description

Total Generation Breakdown

Map of Generation Assets

2nd largest deregulated output in US; largest generation

fleet in ERCOT

18,365 MW

(1)

of generation capacity (2,300 MW

nuclear, 5,837 MW coal/lignite, 10,228 MW gas)

64 TWh of baseload production in a gas-on-the-margin

market

History of strong operating performance

–

3-year average capacity factor of coal plants: 88%

–

3-year average capacity factor of nuclear plant: 96%

55%

32%

13%

Coal

Gas

Nuclear

2006 Generating Capacity

(1)

(MW)

2006 Total Generation

(2)

(GWh)

(1) Includes 1,329 MW of mothballed gas plants.

(2) Does not include purchased power.

Coal

Gas

Nuclear

18,365 MW

67,621 GWh

86%

90%

89%

92%

2004

2005

2006

Long-term

Target

Improvement

~$25mm

EBITDA

annually

(2)

Top decile

$26.43

$25.93

$24.43

$21.00

2004

2005

2006

Long-term

Target

Top quartile

$1 per KW-Yr Improvement ~$6mm EBITDA annually

History of Operational Excellence…

Nuclear Capacity Factors

(1)

2004-LT, based on nameplate

Lignite / Coal Capacity Factors 2004-LT

Lignite / Coal Operating Expense 2004-LT

($/KW-Yr)

Nuclear Operating Expense

(3)

2004-LT

($/KW-Yr)

(1)

Normalized for one outage per year. 100% long-term target based on nameplate capacity, equivalent to 96% of actual current capacity due to upgrades.

(2)

Based on an annual average power price of $65/MWh.

(3)

Normalized for one outage per year.

94%

96%

99%

100%

2004

2005

2006

Long-term

Target

Top decile

Improvement

~$11mm

EBITDA

annually

(2)

$103.00

$95.00

$90.00

$80.00

2004

2005

2006

Long-term

Target

$1 per KW-Yr Improvement ~$2mm EBITDA annually

Top decile

(1)

$50

$34

$27

$18

Average of 1st

Quartile

Average of 2nd

Quartile

Average of 3rd

Quartile

Average of 4th

Quartile

$44

$101

$124

'90-'00

'01-'03

'04-'06

…Enabled By Ongoing Investment and

Benefiting From High Dispatch Rates…

Luminant Lignite / Coal Fleet Capex

(1)

($ millions)

(1) Average annual coal plant capex, excluding emissions-related spend.

US Coal Fleet Total Maintenance Expense

(1) (2)

($/kW)

(1) Values represent 04-06 annual averages.

(2) Total maintenance expenses include capital expenditures.

Source: Generation Knowledge Service (GKS).

Luminant = $31

US Coal Fleet Capacity Factors

(1)

US Coal Fleet Equivalent Availability Factors

(1)

85.4%

78.5%

70.8%

59.7%

Average of 1st

Quartile

Average of 2nd

Quartile

Average of 3rd

Quartile

Average of 4th

Quartile

92.1%

87.7%

83.4%

76.1%

Average of 1st

Quartile

Average of 2nd

Quartile

Average of 3rd

Quartile

Average of 4th

Quartile

(1) Based on 04-06 average unit net generation and net maximum capacity.

Source: Generation Knowledge Service (GKS).

(1) Values represent 04-06 annual averages.

Source: Generation Knowledge Service (GKS).

Luminant = 88%

Luminant = 89%

Competitively Advantaged Projected Construction

Costs

(1)

($/kW)

$1,275

$1,520

$1,911

Oak Grove

Sandow 5

Average US Builder

(2)

…With A New Build Program Focused on Strategically Advantaged Sites

Oak Grove

Sandow

(1)

Commercial online date.

Sites With Access to Low-Cost Lignite Reserves

Luminant Mining will expand operations at Sandow and open

new permitted Kosse Mine to Supply Oak Grove (up to

$1/MMBtu lower than delivered PRB)

Projected Completion Dates

Projected Net

Capacity MW

Fuel

Air Permit

Status

COD

(1)

County

Oak Grove

1&2

1,654

Lignite

Complete

Q3-2009 /

Q1-2010

Robertson

Sandow 5

581

Lignite

Complete

Q2-2009

Milam

Total

2,235

(1)

Estimates of construction expenses excluding mine development costs.

(2)

Based

average

pulvarized

coal

construction cost

estimates/targets

for

2002 –

2007.

Favorable EPC Agreements

Executed EPC agreements with premier EPC contractors

based on fixed price, turn-key contracts, subject to certain

adjustments

–

Substantial majority of total construction, siting and

mining development costs are fixed, with the remainder

subject to adjustment based on labor market conditions

and final bids on non-EPC related construction costs

–

Construction capital to be supported and funded by

TCEH Delayed Draw Term Loan facility

Orders placed for critical, long lead-time equipment

(including boilers, turbine generators and air quality control

systems)

–

EPC agreements contain a number of contractual

completion dates and performance guarantees

New Build Status Update

Sandow 5 Schedule Milestones

November 2005 –

Announced intent to acquire Sandow 5 air

permit from Alcoa

May

2006

–

Signed

finalized

EPC

contract

June

2006

–

Began

construction

Sandow

facility

2009

–

Expected

commercial

online

date

Oak Grove Schedule Milestones

November

2005

–

Announced

intent

build

Oak

Grove

Units

1 & 2

June

2006

–

Signed

finalized

EPC

contract

June

2007

–

Received

final

air

permit

from

TCEQ

June

2007

–

Began

construction

Oak

Grove

facility

2009

–

Expected

commercial

online

date

for

Unit

2010

–

Expected

commercial

online

date

for

Unit

TXU Energy Overview

TXU Energy is the largest competitive retailer in the high growth ERCOT market.

Business Profile

Large scale competitive retailer

–

~60% residential market share in Dallas / Ft.

Worth and other incumbent areas

–

Growing business in other areas; 35%

residential market share throughout ERCOT

–

One of the largest ERCOT providers serving

small businesses and large commercial /

industrials

Strong brand recognition

Superior prices –

lowest price of any incumbent

for legacy (former price-to-beat) customers

Value creating strategy

–

Broadest array of products in the market

place

–

Multi-channel partnering strategy

–

Customer loyalty programs

–

Targeted marketing and service offerings

–

Superior service with call answer times

averaging less than 15 seconds

–

Making investments in market leading

systems

Leading Position in ERCOT…

Millions of residential customers / meters

…In a Market with Significant Long-Term Growth

’06–’16E; Percent annual demand growth

2.3

2.2

2.1

1.9

1.7

1.4

1.1

0.9

FRCC

MRO

ERCOT

SERC

SPP

WECC

NPCC

RFC

Source: NERC.

(1) ERCOT figure represents 2007-2017 data per ERCOT.

Sources: KEMA, company filings.

(1)

1.8

1.5

0.8

0.2

0.1

TXU Energy

RRI

Direct

Energy

First Choice

Stream

Energy

Gexa

TXU Energy Offers Superior Customer Prices…

The price reductions to date have benefited over 1 million of TXU Energy’s customers. The price reductions

and differentiated service levels are expected to result in increased customer retention.

Annualized Incumbent Retailer PTB Rollover Prices 2007

(Cents/kWh (for 1,500 kWh/mo user))

On May 29, 2007, TXU Energy announced a 15% price reduction for legacy customers. The first 10% of this price

reduction was phased in by early June and the remaining 5% will take effect this month as a result of the transaction

closing

15.2

15.0

14.6

13.2

12.4

14.2

Direct Energy (WTU)

Direct Energy (CPL)

Reliant

First Choice

TXU Energy

Pre-Closing

TXU Energy

Post-Closing

TXU Energy Annual Savings

vs. Incumbent

($ per Customer)

$490

$461

$389

$317

$131

N/A

Major City Served

Abilene

Corpus Christi

Houston

Texas City

Dallas/Ft. Worth

Average excluding TXU Energy = 14.7 cents/kWh

(1)

(2)

(1) Prior to final 5% price cut that will take effect this month.

(2) Includes final 5% price cut that will take effect this month.

…Contributing to a Stabilizing Market Share This Year

-6.0%

-5.0%

-4.0%

-3.0%

-2.0%

-1.0%

0.0%

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

-1.0%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

-3.0%

-2.0%

-1.0%

0.0%

1.0%

2.0%

3.0%

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

2005

2006

2007 YTD

In-Territory Loss Rate

(% of IT Customers)

Out-of-Territory Growth Rate

(% of OOT Customers)

Total Residential Growth/Loss Rate

(% monthly change)

(45.8)

(7.6)

7.3

33.6

(38.4)

26.0

Q3 '06

Q3 '07 Estimates

Q3 ‘07 vs

Q3 ‘06 Customer Gains

(Change in Customers in Thousands)

In-Territory

Total ERCOT

Out-of-Territory

Strong Mitigants for Major Enterprise Risks

Reduction of coal program from 11 units to 3; support from environmental groups

Reaffirmed

commitment

environmental

stewardship

and

voluntary

environmental

upgrade

program

Plans to double wind purchases to 1.5 GW or more

Potential

carbon

regulation

not

expected

implemented

until

2010+

Most advanced competitive market in US; SB7 framework resilient and successful

Voluntary Mitigation Plan (“VMP”) for wholesale bidding practices negotiated with Independent Market

Monitor

and

PUC

Staff

August

2007

(PUC’s

procedure

for

adopting

the

VMP

subject

court

challenge

by other market participants)

Plant operations

–

Management expertise and experience; Investor Group experience with Texas Genco

–

High quality, well-maintained assets with demonstrated track record of operational excellence

Construction

–

Reduced lignite / coal buildout (from 11 to 3 units); all units are already permitted and under construction

–

EPC agreements in place for Sandow 5 and Oak Grove with substantial portions of costs fixed

Nuclear risk

–

Two separate units, each less than 15% of total generation

–

Top performing nuclear operation from both availability and safety perspectives

~75% of gas price position hedged over next 6 years

(1)

; ongoing hedging program is key aspect of

management strategy (see following pages)

Collateral

and

liquidity

management

programs

designed

support

underlying

business

and

hedging

requirements

TCEH

expects

hedge

substantial

portion

its

interest

rate

exposure

for

the

term

its

debt

facilities

Credit statistics are reasonable even under stress scenarios

Mitigants

Risks

Market /

Commodity

Operational

Environmental

Legislative /

Regulatory

(1) Includes impact of estimated short position associated with fixed price contracts and other retail activities.

Significantly Hedged Natural Gas Position

TCEH has hedged approximately 2.6 billion MMBtu of natural gas position through 2013 and expects to

continue to execute a rolling five-year hedge program

(1)

Estimated Natural Gas Position 2008E–2013E

(2)

(Million MMBtu)

(1)

Assumed natural gas conversion factor of ~90% of the market-clearing heat rate given that coal is on the margin for select periods; during those periods, there is no natural-gas

position that is generated.

(2)

Includes fixed price sold forward positions and estimates that of total non-contract in-territory load, 50% is a short-position in 2008, dropping to 25% in 2009.

(3)

Includes

~35

million

MMBtu

put

option

delta

volume

(notional

160

million

MMBtu

put

purchased

for

2008

protect

against

downside

gas

movements).

(4)

Weighted

average

prices

are

based

actual

contract

prices

and,

importantly,

certain

the

volumes

associated

with

TCEH’s

CCR

reflect

re-contracting

the

volumes

October

2007.

the

weighted

average

prices

were

adjusted

reflect

re-contracting

those

same

volumes

the

pro

forma

date

(June

30,

2007)

and

consistent

with

the

presentation of

drawn

balances

under

TCEH

CCR,

the

weighted

average

prices

would

$8.30,

$8.25,

$7.90,

$7.75,

$7.30

and

$7.25

for

2008E

through

2013E respectively.

(2)

(3)

525

610

665

680

690

~95%

Hedged

~75%

Hedged

~80%

Hedged

~80%

Hedged

~60%

Hedged

~60%

Hedged

680

Average price of

natural gas swap

hedges (NYMEX

equivalent price)

(4)

~$8.15

~$8.10

~$7.80

~$7.55

~$7.25

180

310

370

510

545

425

400

155

135

125

265

280

2008E

2009E

2010E

2011E

2012E

2013E

Other Short Positions

Natural Gas Hedges

Unhedged

Position

Financial Objectives

Strong cash generation through advantaged asset base, prudent risk management and strong capital

discipline.

Strong Asset Base

Strong Capital Discipline

Prudent Risk Management

8,137 MW of baseload

generation in a gas-on-the-

margin market

History of reliable, cost-effective

and safe operations

Largest retail customer count

position in ERCOT with loyal

customers

Strong correlation between gas

and power prices currently allows

for hedging through highly-liquid

and longer-dated gas markets

Commodity hedging program

expected to significantly reduce

exposure to changes in electricity

prices over 6 years

Expect to hedge a substantial

portion of TCEH’s

interest rate

exposure for the term of its debt

facilities

Renewed commitment to

environmental stewardship and

serving needs of key stakeholders

Balanced development

program, with 3 new lignite

units under construction;

substantial majority of total

construction costs are fixed

costs via contracts with EPC

firms

Efficient use of asset-backed

structures to support commodity

hedges, reflecting right-way risk

Strong Cash Flow Generation

TCEH Historical Financials

Adjusted EBITDA

(1)

($ in millions)

Note: LTM as of 6/30/07.

(1) 2004

–

LTM

EBITDA

adjusted

for

restructuring

costs,

unrealized

mark

market

gains

and

losses

associated

with

natural

gas

hedging

obligations,

Luminant

Construction

and

Development losses, and

certain

other

items

allowed

under

the

Senior

Secured Facilities.

(2)

Adjusted

Capex

represents

EFH

consolidated

capex

less

amounts

Oncor;

All

Other

category

includes

capitalized

interest,

nuclear

development

capex,

nuclear

fuel

capex,

and

the

costs

the

Comanche Peak steam

generator

replacement.

New

Build Program

capex

includes

plant construction

and

mine

development capex

for

the

new Oak

Grove

and

Sandow

units

and

the

environmental retrofit

program.

$1,982

$2,888

$4,387

$3,999

2004

2005

2006

PF LTM 6/30/07

Adjusted Capex

(2)

($ in millions)

$2,313

$1,457

$371

$399

2004

2005

2006

LTM 6/30/07

All Other

New Build Program

Reference Plant Program

TCEH Historical Financials

Note: LTM as of 6/30/07.

(1)

Pro

forma

LTM

period

financial

information

includes

adjustments

for

purchase

asccounting

and

financing

the

transaction.

(2)

Excludes

Oak

Grove

and

Sandow

capital

expenditures

transferred

into

TCEH

October

2007.

Year Ended

Six Months

Pro Forma

December 31,

Ended June 30,

LTM

($ in millions)

2004

2005

2006

2007

6/30/07

(1)

Operating revenues

$8,402

$9,552

$9,595

$4,478

$3,411

$8,181

Operating costs and expenses:

Fuel, purchased power costs and delivery fees

5,173

5,545

3,922

1,733

1,900

4,244

Operating costs

703

667

613

307

319

626

Depreciation and amortization

350

313

333

169

160

672

Selling, general and administrative expenses

666

522

532

242

285

634

Franchise and revenue-based taxes

117

114

126

125

Other income

(110)

(64)

(25)

(1)

(9)

(25)

Other deductions

611

200

195

Total costs and expenses

$7,510

$7,112

$5,701

$2,699

$2,723

$6,296

Operating Income

$892

$2,440

$3,894

$1,779

$688

$1,885

Net income

$378

$1,414

$2,435

$1,063

$480

($205)

Provision for income taxes

162

687

1,277

590

180

(241)

Interest expense

353

393

384

202

190

2,619

Depreciation and amortization

350

313

333

169

160

672

EBITDA

$1,243

$2,807

$4,429

$2,024

$1,010

$2,845

Total Adjustments to EBITDA

739

(42)

661

1,154

Adjusted EBITDA

$1,982

$2,888

$4,387

$2,051

$1,671

$3,999

Capital Expenditures

(2)

$281

$309

$388

$218

$381

$551

1H ‘07 Performance Update

Strong progress in generation development

–

Received air permits for Oak Grove 1 & 2

–

Finalized EPC contracts at attractive terms

–

Began construction on Oak Grove 1 & 2

–

Increased the portfolio of wind-power contracts with a

209-megawatt agreement

Strong underlying performance in the generation fleet

–

Continued to achieve record or near-record level

performance from the lignite / coal fleet

–

Executed the replacement of the Comanche Peak Unit 1

steam generator in world record time

Strong retail performance

–

Experienced residential customer growth

–

Implemented price cuts for residential customers of 10% (additional 5% will take effect as a result of the transaction

closing)

Continued focus on risk management through expansion of the natural gas hedging program

Operational earnings declined over the prior-year periods due to:

–

Cooler than normal weather and abnormally high rainfall that negatively affected coal fuel costs as well as electricity

sales

–

Planned outage at Comanche Peak

–

Lower average retail pricing (including previously announced residential price cuts)

–

Reduced average weather-adjusted mass market consumption

–

Customer attrition

$2,051

$1,671

1H '06

1H '07

TCEH Adjusted EBITDA

(1)

($ in millions)

(1)

EBITDA

adjusted

for

restructuring

costs,

unrealized

mark

market

gains

and

losses

associated

with

associated

with

natural

gas

hedging

obligations,

Luminant

Construction and

Development

losses,

and

certain

other

items

allowed

under

the

Senior

Secured

Facilities.

Favorable Liquidity Position

Key Liquidity Highlights

Significant liquidity in place to fund ongoing business operations

–

Combination of revolver and deposit LC facility totaling $3.95 billion

–

Additional $1.95 billion of delayed draw term loan commitments in place to ensure available liquidity to

fund the construction of the new plants

Additional facilities in place to cover the liquidity needs associated with the commodity hedging program

–

Facilities have "right-way" risk characteristics as gas prices are positively correlated with the value of

TCEH’s

solid fuel assets

–

Approximately

50%

Luminant’s

natural

gas

hedge

book

secured

first

lien

position

TCEH’s

assets (requiring no collateral posting)

–

Approximately 80% of the remaining natural gas hedge book is supported by a new collateral posting

revolving

facility

TCEH

that

secured

first

lien

TCEH’s

assets

(fixed

fee,

uncapped)

–

Expectation

implement

additional

structures

for

the

remaining

positions

1,950

Delayed Draw Term Loan (unfunded portion)

$5,900

Total Capacity

2,700

Revolver

$1,250

Deposit LC Facility

Available Liquidity

Texas Competitive Electric Holdings

($ in millions)

TCEH Adjusted EBITDA Reconciliation

(1) Pro forma LTM period financial information includes adjustments for purchase accounting and financing related to the transaction.

Year Ended

Six Months

Pro Forma

December 31,

Ended June 30,

LTM

($ in millions)

2004

2005

2006

2007

6/30/07

(1)

Net income

$378

$1,414

$2,435

$1,063

$480

($205)

Provision for income taxes

162

687

1,277

590

180

(241)

Interest expense

353

393

384

202

190

2,619

Depreciation and amortization

350

313

333

169

160

672

EBITDA

$1,243

$2,807

$4,429

$2,024

$1,010

$2,845

Adjustments to EBITDA:

Interest Income

(31)

(70)

(202)

(76)

(162)

(288)

Amortization of nuclear fuel

135

Purchase Accounting Adjustments

Impairment of assets and inventory write down

192

201

Unrealized net (gain) or loss resulting from Hedging obligations

109

(330)

(148)

750

939

Customer appreciation one-time bonus

165

Amount of loss on sales of receivables and related assets in

connection with the Receivables Facility

Income from discontinued operations, net of tax

Cumulative effect of changes in accounting principles, net of tax

(4)

Non-cash compensation expenses (FAS 123R)

Severance expense

107

Loss on early extinguishment of debt and energy services contract

(4)

Transition and business optimization costs

Transaction and Merger expenses

Restructuring, merger and transaction costs

212

(10)

(7)

(12)

Expenses incurred to upgrading and expanding a generation station

Adjusted EBITDA

$1,982

$2,888

$4,387

$2,051

$1,671

$3,999

EFH Historical Financials

Year Ended

Six Months

Pro Forma

December 31,

Ended June 30,

LTM

($ in millions)

2004

2005

2006

2007

6/30/07

(1)

Operating revenues

$9,216

$10,662

$10,856

$4,971

$3,691

$9,599

Operating costs and expenses:

Fuel, purchased power costs and delivery fees

3,755

4,261

2,784

1,179

1,404

3,165

Operating costs

1,429

1,425

1,373

684

714

1,403

Depreciation and amortization

760

776

830

413

403

1,169

Selling, general and administrative expenses

1,091

781

819

370

447

893

Franchise and revenue-based taxes

367

364

390

174

176

392

Other income

(148)

(151)

(121)

(55)

(45)

(111)

Other deductions

1,172

269

221

891

940

Total costs and expenses

$8,426

$7,501

$6,345

$2,986

$3,990

$7,851

Operating Income

$790

$3,161

$4,512

$1,985

($299)

$1,748

Net income

$485

$1,722

$2,552

$1,073

($377)

($1,002)

Provision for income taxes

632

1,263

561

(294)

(726)

Interest expense

695

802

830

431

418

3,574

Depreciation and amortization

760

776

830

413

403

1,169

EBITDA

$1,982

$3,932

$5,475

$2,478

$150

$3,015

Total Adjustments to EBITDA

960

134

152

168

2,104

2,220

Adjusted EBITDA - Restricted Payments Test

$2,942

$4,066

$5,627

$2,646

$2,254

$5,235

Capital Expenditures

(2)

$912

$1,047

$2,180

$825

$1,611

EFH Adjusted EBITDA Reconciliation

(1) Pro forma LTM period financial information includes adjustments for purchase accounting and financing related to the transaction.

Year Ended

Six Months

Pro Forma

December 31,

Ended June 30,

LTM

($ in millions)

2004

2005

2006

2007

6/30/07

(1)

Net income

$485

$1,722

$2,552

$1,073

($377)

($1,002)

Provision for income taxes

632

1,263

561

(294)

(726)

Interest expense

695

802

830

431

418

3,574

Depreciation and amortization

760

776

830

413

403

1,169

EBITDA

$1,982

$3,932

$5,475

$2,478

$150

$3,015

Adjustments to EBITDA:

Oncor EBITDA

(1,057)

(1,241)

(1,276)

(597)

(602)

(1,281)

Oncor Dividends

340

170

176

346

Interest Income

(28)

(48)

(46)

(20)

(35)

(60)

Amortization of nuclear fuel

135

Purchase Accounting Adjustments

Impairment of assets and inventory write down

192

204

201

795

798

Unrealized net (gain) or loss resulting from Hedging Obligations

109

(272)

(29)

1,182

939

Customer appreciation one-time bonus

165

Amount of loss on sales of receivables and related assets in

connection with the Receivables Facility

Income from discontinued operations, net of tax

(378)

(5)

(87)

(60)

(11)

(38)

Extraordinary (gain) or loss, net of tax

Cumulative effect of changes in accounting principles, net of tax

(8)

Non-cash compensation expenses (FAS 123R)

Severance expense

112

Equity losses of unconsolidated affiliate engaged in

broadband over power lines

Loss on early extinguishment of debt and energy services contract

416

(4)

Transition and Business Optimization Costs

Shareholder litigation

(35)

(15)

Transaction and Merger expenses

100

Restructuring & Other

271

(6)

(7)

(12)

Expenses incurred to upgrade or expand a generation station

Adjusted EBITDA (per Debt Incurrence Test)

$1,843

$2,811

$4,671

$2,211

$1,815

$4,275

Add back Oncor Adjustments

1,099

1,255

956

435

439

960

Adjusted EBITDA (per Restricted Payments Test)

$2,942

$4,066

$5,627

$2,646

$2,254

$5,235