EFH Corp.

Q2 2012 Investor Call

July 31, 2012

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 or the lenders

under

the

commodity

collateral

posting

facility

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

Q2 2012 Review

Q&A

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

Q2  11 vs. Q2 12; $ millions, after tax

1

Three months ended June 30

2

Items are noncash except for fees associated with TCEH debt amendment and extension transactions and 2011 income tax charge.

EFH Corp.

Adjusted

(Non-GAAP)

Operating

Results

-

QTR

3

Factor

Q2 11

Q2 12

Change

EFH Corp. GAAP net loss

(705)

(696)

9

Items excluded from adjusted (non-GAAP) operating results

2

(after tax):

Unrealized commodity-related mark-to-market net loss

45

395

350

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

262

68

(194)

Debt extinguishment gains

(16)

-

16

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

64

-

(64)

State income tax charge due to April 2011 TCEH amendment and extension transactions

13

-

(13)

EFH Corp. adjusted (non-GAAP) operating loss

(337)

(233)

104

1

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

Q2 11 vs. Q2 12; $ millions, after tax

EFH Corp.

Adjusted

(Non-GAAP)

Operating

Results

Key

Drivers

-

QTR

Description/Drivers

Than

Q2 11

Competitive Business¹:

Higher net margin from asset management and retail activities, including commodity hedging and economic backdown

56

Lower amortization of intangibles arising from purchase accounting

14

Higher nuclear generation due to effect of refueling outage in 2011, partially offset by outages at coal units

5

Higher fuel costs for coal and nuclear generation 

(18)

Contribution margin    

57

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

18

Lower operating costs reflecting nuclear unit refueling outage in 2011, partially offset by higher coal unit maintenance and environmental spend in 2012

12

10

Lower retail bad debt expense primarily due to improved customer

care processes

4

Higher net interest expense driven by higher average rates

(10)

All

other

-

net

2

Total

change

-

Competitive

Business

93

Regulated Business:

31

11

Higher consumption primarily due to hotter weather

4

Higher third party transmission fees

(11)

Higher depreciation and amortization reflecting infrastructure investment

(9)

Higher  operation  and  maintenance  expense  due  to  regulatory  asset  amortization  and  employee-related  costs

(6)

Higher taxes other than income driven by increased property tax rates

(3)

All

other

–

net,

primarily

effective

tax

rate

and

noncontrolling

interests

(6)

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

11

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

104

1

Competitive

Business

consists

of

Competitive

Electric

segment

and

Corporate

and

Other.

4

Higher

revenues

from

transmission

cost

recovery

charges

(largely

offsets

3

rd

party

transmission

fees

on

an

annual

basis)

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

Better (Worse)

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

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

YTD

11 vs. YTD 12; $ millions, after tax

1

2

3

EFH Corp.

Adjusted

(Non-GAAP)

Operating

Results

-

YTD

5

Factor

YTD 11

YTD 12

Change

EFH Corp. GAAP net loss

(1,066)

(1,000)

66

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

2

:

Unrealized commodity-related mark-to-market net loss

248

493

245

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

170

(6)

(176)

Debt extinguishment gain

(16)

-

16

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

64

-

(64)

Gain related to counterparty bankruptcy settlement

(14)

-

14

Income tax charges

13

-

(13)

EFH Corp. adjusted (non-GAAP) operating loss

(601)

(513)

88

3

1

Six months ended June 30

Items are noncash except for fees associated with TCEH amendment and extension debt transactions, gain related to counterparty bankruptcy settlement and 2011 income tax charge.

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

Description/Drivers

Better (Worse) 

Than

YTD 11

Competitive Business:

Higher net margin from asset management and retail activities, including commodity hedging and economic backdown

74

Lower amortization of intangibles arising from purchase accounting

30

Higher nuclear generation due to effect of refueling outage in 2011, partially offset by outages at coal units

5

Higher fuel costs reflecting increased costs of purchased coal and related transportation and higher nuclear fuel amortization

(24)

All

other

–

net

5

Contribution margin    

90

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

39

Lower operating costs reflecting nuclear plant refueling outage in 2011, partially offset by higher coal unit maintenance and environmental

spend in 2012

18

9

8

Higher net interest expense driven by higher rates

(85)

Property damage claim and sales tax refund in 2011

(8)

Other

-

net

(2)

Total

change

-

Competitive

Business

69

Regulated Business:

66

Higher

revenues

from

transmission

cost

recovery

charges

(largely

offsets

3

rd

party

transmission

fees

on

an

annual

basis)

43

Higher third party transmission fees

(30)

Higher depreciation and amortization reflecting infrastructure investment

(17)

Lower consumption primarily due to warmer weather

(13)

(11)

Higher taxes other than income driven by higher property tax rates

(6)

Higher net interest expense driven by increased borrowings

(2)

(11)

Total

change

-

Regulated

Business

(~80%

owned

by

EFH

Corp.)

19

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

88

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

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

EFH Corp.

Adjusted

(Non-GAAP)

Operating

Results

Key

Drivers

(after

tax)

-

YTD

6

Lower retail bad debt expense primarily due to improved customer care processes

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

Higher operation and maintenance expense due to regulatory asset amortization and employee-related and vegetation management costs

All other – net, primarily effective tax rate and noncontrolling interests

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)

Q2

11 vs. Q2 12 and YTD 11 vs. YTD 12;

$ millions

Q2 12

Q2 11

1,353

900

447

TCEH 

Oncor

7

11%

YTD 12

YTD 11

2,583

1,734

833

10%

858

404

1,266

1,663

755

2,432

6%

4%

7%

5%

1

1

See Appendix for Regulation G reconciliations and definition.  Includes $4 million, $6 million, $14 million and $16 million in Q2 11, Q2 12, YTD 11 and YTD 12, respectively, of Corp.

& Other Adjusted EBITDA.

Q2 and YTD performance was largely driven by the same key drivers impacting adjusted (non-

GAAP) operating results.

Luminant Operational Results

8

Nuclear-fueled generation; GWh

Coal-fueled generation; GWh

Q2

2012

Nuclear-Fueled

Plant

Results

Solid safety performance

Higher generation due to refueling

outage in Q2 2011

Top decile industry performance for

reliability and cost

Q2

2012

Coal-Fueled

Plant

Results

3.4 TWh lower generation due to more

outage days

1.2 TWh lower generation due to

increased economic backdown

Q2 12

Q2 11

4,384

9,590

YTD 11

YTD 12

10,497

5,159

31%

QTR

YTD 11

Q2 11

10,057

14,657

20,750

28,623

Q2 12

YTD 12

9%

YTD

18%

QTR

28%

YTD

9

Q2

2012

Results

Residential sales volumes declined

10.3% driven by milder weather and a

7.5% decrease in customer counts

Residential attrition rates improved

21.1% compared to Q2 2011 

Lower SMB

1

and LCI

2

volumes

reflect competitive intensity and

focus on margin discipline

Bad debt expense decreased by

49.8% in Q2 12 compared to Q2 11

due to improved customer care

processes

TXU Energy Operational Results

Total residential customers

End of period, thousands

Retail electricity sales volumes by customer class;

GWh

1,603

1,578

1

SMB –

small business

2

LCI -

large commercial and industrial

3

Latest twelve months

YTD 11

SMB

1

LCI

2

Residential

Q2 11

11,890

22,858

Q2 11

Q1 12

7.5%

LTM3

10,791

6,833

5,046

3,251

1,806

2,937

Q2 12

Q2 12

1,578

1,706

1.6%

QTR

12,777

6,509

3,572

6,131

2,596

1,599

18,774

10,326

Q2 12

YTD 12

13.2%

QTR

17.9%

YTD

16,380

17,457

32,880

33,354

19,284

18,019

9,146

9,067

10

Oncor Operational Results

Electric energy billed volumes

4

; GWh

Q2 11

Q2 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

Latest twelve months

Residential

SMB & LCI

1

3,189

3,225

1%

LTM

5

Electricity distribution points of delivery

End of period, thousands of meters

Q2 12

Q1 12

3,214

3,225

Q2 2012 Results

Higher Q2 2012 volumes principally

due to increased consumption;

lower YTD 2012 volumes due to

milder weather  

Higher SMB & LCI

1

energy volumes

due to improved economy

Execution of AMS

2

plan –

~281,000

advanced meters installed during Q2

2012; over 2.8 million installed

through June 30, 2012

$1.204 billion spent on CREZ

3

through June 30, 2012; $305 million

spent YTD 2012

1%

YTD

7%

YTD

Q2 12

25,447

26,603

52,164

51,373

1%

QTR

Q2 11

YTD 11

YTD 12

7%

QTR

EFH Corp. Liquidity Management

As of June 30, 2012

11

Cash and Equivalents

TCEH Letter of Credit Facility

TCEH Revolving Credit Facility

1,051

3,116

EFH Corp. (excluding Oncor) available liquidity

As of 6/30/12; $ millions

3,013

2,054

1,869

185

1,062

81

866

1,063

Facility Limit

LOCs/Cash Borrowings

Availability

1

As

of

June

30

,

the

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

of $866

million

supports

letters

of

credit

outstanding,

leaving

$81

million

in

available

letter

of

credit

facility.

th

1

EFH Corp. and TCEH continue to monitor capital market conditions for opportunities to ensure

liquidity needs are met and to improve financial flexibility.

12

12

12

Commodity Prices

Commodity

Units

Q2 11

Actual

Q2 12

Actual

YTD 11

Actual

YTD 12

Actual

BOY 12E

NYMEX gas price

$/MMBtu

$4.35

$2.27

$4.26

$2.36

$2.96

HSC gas price

$/MMBtu

$4.32

$2.23

$4.21

$2.32

$2.93

7x24 market heat rate (HSC)

MMBtu/MWh

8.08

10.93

8.72

10.47

15.05

North Hub 7x24 power price

$/MWh

$34.82

$24.31

$36.95

$23.88

$43.36

TCEH weighted avg. hedge

price

4

$/MMBtu

$7.35

$7.32

$7.64

$7.39

$7.32

Gulf Coast ultra-low sulfur

diesel

$/gallon

$3.08

$2.94

$2.95

$3.05

$2.74

PRB 8400 coal

$/ton

$10.36

$6.67

$10.91

$7.48

$6.38

LIBOR interest rate

5

percent

0.42%

0.73%

0.44%

0.75%

0.73%

Commodity prices

Q2 11, Q2 12, YTD 11, YTD 12 and BOY 12E; mixed measures

1

2012

estimate

based

on

average

of

monthly

commodity

prices

as

of

6/30/12

for

July

2012

through

December

2012.

2

The

actual

prices

are

computed

based

on

settled

Gas

Daily

prices

for

Henry

Hub.

3

Actual prices based on ERCOT Nodal market clearing price for North Hub.

4

Weighted

average

prices

in

the

TCEH

natural

gas

hedging

program.

Based

on

NYMEX

Henry

Hub

prices

of

forward

natural

gas

sales

positions

in

the

hedging

program

(excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions).

5

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

2

1

3

13

Factor

Measure

2012

2013

2014

Total or Avg.

3/31/12

Natural gas hedges

mm MMBtu

~225

~254

~149

~628

Wtd. avg. hedge price

1

$/MMBtu

~$7.32

~$7.19

~$7.80

Natural gas prices

$/MMBtu

~$2.50

~$3.47

~$3.96

Cum. MtM gain at 3/31/12

2

$ billions

~$1.4

~$1.0

~$0.6

~$3.0

06/30/12

Natural gas hedges

3

mm MMBtu

~155

~246

~146

~547

Wtd. avg. hedge price

1

$/MMBtu

~$7.32

~$7.19

~$7.80

Natural gas prices

4

$/MMBtu

~$2.96

~$3.58

~$3.95

Cum. MtM gain at 06/30/12

2

$ billions

~$0.8

~$1.0

~$0.6

~$2.4

Q2 12 MtM (loss) gain

$ billions

~($0.6)

~$0.0

~$0.0

~($0.6)

13

Unrealized Mark-To-Market Impact Of Hedging

Unrealized mark-to-market impact of hedging program

06/30/12 vs. 3/31/12; mixed measures, pre-tax

The value of the forward hedge program remained strong due to low natural gas prices

1

Weighted

average

prices

are

based

on

NYMEX

Henry

Hub

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. 3/31/12 prices for 2012 represent

April 1, 2012 through December 31, 2012 values and 6/30/12 prices for 2012 represent July 1, 2012 through December 31, 2012 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

6/30/12,

2012

represents

July

1,

2012

through

December

31,

2012

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 142

million MMBtu in 2014.

4

2012 represents the average of monthly forward prices for July 1, 2012 though December 31, 2012.

87

104

30

88

246

146

40

9

173

351

224

523

527

2012

2013

2014

14

14

TCEH Natural Gas Exposure

TCEH Natural Gas Position

12-14

1

; million MMBtu

Hedges Backed by Asset First Lien

Open Position

Factor

Measure

2012

2013

2014

Natural gas hedging program

million MMBtu

~128            

~246

~146

TXUE and LUME net positions

million MMBtu

~87

~30

Overall estimated percent of

total NG position hedged

percent

~96%

~67%

~33%

TXUE and Luminant Net Positions

TCEH has hedged 96% of its estimated natural gas price exposure for 2012

Hedges Backed by CCP

1

As of 6/30/12.  Balance of 2012 is from August 1, 2012 to December 31, 2012.  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).

Estimated

position

reflects

the

impact

of

Clean Air Interstate Rule (CAIR), which currently governs Luminant emissions.  Potential impacts of Cross-State Air Pollution Rule (CSAPR) following the outcome of the pending legal

proceeding are not reflected.

2

Includes estimated retail/wholesale effects. 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 ~142 million MMBtu.

3

2

~104

15

15

15

EFH Corp. Adjusted EBITDA Sensitivities

Commodity

Percent Hedged at

June 30, 2012

Change

BOY 12E Impact

$ millions

7X24 market heat rate (MMBtu/MWh)

2

~80

0.1 MMBtu/MWh

~3

NYMEX gas price ($/MMBtu)

~96

$1/MMBtu

~9

Diesel ($/gallon)

3

~100

$1/gallon

~0

Base coal ($/ton)

4

~95

$2/ton

~1

Generation operations

Nuclear-

and coal / lignite-fueled generation (TWh)

N/A

1 TWh

~15

Retail operations

BOY 2012

Residential contribution margin ($/MWh)

12 TWh

$1/MWh

~12

Residential consumption

12 TWh

1%

~4

Business markets consumption

8 TWh

1%

~1

Impact on EFH Corp. Adjusted EBITDA

12E; mixed measures

The majority of 2012 commodity-related risks are significantly mitigated.

1

2012 estimate based on commodity positions as of 6/30/12 and reflecting the impact of CAIR, net of natural gas hedges and wholesale/retail effects. Potential impacts of CSAPR following

the outcome of the pending legal proceeding are not reflected. Excludes gains and losses incurred prior to June 30, 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.

1

$0.50

$0.75

$1.88

$1.79

$2.63

2nd Lien

1st Lien

Estimate as of June 30, 2012; $ billions

EFH / EFIH

TCEH

1

1st Lien

$0.50

$0.75

2

2nd Lien

$1.29

$1.88

3

Total

$1.79

$2.63

Estimated Secured Debt Capacity at EFH / EFIH and TCEH

2, 3

4

5

$1.29

1

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. The 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

EFH Corp. debt capacity reduced by any debt issued at EFIH and/or TCEH (other than indebtedness meeting the requirements of the refinancing carve-out).

3 

EFIH debt capacity reduced by any debt issued at EFH Corp. and/or TCEH (other than indebtedness meeting the requirements of the refinancing carve-out).

4 

Of this amount, $1.0B is permitted to be issued for cash (entire amount is permitted to be issued for exchanges).

5

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.

16

17

Today’s Agenda

Q&A

Q&A

Financial and Operational

Overview

Financial and Operational

Overview

Q2 2012 Review

Q2 2012 Review

John Young

President & CEO

HSC Natural Gas Prices

$/MMBtu

ERCOT North Hub ATC (7x24) Heat Rate

MMBtu/MWh

Forward Natural Gas Prices and Heat Rates

Forward gas prices declined due to shale production and mild weather; heat rates have

risen due to an expectation of tightening reserve margins and ERCOT / PUCT actions

for resource adequacy

1

2

1

18

2

2

2014 prices became observable year-end 2011.

Calendar 2012 represents market price for the balance of the year. For example, Calendar 2012 for June 2012 represents prices from August through December.

19

1

ERCOT Capacity, Demand and Reserves (CDR) Summary, May 2012

2

Historical reserve margins based on projections for each year prior to summer peak season, based on the formula in effect at the time.

Resource Adequacy in ERCOT

3.8

13.9

14.3

9.8

6.9

6.5

'11

'12

'13

'14

'15

'16

Historical forecasts

2

Operating reserve on Aug. 3, 2011

May 2012 forecast

1

17.5

13.75% target reserve margin

(buffer against de-rates, forced

outages, wind variability, forecast

error, and weather related  spikes)

Current Market Activities:

Stakeholders have been actively working

with the PUCT and ERCOT to develop

several market enhancements:

–

Mitigated the price dampening impact

of certain reliability services(e.g.,

established minimum offer floor

pricing)

–

Took positive action to signal

regulatory support for prices indicative

of scarcity conditions

–

Increased system-wide offer cap to

$4,500

Pending PUCT/ERCOT actions and

deliberations:

–

Increase system-wide offer cap above

$4,500

–

Brattle Group recommendations

published in June for other market

enhancements, including longer-term

policy options

ERCOT reserve margin

2011A-2016E; percent

20

Today’s Agenda

Q&A

Q&A

Financial and Operational

Overview

Financial and Operational

Overview

Q2 2012 Review

Q2 2012 Review

EFH Corp. Senior Executive Team

21

Questions & Answers

22

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 allowable under the EFH Corp. 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 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.

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

Refers to the results of the Regulated Delivery segment, which consists largely of EFH Corp.’s investment in Oncor.

23

24

Table 1: EFH Corp. Adjusted EBITDA Reconciliation

Three and Six Months Ended June 30, 2011 and 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

Represents

amounts

recorded

under

stock-based

compensation

accounting

standards

and

excludes

capitalized

amounts.

3

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

4

Primarily represents Sponsor Group management fees.

5

Includes third-party fees related to the amendment and extension of the TCEH Senior Secured Facilities and settlement of amounts due from a hedging/trading counterparty. 

6

Reflects noncapital outage costs.

Factor

Q2 11

Q2 12

YTD 11

YTD 12

Net loss

(705)

(696)

(1,066)

(1,000)

Income tax benefit

(384)

(403)

(599)

(583)

Interest expense and related charges

1,301

1,019

1,945

1,804

Depreciation and amortization

371

342

740

679

EBITDA

583

262

1,020

900

Adjustments to EBITDA (pre-tax):

Oncor distributions/dividends

16

33

32

69

Interest income

-

1

(2)

(1)

Amortization of nuclear fuel

32

41

69

83

Purchase accounting adjustments

1

88

20

138

41

Impairment and write-down of assets

1

-

1

1

Debt extinguishment gains

(25)

-

(25)

-

Equity in earnings of unconsolidated subsidiary

(72)

(84)

(122)

(141)

Unrealized net loss resulting from hedging and trading transactions

69

613

385

765

Noncash compensation expense

2

3

3

3

7

Severance expense

2

-

5

1

Transition and business optimization costs

3

9

10

14

19

Transaction and merger expenses

4

9

9

18

19

Restructuring and other

5

100

(3)

73

(4)

Expenses incurred to upgrade or expand a generation station

6

64

34

100

60

EFH Corp. Adjusted EBITDA per Incurrence Covenant

879

939

1,709

1,819

Add back Oncor adjustments

387

414

723

764

EFH Corp. Adjusted EBITDA per Restricted Payments Covenant

1,266

1,353

2,432

2,583

25

Table 2: TCEH Adjusted EBITDA Reconciliation

Three and Six Months Ended June 30, 2011 and 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

Represents

amounts

recorded

under

stock-based

compensation

accounting

standards

and

excludes

capitalized

amounts.

3

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

4

Primarily represents Sponsor Group management fees.

5

Includes third-party fees related to the amendment and extension of the TCEH Senior Secured Facilities and settlement of amounts due from a hedging/trading counterparty.

6

Reflects noncapital outage costs.

7

Represents the annualization of the actual three months ended June 30, 2011 EBITDA results for Oak Grove 2. The TCEH senior secured facilities provide that upon achievement of 70%

average capacity factor the applicable unit’s EBITDA shall be included in the EBITDA calculation.

8

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

Factor

Q2 11

Q2 12

YTD 11

YTD 12

Net loss

(650)

(645)

(951)

(883)

Income tax benefit

(343)

(334)

(499)

(449)

Interest expense and related charges

1,150

831

1,651

1,453

Depreciation and amortization

364

333

726

663

EBITDA

521

185

927

784

Adjustments to EBITDA (pre-tax):

Interest income

(19)

(9)

(46)

(26)

Amortization of nuclear fuel

32

41

69

83

Purchase accounting adjustments

1

77

12

115

21

Unrealized net loss resulting from hedging and trading transactions

69

613

385

765

Net loss attributable to noncontrolling interests

-

1

-

1

EBITDA amount attributable to consolidated unrestricted subsidiaries

(1)

(2)

(3)

(4)

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

4

5

7

9

Noncash compensation expense

2

3

2

3

5

Severance expense

2

-

2

1

Transition and business optimization costs

3

9

10

15

19

Transaction and merger expenses

4

8

9

19

19

Restructuring and other

5

89

(1)

70

(3)

Expenses incurred to upgrade or expand a generation station

6

64

34

100

60

TCEH Adjusted EBITDA per Incurrence Covenant

858

900

1,663

1,734

Expenses related to unplanned generation station outages

33

23

91

49

Pro forma adjustment for Oak Grove 2 reaching 70% average capacity in Q2 2011

7

25

-

25

-

Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant

8

-

-

8

-

TCEH Adjusted EBITDA per Maintenance Covenant

916

923

1,787

1,783

26

1

Purchase accounting adjustments consist of amounts related to the accretion of an adjustment (discount) to regulatory assets.

Table 3: Oncor Adjusted EBITDA Reconciliation

Three and Six Months Ended June 30, 2011 and 2012

$ millions

Factor

Q2 11

Q2 12

YTD 11

YTD 12

Net income

92

107

157

182

Income tax expense

58

72

98

121

Interest expense and related charges

88

92

177

183

Depreciation and amortization

178

192

350

376

EBITDA

416

463

782

862

Interest income

(8)

(12)

(18)

(21)

Purchase accounting adjustments

(7)

(6)

(15)

(12)

Transition and business optimization costs and other

3

2

6

4

Oncor Adjusted EBITDA

404

447

755

833

1