Oncor Electric Delivery 8-K Deutsche Bank Annual Electric Power Conference

Exhibit 99.2

ABOUT THE COMPANY

TXU Corp., (NYSE: TXU) a Dallas-based energy company, manages a portfolio of competitive and regulated energy businesses in North America, primarily in Texas. With $9.3 billion in operating revenues in 2004, TXU ranks in the top half of the Fortune 500. TXU conducts its operations primarily through three core businesses.

TXU’s business model for competitive markets combines production, and retail and wholesale energy sales through its TXU Energy Holdings segment (TXU Energy Company LLC). The regulated electric delivery segment (TXU Electric Delivery Company), comprised of distribution and transmission assets, complements the competitive operations, delivering stable earnings and cash flow for TXU stakeholders. The electric delivery business uses its asset management skills developed over its hundred year history to provide reliable electric delivery to nearly 3 million points of delivery. It is the largest electric delivery business in the state and the sixth largest in the nation.

In its primary market of Texas, TXU’s portfolio includes over 18,300 megawatts of generation and additional contracted capacity with a fuel mix of nuclear, coal/lignite, natural gas/oil, and wind power. TXU Energy serves more than 2.4 million competitive electric customers in Texas where it is the leading energy retailer.

THIS SUMMARY

The consolidated financial data and statistics in this summary reflect the financial position and operating results of TXU through 2004.

This summary is only intended to provide limited supplemental operational and statistical information. Its contents do not constitute a complete set of financial statements prepared in accordance with generally accepted accounting principles. Accordingly, this summary is qualified in its entirety by reference to, and should be read in conjunction with, and not in lieu of, the companies’ reports, including financial statements and their accompanying notes, on file with the Securities and Exchange Commission.

Independent auditors have not audited all of the financial and operating statements. This summary has been prepared primarily for security analysts and investors in the hope that it will serve as a convenient and useful resource. The format of this summary may change in the future as we continue to try to meet the needs of our investors. The company does not undertake to update any of the information in this summary.

This summary is not intended for use in connection with any sale, offer to sell, or solicitation of any offer to buy any securities of TXU Corp. or its subsidiaries. Inquiries concerning this summary should be directed to Investor Relations:

Tim Hogan

214-812-4641

Bill Huber

214-812-2480

Steve Oakley

214-812-2220

CONTENTS Last Update: May 2005

Statements of Consolidated Income	2
Reconciliation of Operational Earnings to Reported Net Income	3
Statements of Consolidated Cash Flows	4
Consolidated Balance Sheets	6
Operating Statistics – TXU Electric Delivery	7
Operating Statistics – TXU Power	11
Operating Statistics – TXU Energy	19
ERCOT/Texas Market/Regulatory Highlights	25
Schedule of Long-Term Debt	30
Schedule of Preferred Securities	32
Common Stock Data and Credit Ratings	33
Liquidity and Capital Expenditures	34
Definitions	35
Investor Information	36

1

TXU CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

	Year Ended December 31,
	2004			2003			2002
	(millions of dollars, except per share amounts)
Operating revenues	$	9,308		$	8,600		$	8,094
Costs and expenses:
Cost of energy sold and delivery fees		3,847			3,640			3,199
Operating costs		1,429			1,389			1,354
Depreciation and amortization		760			724			733
Selling, general and administrative expenses		1,091			907			1,046
Franchise and revenue-based taxes		367			390			428
Other income		(148	)		(58	)		(41	)
Other deductions		1,172			42			533
Interest income		(28	)		(36	)		(33	)
Interest expense and related charges		695			784			693
Total costs and expenses		9,185			7,782			7,912
Income from continuing operations before income taxes, extraordinary gain (loss) and cumulative effect of changes in accounting principles		123			818			182
Income tax expense		42			252			77
Income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles		81			566			105
Income (loss) from discontinued operations, net of tax effect		378			74			(4,181	)
Extraordinary gain (loss), net of tax effect		16			—			(134	)
Cumulative effect of changes in accounting principles, net of tax effect		10			(58	)		—
Net income (loss)		485			582			(4,210	)
Exchangeable preferred membership interest buyback premium		849			—			—
Preference stock dividends		22			22			22
Net income (loss) available for common stock	$	(386	)	$	560		$	(4,232	)
Average shares of common stock outstanding (millions):
Basic		300			322			278
Diluted		300			379			278
Per share of common stock— Basic:
Income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles	$	0.27		$	1.76		$	0.37
Exchangeable preferred membership interest buyback premium		(2.83	)		—			—
Preference stock dividends		(0.07	)		(0.07	)		(0.08	)
Net income (loss) from continuing operations available for common stock		(2.63	)		1.69			0.29
Income (loss) from discontinued operations, net of tax effect		1.26			0.23			(15.04	)
Extraordinary gain (loss), net of tax effect		0.05			—			(0.48	)
Cumulative effect of changes in accounting principles, net of tax effect		0.03			(0.18	)		—
Net income (loss) available for common stock	$	(1.29	)	$	1.74		$	(15.23	)
Per share of common stock— Diluted:
Income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles	$	0.27		$	1.63		$	0.37
Exchangeable preferred membership interest buyback premium		(2.83	)		—			—
Preference stock dividends		(0.07	)		(0.06	)		(0.08	)
Net income (loss) from continuing operations available for common stock		(2.63	)		1.57			0.29
Income (loss) from discontinued operations, net of tax effect		1.26			0.20			(15.04	)
Extraordinary gain (loss), net of tax effect		0.05			—			(0.48	)
Cumulative effect of changes in accounting principles, net of tax effect		0.03			(0.15	)		—
Net income (loss) available for common stock	$	(1.29	)	$	1.62		$	(15.23	)
Dividends declared	$	0.938		$	0.50		$	1.925

2

TXU CORP. AND SUBSIDIARIES

RECONCILIATION OF OPERATIONAL EARNINGS TO REPORTED NET INCOME

Reconciliation of Operational Earnings¹ to Reported Net Income

For the years ended December 31, 2003 and 2004; $ per share after tax

Factor	04		03
Net income (loss) to common	(1.29	)	1.62
Discontinued operations	(1.26	)	(0.20	)
Extraordinary gain	(0.05	)	—
Cum. effect of changes in accounting principles	(0.03	)	0.15
Premium on EPMIs	2.83		—
Preference stock dividends	0.07		0.06
Income (loss) from continuing operations	0.27		1.63
Preference stock dividends	(0.07	)	(0.06	)
Effect of diluted shares calculation	0.04		0.01
Special items	2.58		—
Operational earnings	2.82		1.58

Description of Special Items

For the year ended December 31, 2004; $millions and $ per share after tax

Special Item	Main Earnings Category	Amount		Per Share		Cash		Non-Cash2
Energy segment:
Software projects write-off	Other deductions	69		0.22		—		69
Severance and related expenses	Other deductions	72		0.22		45		27
Inventory/gas plant write-downs	Other deductions	55		0.17				55
Lease termination expense	Other deductions	117		0.37		15		102
Power contract settlement expense	Other deductions	66		0.20		112		(46	)
Disposition of property	Other income	(50	)	(0.15	)	(12	)	(38	)
Other charges	Other deductions	10		0.03		10
Electric Delivery segment:
Rate case settlement reserve	Other deductions	14		0.04		—		14
Severance/other expenses	Other deductions	19		0.06		11		8
Corporate and Other:
One-time compensation expense	SG&A	51		0.16		51		—
Transaction professional fees	SG&A	35		0.11		35		—
Litigation settlement expense	Other deductions	56		0.17		—		56
Liability management expense	Other deductions income/deductions	384		1.20		382		2
Severance charges and other	Other deductions	5		0.02		5		—
Income tax benefit	Income tax expense	(75	)	(0.24	)	—		(75	)
Total		828		2.58		654		174

¹ Operational earnings is a non-GAAP measure that adjusts net income for special items. See Definitions for a

detailed definition of operational earnings.

² While these items are reflected in earnings for the current period, the cash impact, if any, will be realized in future periods. These items are considered non-cash for the current period.

3

TXU CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

	Year Ended December 31,
	2004			2003			2002
	(millions of dollars)
Cash flows — operating activities
Income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles	$	81		$	566		$	105
Adjustments to reconcile income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles to cash provided by operating activities:
Depreciation and amortization		826			791			804
Deferred income taxes and investment tax credits — net		(11	)		(40	)		21
Losses on early extinguishment of debt		416			—			40
Asset writedowns and lease-related charges		376			—			237
Net gain from sales of assets		(135	)		(45	)		(30	)
Net effect of unrealized mark-to-market valuations of commodity contracts		109			100			113
Litigation settlement charge		84			—			—
Bad debt expense		90			119			160
Stock-based compensation expense		56			25			1
Net equity (income) loss from unconsolidated affiliates and joint ventures		(1	)		17			255
Change in regulatory-related liabilities		(70	)		(144	)		34
Changes in operating assets and liabilities:
Accounts receivable—trade		(246	)		173			(632	)
Impact of accounts receivable sales program		(73	)		100			(15	)
Inventories		15			(46	)		(48	)
Accounts payable—trade		185			(24	)		108
Commodity contract assets and liabilities		(5	)		24			(45	)
Margin deposits—net		34			25			—
Other — net assets		(133	)		290			(97	)
Other — net liabilities		160			482			41
Cash provided by operating activities		1,758			2,413			1,052
Cash flows — financing activities
Issuances of securities:
Long-term debt		5,090			2,846			4,446
Common stock		112			23			1,274
Retirements/repurchases of securities:
Long-term debt held by subsidiary trusts		(546	)		—			—
Equity-linked debt securities		(1,105	)		—			—
Other long-term debt		(3,088	)		(2,187	)		(3,407	)
Exchangeable preferred membership interests		(750	)		—			—
Preferred securities of subsidiaries		(75	)		(98	)		—
Common stock		(4,687	)		—			—
Change in notes payable:
Commercial paper		—			—			(854	)
Banks		210			(2,305	)		1,490
Cash dividends paid:
Common stock		(150	)		(160	)		(652	)
Preference stock		(22	)		(22	)		(22	)
Premium paid for redemption of exchangeable preferred membership interests		(1,102	)		—			—
Redemption deposits applied to debt retirements		—			210			(210	)
Debt premium, discount, financing and reacquisition expenses		(406	)		(38	)		(283	)
Cash provided by (used in) financing activities		(6,519	)		(1,731	)		1,782

4

TXU CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)

	Year Ended December 31,
	2004			2003			2002
	(millions of dollars)
Cash flows — investing activities
Capital expenditures		(912	)		(721	)		(813	)
Dispositions of businesses		4,814			14			—
Acquisition of telecommunications partner’s interest		—			(150	)		—
Proceeds from sales of assets		27			10			447
Change in collateral trust		525			(525	)		—
Nuclear fuel		(87	)		(44	)		(51	)
Other, including transaction costs		(87	)		16			(186	)
Cash provided by (used in) investing activities		4,280			(1,400	)		(603	)
Discontinued operations
Cash provided by (used in) operating activities		(79	)		338			203
Cash provided by (used in) financing activities		(10	)		97			(966	)
Cash used in investing activities		(153	)		(409	)		(210	)
Effect of exchange rate changes		—			8			60
Cash provided by (used in) discontinued operations		(242	)		34			(913	)
Net change in cash and cash equivalents		(723	)		(684	)		1,318
Cash and cash equivalents — beginning balance		829			1,513			195
Cash and cash equivalents — ending balance	$	106		$	829		$	1,513

5

TXU CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2004		2003
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	106	$	829
Restricted cash		49		12
Accounts receivable — trade		1,274		1,016
Income taxes receivable		25		—
Inventories		320		419
Commodity contract assets		546		548
Accumulated deferred income taxes		224		94
Assets of telecommunications holding company		—		110
Other current assets		249		196
Total current assets		2,793		3,224
Investments:
Restricted cash		47		582
Other investments		664		632
Property, plant and equipment — net		16,676		16,803
Goodwill		542		558
Regulatory assets — net		1,891		1,872
Commodity contract assets		315		109
Cash flow hedge and other derivative assets		6		88
Other noncurrent assets		283		214
Assets held for sale		24		7,202
Total assets	$	23,241	$	31,284
LIABILITIES, PREFERRED SECURITIES OF SUBSIDIARIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Notes payable - banks	$	210	$	—
Long-term debt due currently		229		678
Accounts payable — trade		950		790
Commodity contract liabilities		491		502
Litigation and other settlement accruals		391		—
Liabilities of telecommunications holding company		—		603
Other current liabilities		1,445		1,322
Total current liabilities		3,716		3,895
Accumulated deferred income taxes		2,721		3,599
Investment tax credits		405		430
Commodity contract liabilities		347		47
Cash flow hedge and other derivative liabilities		195		240
Long-term debt held by subsidiary trusts		—		546
All other long-term debt, less amounts due currently		12,412		10,608
Other noncurrent liabilities and deferred credits		2,762		2,289
Liabilities held for sale		6		2,952
Total liabilities		22,564		24,606
Preferred securities of subsidiaries		38		759
Contingencies
Shareholders’ equity		639		5,919
Total liabilities, preferred securities of subsidiaries and shareholders’ equity	$	23,241	$	31,284

6

OPERATING STATISTICS – TXU ELECTRIC DELIVERY

TXU Electric Delivery¹ consists of regulated electricity transmission and distribution operations in Texas. TXU Electric Delivery provides the essential service of delivering electricity safely, reliably, and economically to approximately three million electric delivery points, or about a third of the state’s population. It is the largest electric transmission and distribution business in the state and the sixth largest in the nation.

Description of TXU Electric Delivery Business

TXU Electric Delivery owns and operates more than 100,000 miles of electric distribution lines and over 14,000 miles of electric transmission lines. The operating assets are located principally in the north-central, eastern and western parts of Texas. TXU Electric Delivery operates within the Electric Reliability Council of Texas (ERCOT) system. ERCOT is an intrastate network of investor-owned entities, cooperatives, public entities, non-utility generators and power marketers.

Electricity Distribution

TXU’s distribution business is responsible for the overall safe and efficient operation of distribution facilities, including power delivery, power quality and system reliability. The electricity distribution business owns, manages, constructs, maintains and operates the distribution system within its certificated service area. Over the past five years, the number of TXU Electric Delivery’s distribution premises served has been growing at an average rate of 2% per year. TXU’s distribution system receives electricity from the transmission system through substations and distributes electricity to end users and wholesale customers through 2,943 distribution feeders.

Distribution Facts

As of December 31, 2000 – 2004; Mixed measures

Item	2004	2003	2002	2001	2000
Transformer Capacity (MVA)	49,462	47,991	46,722	45,503	43,949
Circuit Miles of Line	99,638	98,286	96,847	95,793	94,644
Count of Load Serving Substations	785	780	776	774	772
Distribution Feeders	2,943	2,914	2,884	2,867	2,831
Electric Delivery Owned Poles2	1,898,312	1,886,284	1,877,954	1,893,714	1,885,040
Third Party Poles3	295,468	297,188	296,218	270,649	270,620

Electric Transmission

TXU’s electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction and maintenance of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over TXU Electric Delivery’s transmission facilities in coordination with ERCOT. The transmission business participates with ERCOT and other member utilities to plan, design, construct, and operate new transmission lines, with regulatory approval, necessary to maintain reliability, increase bulk power transfer capability and to minimize limitations and constraints on the ERCOT transmission grid.

¹ TXU Electric Delivery operated under the name ‘Oncor Electric Delivery’ during 2003 and 2002.

² Approximately 30,000 poles sold during the 2000 to 2002 timeframe.

³ Count of third party poles contacted.

7

OPERATING STATISTICS – ELECTRIC DELIVERY

Transmission Facts

As of December 31, 2000 – 2004; Mixed measures

Item	2004	2003	2002	2001	2000
Transformer Capacity (MVA)	75,533	70,890	68,385	68,089	66,893
Circuit Miles of Line	14,191	14,180	14,137	14,010	13,815
Count of Substations, Switching Stations and Plant Switchyards	950	950	946	941	935
Transmission Circuit Breakers	5,825	5,749	5,633	5,569	5,466
Interconnection to Generation Facilities	40	43	41	38	34
Interconnection to Other Transmission Providers	248	241	200	217	211

Key Operational Metrics

For years ended December 31, 2000 – 2004; Mixed measures

Metric	2004		2003		2002		2001		2000
Non-Storm SAIDI (minutes)1	75.54		74.15		90.36		81.77		87.46
Non-Storm SAIFI (frequency)1	1.10		1.17		1.39		1.23		1.37
Non-Storm CAIDI (minutes)1	68.67		63.30		64.81		66.48		63.84
Meter Reading Accuracy	99.91	%	99.89	%	99.92	%	99.91	%	99.90	%
DART Incident Rate	1.96		1.73		1.87		2.35		2.30
Regulatory Complaints2	484		367		394		852		297

Selected Financial Metrics

For years ended December 31, 2000 – 2004; $ millions, %

Metric	2004		2003		2002		20013		20003
Total Operating Revenues	2,226		2,087		1,994		2,314		2,081
Total Operating Expenses	1,697		1,565		1,517		1,820		1,597
Net Income Before Extraordinary Items	255		258		245		228		226
Property, Plant & Equipment – Net	6,609		6,333		6,056		5,802		5,445
Capital Expenditures	600		543		513		635		517
Capitalization Ratios
Long-term debt, less amounts due currently	61.0	%	58.2	%	60.6	%	54.9	%	52.1	%
Shareholder Equity	39.0	%	41.8	%	39.4	%	45.1	%	47.9	%
Capitalization Ratios (without transition bonds)4
Long-term debt, less amounts due currently	53.2	%	55.1	%	60.6	%	54.9	%	52.1	%
Shareholder Equity	46.8	%	44.9	%	39.4	%	45.1	%	47.9	%

¹ Based on all outages greater than one minute in duration.

² Complaints spiked in 2001 due to implementation of the pilot prior to the opening of the Texas electricity market to competition, and increased public awareness of the PUC’s involvement in regulating electric utilities. 2001 includes statistics for both TXU Electric Delivery and TXU Energy. The increase in 2004 vs 2003 is significantly due to a series of severe storms that struck North Texas during the week of June 1, 2004. Over one million customers lost power during this week and many experienced extended outages.

³ The 2000 and 2001 financial information for TXU Electric Delivery includes information derived from the historical financial statements of TXU Electric Company. Reasonable allocation methodologies were used to unbundle the financial statements of TXU Electric Company between its generation, retail and T&D operations. Allocation of revenues reflected consideration of return on invested capital, which continues to be regulated for the T&D operations. TXU Electric maintained expense accounts for each of its functional operations. Costs of O&M, plant and equipment and depreciation, as well as other assets and liabilities were specifically identified by component and function and then disaggregated. Interest and other financing costs were determined based upon debt allocated. Allocations reflected in the financial information for 2000 and 2001 did not necessarily result in amounts reported in individual line items that are comparable to actual results in 2002. Had the unbundled T&D operations of TXU US Holdings actually existed as a separate legal entity, its results of operations could have differed materially from those included in the historical financial statements of TXU Electric.

⁴ Excludes securitization bonds issued in years 2003 and 2004, as such bonds are serviced by transition charges and are excluded from debt in credit analyses and for regulatory rate proceedings.

8

OPERATING STATISTICS – TXU ELECTRIC DELIVERY

Service Performance Statistics

TXU Electric Delivery finished 2004 as the best performing transmission and distribution service provider (TDSP) by performing at or above market average in 5 out of 7 key ERCOT service categories. TXU Electric Delivery had 49% of the total ERCOT market transactions.

Service Performance Statistics

For the year ended 12/31/04; %

Service Category	ERCOT Report Market Average		TXU
Scheduling of Switches	99.7	%	99.8	%
Scheduling of Move-ins	Unavailable		99.97	%
On Schedule Completion of Switches	86.6	%	98.3	%
On Schedule Completion of Move-ins	85.9	%	91.6	%
Providing Historical Usage	98.0	%	97.0	%
Loading of IDR Metering Data	99.7	%	99.8	%
Loading of NIDR Metering Data	99.7	%	99.6	%

Regulatory Environment

TXU Electric Delivery is subject to regulation by Texas authorities. TXU Electric Delivery provides delivery services to Retail Electric Providers (REPs) who sell electricity to retail customers; consequently, the electric delivery business has no commodity supply or price risk. TXU Electric Delivery believes that it operates in a favorable regulatory environment, as evidenced by a regulatory provision that allows annual updates of transmission rates to reflect changes in invested capital. This provision encourages investment in the transmission system to help ensure reliability and efficiency by allowing for timely recovery and return on new transmission investments.

General Rate Information

TXU Electric Delivery has an authorized return on equity of 11.25%. In the fourth quarter of 2004, TXU Electric Delivery recorded a $21 million ($14 million after-tax) charge for estimated settlement payments. The settlement, which was finalized February 22, 2005, is the result of a number of municipalities initiating an inquiry regarding distribution rates. The agreement avoids any immediate rate actions, but would require TXU Electric Delivery to file a rate case in 2006, based on a 2005 test year, unless the municipalities and TXU Electric Delivery mutually agree that such a filing is unnecessary. The final settlement amounts are being determined; however TXU Electric Delivery believes the total will closely approximate the amount accrued.

Transmission Cost of Service (TCOS) and Transmission Cost Recovery Factor (TCRF)

ERCOT transmission service providers (TSPs) recover their TCOS through a network transmission service rate approved by the Public Utility Commission of Texas (PUC). ERCOT TSPs bill their wholesale network transmission service charges to ERCOT distribution utilities, by applying their approved wholesale transmission rates to the distribution utilities’ average loads for the prior summer¹. Distribution utilities² are billed for wholesale transmission service by all ERCOT TSPs. Distribution utilities² recover these transmission fees by billing the REPs a base retail transmission charge. In the Utility Cost of Service (UCOS) cases, the distribution utilities established base retail transmission charges by rate class. These rates are in addition to the base retail distribution system wires charges and other non-bypassable charges that are billed to retail electric providers.

In the latest wholesale transmission rulemaking, the PUC approved a new rule section, Distribution Service Provider TCRF. The purpose of this rule section is to allow distribution service providers to pass through wholesale transmission rate increases without the need for a distribution utility rate case. The TCRF rule allows distribution utilities to update the TCRF on March 1 and September 1 each year. The TCRF charges are billed in addition to the base retail transmission wires charges.

¹ The load for a distribution utility is the average demand at the time of the ERCOT peak for the months of June, July, August, and September.

² Investor Owned Utilities (IOU’s) and other entities participating in customer choice.

9

OPERATING STATISTICS – TXU ELECTRIC DELIVERY

Wire Rate Charges

As shown in the chart below, TXU Electric Delivery has the lowest basic wires rate in the State of Texas.

Operational Wires Rates Comparison – Residential with TCRF Factors (as of March 1, 2005)

Charge	TXU		CenterPoint		AEP Central		AEP North		TNMP
Customer Charge	$	2.74/cust/month	$	2.39/cust/month	$	2.58/cust/month	$	4.58/cust/month	$	0.33/cust/month
Metering Charge	$	2.21/cust/month	$	1.91/cust/month	$	2.38/cust/month	$	4.78/cust/month	$	3.58/cust/month
Merger Savings/Rate Reduction Charge	$	0.00/cust/month	$	0.00/cust/month		($0.28)/cust/month		($0.48)/cust/month	$	0.00/cust/month
Subtotal, Fixed Charges	$	4.95/cust/month	$	4.30/cust/month	$	4.68/cust/month	$	8.88/cust/month	$	3.91/cust/month
Distribution System Charge	$	0.014070/kWh	$	0.018870/kWh	$	0.015628/kWh	$	0.019863/kWh	$	0.017291/kWh
Transmission System Charge	$	0.004493/kWh	$	0.004310/kWh	$	0.003712/kWh	$	0.004638/kWh	$	0.004150/kWh
Transmission Cost Recovery Factor	$	0.000899/kWh	$	0.000752/kWh	$	0.000705/kWh	$	0.000972/kWh	$	0.000866kWh
Subtotal, Basic Wires Charges	$	0.019462/kWh	$	0.023932/kWh	$	0.020045/kWh	$	0.025473/kWh	$	0.022307/kWh
System Benefit Fund	$	0.000655/kWh	$	0.000655/kWh	$	0.000662/kWh	$	0.000660/kWh	$	0.000654/kWh
Nuclear Decommissioning Charge	$	0.000169/kWh		Included in base chges		n/a		n/a		n/a
Transition Charge	$	0.000712/kWh	$	0.000939/kWh	$	0.004241/kWh		n/a		n/a
Excess Mitigation Credit		Expired 12/31/03		($0.004873)/kWh		($0.000822)/kWh		n/a		n/a
Merger Savings/Rate Reduction Riders		n/a		n/a		($ 0.001095)/kWh		($0.001248)/kWh		n/a
Customer Charge and Wires Charge (no non-by passable charges) for 1,000 kWh	$	24.41	$	28.23	$	24.73	$	34.35	$	26.22
Customer Charge and Wires Charge (no non-by passable charges) for 1,300 kWh	$	30.25	$	35.41	$	30.74	$	41.99	$	32.91
Total Wires Charge for 1,000 kWh	$	25.95	$	24.95	$	27.71	$	33.77	$	26.87
Total Wires Charge for 1,300 kWh	$	32.25	$	31.15	$	34.62	$	41.23	$	33.76
TXU Electric Delivery’s average residential consumption for 2004 was approximately 1,300 kWh.

Rate Base

For the period ending December 31, 2004, TXU Electric Delivery’s Adjusted Total Invested Capital¹ is approximately $5,644,507,000, as compared to 2003 Adjusted Total Invested Capital of $5,381,055,975.

¹ Adjusted Total Invested Capital = Total Invested Capital – [Construction Work in Progress + Plant Held for Future Use]

10

OPERATING STATISTICS – TXU POWER

TXU Power’s generating facilities provide the capability to supply a significant portion of the wholesale electricity market demand in Texas, particularly in the North Texas market, at competitive production costs. Low cost nuclear-fueled and lignite/coal-fired (base load) generation is available to supply the electricity demands of its retail customers and other competitive retail electric providers. The generating fleet in Texas consists of 19 owned or leased plants with generating capacity fueled as follows: 2,300 MW nuclear; 5,837 MW coal/lignite; and 10,228 MW gas/oil.

Generating Plant Facts – Texas

Fact	Nuclear	Lignite/Coal	Gas/Oil	Total
Number of Generating Units	2	9	45	56
2004 Installed Capacity (MWs)	2,300	5,837	10,228	18,365
Annual Generation (3 year average MWhs)	17,793,690	42,391,417	12,168,793	72,353,900

Generating Plant Locations – Texas

11

OPERATING STATISTICS – TXU POWER

Unit Statistics and Information – Texas

As of 12/31/04; MW

Plant	Unit	Fuel type	Type	Year in Service1	County	Installed Capacity
Comanche Peak	1	Nuclear	Base load	1990	Somervell	1,150
Comanche Peak	2	Nuclear	Base load	1993	Somervell	1,150
Subtotal						2,300
Big Brown	1	Lignite/Coal	Base load	1971	Freestone	575
Big Brown	2	Lignite/Coal	Base load	1972	Freestone	575
Monticello	1	Lignite/Coal	Base load	1974	Titus	565
Monticello	2	Lignite/Coal	Base load	1975	Titus	565
Monticello	3	Lignite/Coal	Base load	1978	Titus	750
Martin Lake	1	Lignite/Coal	Base load	1977	Rusk	750
Martin Lake	2	Lignite/Coal	Base load	1978	Rusk	750
Martin Lake	3	Lignite/Coal	Base load	1979	Rusk	750
Sandow	4	Lignite/Coal	Base load	1981	Milam	557
Subtotal						5,837
Collin (M)	1	Gas/Oil	Gas - Cycling	1955	Collin	153
DeCordova	1	Gas/Oil	Gas - Intermediate	1975	Hood	818
DeCordova 4 CT’s2		Gas/Oil	Gas - Peaking	1990	Hood	260
Eagle Mountain (M)	1	Gas/Oil	Gas - Cycling	1954	Tarrant	115
Eagle Mountain (M)	2	Gas/Oil	Gas - Cycling	1956	Tarrant	175
Eagle Mountain (RMR)	3	Gas/Oil	Gas - Cycling	1971	Tarrant	375
Graham	1	Gas/Oil	Gas - Cycling	1960	Young	240
Graham	2	Gas/Oil	Gas - Intermediate	1969	Young	390
Lake Creek	1	Gas/Oil	Gas - Cycling	1953	McLennan	87
Lake Creek	2	Gas/Oil	Gas - Cycling	1959	McLennan	230
Lake Hubbard	1	Gas/Oil	Gas - Cycling	1970	Dallas	393
Lake Hubbard	2	Gas/Oil	Gas - Intermediate	1973	Dallas	528
Morgan Creek (M)	5	Gas/Oil	Gas - Cycling	1959	Mitchell	175
Morgan Creek (M)	6	Gas/Oil	Gas - Intermediate	1966	Mitchell	511
Morgan Creek 6 CT’s2		Gas/Oil	Gas - Peaking	1988	Mitchell	390
North Lake (M)	1	Gas/Oil	Gas - Cycling	1959	Dallas	175
North Lake (M)	2	Gas/Oil	Gas - Cycling	1961	Dallas	175
North Lake (M)	3	Gas/Oil	Gas - Cycling	1964	Dallas	365
Permian Basin	5	Gas/Oil	Gas - Cycling	1959	Ward	115
Permian Basin	6	Gas/Oil	Gas - Intermediate	1973	Ward	540
Permian Basin 5 CT’s2		Gas/Oil	Gas - Peaking	1990	Ward	325
Stryker Creek	1	Gas/Oil	Gas - Cycling	1958	Cherokee	175
Stryker Creek	2	Gas/Oil	Gas - Intermediate	1965	Cherokee	500
Tradinghouse	1	Gas/Oil	Gas - Intermediate	1970	McLennan	565
Tradinghouse	2	Gas/Oil	Gas - Intermediate	1972	McLennan	818
Valley (M)	1	Gas/Oil	Gas - Cycling	1962	Fannin	175
Valley (M)	2	Gas/Oil	Gas - Intermediate	1967	Fannin	550
Valley (M)	3	Gas/Oil	Gas - Cycling	1971	Fannin	390
Trinidad	6	Gas/Oil	Gas - Cycling	1965	Henderson	240
Sweetwater	4	Gas/Oil	Gas - Cycling	1989	Nolan	85
Sweetwater 3 CTs2		Gas/Oil	Gas - Peaking	1989	Nolan	175
Diesels3						20
Subtotal						10,228
Total						18,365

(M) – Mothballed (RMR) – Reliability Must Run for ERCOT

¹ Average useful lives: nuclear (60 years), lignite (50 years), gas (51 years), and gas CT’s (27 years)

² CT - Combustion Turbine; DeCordova and Permian Basin CT capacity is under a purchase power agreement.

³ Diesels are located at Lake Creek (3), Stryker Creek (5) and Trinidad (2).

12

OPERATING STATISTICS – TXU POWER

Nuclear Plant Statistics

Item	CPSES Unit 1	CPSES Unit 2
Commercial Operation Date	August 1990	August 1993
License Expiration Date	February 2030	February 2033
Architect/Engineer	Gibbs & Hill	Gibbs & Hill
Reactor Manufacturer	Westinghouse	Westinghouse
Reactor Type	PWR	PWR
Turbine Generator Manufacturer	Siemens	Siemens
Maximum Dependable Capacity (MW)	1,150	1,150
Refueling Data
Last Date	March 27, 2004	March 26, 2005
# of Days	38	32
Next Scheduled Refueling	Fall 2005	Fall 2006

13

OPERATING STATISTICS – TXU POWER

Net Generation – Texas

For years ended December 31, 2000 – 2004; MWh

Plant	Unit	2004		2003		2002		2001	2000
Comanche Peak	1	9,013,792		9,625,953		7,785,265		8,444,318	9,619,797
Comanche Peak	2	10,038,851		8,123,390		8,793,819		9,877,947	8,868,045
Subtotal		19,052,643		17,749,343		16,579,084		18,322,265	18,487,842
Big Brown	1	3,837,349		4,587,394		4,362,128		3,733,166	4,230,742
Big Brown	2	4,464,491		3,875,181		3,558,722		3,539,669	4,314,241
Monticello	1	4,305,393		4,134,558		3,711,998		3,646,758	4,143,518
Monticello	2	4,465,894		3,704,847		4,030,192		4,024,631	3,478,659
Monticello	3	5,277,059		5,666,922		5,385,687		4,904,882	4,748,085
Martin Lake	1	5,958,153		4,847,711		5,148,997		5,104,000	5,596,189
Martin Lake	2	5,339,493		5,781,564		5,079,555		4,812,971	5,433,020
Martin Lake	3	5,941,004		5,855,120		4,596,454		5,305,204	5,492,880
Sandow	4	4,527,603		4,787,459		3,943,323		4,434,912	3,556,611
Subtotal		44,116,439		43,240,756		39,817,056		39,506,193	40,993,945
Collin (M)	1	(1,217	)	98,879		74,572		191,886	297,464
DeCordova	1	206,385		1,414,916		2,974,511		3,338,979	3,911,118
DeCordova CT’s		97,164		54,144		68,125		102,052	181,854
Eagle Mountain (M)	1	20,071		57,865		101,874		74,725	148,244
Eagle Mountain (M)	2	23,719		79,830		193,175		197,646	256,133
Eagle Mountain (RMR)	3	208,557		479,676		526,756		317,572	531,411
Graham	1	117,645		186,907		564,898		452,737	931,078
Graham	2	396,060		575,707		651,729		803,227	1,362,246
Lake Creek	1	(2,223	)	1,858		29,460		64,960	208,005
Lake Creek	2	69,041		83,025		281,967		472,369	691,554
Lake Hubbard	1	129,333		400,926		414,224		462,944	802,460
Lake Hubbard	2	576,784		1,235,607		1,270,631		1,584,785	1,863,522
Morgan Creek (R)	2	(347	)	(1,561	)	(1,478	)	1,492	22,510
Morgan Creek (R)	3	(177	)	(626	)	(719	)	3,812	16,203
Morgan Creek (R)	4	(418	)	(1,569	)	6,343		37,413	127,195
Morgan Creek (M)	5	39,166		121,329		232,540		365,920	568,993
Morgan Creek (M)	6	42,720		629,540		842,029		1,979,522	2,687,161
Morgan Creek CT’s		80,773		38,492		43,183		68,387	174,584
North Lake(M)	1	83,889		226,630		352,048		339,274	337,409
North Lake (M)	2	89,555		167,805		309,276		378,195	461,831
North Lake (M)	3	340,276		479,022		610,546		608,939	1,120,695
North Main (R)	4	(181	)	(832	)	56,863		14,775	145,506
Parkdale (R)	1	(285	)	12,203		62,470		50,900	141,342
Parkdale (R)	2	(169	)	21,096		99,219		81,301	209,655
Parkdale (R)	3	(195	)	30,029		124,749		120,699	263,059
Permian Basin	5	17,241		40,019		95,770		221,266	321,259
Permian Basin	6	904,003		1,802,737		2,136,339		2,367,173	2,607,556
Permian Basin CT’s		72,416		35,266		31,412		62,367	165,561
River Crest (R)	6	(140	)	(833	)	(584	)	8,348	183,042
Stryker Creek	1	3,820		72,005		56,704		312,232	449,959
Stryker Creek	2	506,676		1,019,363		1,058,502		1,417,285	1,921,490
Tradinghouse	1	121,069		552,739		1,483,468		1,520,938	1,806,095
Tradinghouse	2	186,958		1,548,337		1,578,856		3,568,742	3,595,258
Valley (M)	1	5,851		141,253		192,241		327,436	496,770
Valley (M)	2	(989	)	325,731		1,236,428		1,668,866	2,086,165
Valley (M)	3	823		95,422		199,461		366,490	610,776
Trinidad	6	45,330		144,262		218,517		415,436	397,010
Sweetwater	4	76,293		244,802		153,002		—	—
Sweetwater CT	1	44,560		65,316		85,440		—	—
Sweetwater CT	2	92,595		290,888		39,504		—	—
Sweetwater CT	3	81,478		330,777		279,435		—	—
Subtotal		4,673,910		13,098,982		18,733,486		24,371,090	32,102,173
Total		67,842,992		74,089,081		75,129,626		82,199,548	91,583,960

Note: Excludes Handley and Mountain Creek Units sold in 2002.	(R) Retired during 2004.
(M) Mothballed	(RMR) Reliability Must Run for ERCOT

14

OPERATING STATISTICS – TXU POWER

Unit Capacity Factors – Texas

For years ended December 31, 2000 – 2004; %

Plant	Unit	2004	2003	2002	2001	2000
Comanche Peak	1	89.2	95.6	77.2	83.8	95.2
Comanche Peak	2	99.4	80.6	87.2	98.1	87.7
Big Brown	1	76.0	91.1	86.6	74.1	83.8
Big Brown	2	88.4	76.9	70.7	70.3	85.4
Monticello	1	86.8	83.5	75.0	73.7	83.5
Monticello	2	90.0	74.9	81.4	81.3	70.1
Monticello	3	80.1	86.3	82.0	74.7	72.1
Martin Lake	1	90.4	73.8	78.4	77.7	84.9
Martin Lake	2	81.0	88.0	77.3	73.3	82.5
Martin Lake	3	90.2	89.1	70.0	80.7	83.4
Sandow	4	94.6	100.3	82.6	92.9	74.3
Collin (M)	1	—	7.4	5.6	14.3	22.1
DeCordova	1	2.9	19.7	41.5	46.6	54.4
Decordova CT’s		3.5	1.9	2.4	3.6	6.5
Eagle Mountain (M)	1	2.0	5.7	10.1	7.4	14.7
Eagle Mountain (M)	2	1.5	5.2	12.6	12.9	16.7
Eagle Mountain (RMR)	3	6.3	14.6	16.0	9.7	16.1
Graham	1	5.6	8.9	26.9	21.5	44.2
Graham	2	11.6	16.9	19.1	23.5	39.8
Lake Creek	1	—	0.2	3.9	8.5	27.2
Lake Creek	2	3.4	4.1	14.0	23.4	34.2
Lake Hubbard	1	3.7	11.6	12.0	13.4	23.2
Lake Hubbard	2	12.4	26.7	27.5	34.3	40.2
Morgan Creek (R)	2	—	—	—	0.8	11.6
Morgan Creek (R)	3	—	—	—	1.0	4.2
Morgan Creek (R)	4	—	—	1.0	6.1	20.7
Morgan Creek (M)	5	2.5	7.9	15.2	23.9	37.0
Morgan Creek (M)	6	1.0	14.1	18.8	44.2	59.9
Morgan Creek CT’s		1.9	0.9	1.0	1.6	4.1
North Lake (M)	1	5.5	14.8	23.0	22.1	22.0
North Lake (M)	2	5.8	10.9	20.2	24.7	30.0
North Lake (M)	3	10.6	15.0	19.1	19.0	35.0
North Main (R)	4	—	—	8.1	2.1	20.7
Parkdale (R)	1	—	1.6	8.2	6.7	18.5
Parkdale (R)	2	—	2.1	9.8	8.1	20.8
Parkdale (R)	3	—	2.7	11.4	11.0	24.0
Permian Basin	5	1.7	4.0	9.5	22.0	31.8
Permian Basin	6	19.1	38.1	45.2	50.0	55.0
Permian Basin CT’s		2.1	1.0	0.9	1.8	4.7
River Crest (R)	6	—	—	—	0.9	18.9
Stryker Creek	1	0.2	4.7	3.7	20.4	29.3
Stryker Creek	2	11.5	23.3	24.2	32.4	43.8
Tradinghouse	1	2.4	11.2	30.0	30.7	36.4
Tradinghouse	2	2.6	21.6	22.0	49.8	50.0
Valley (M)	1	0.4	9.2	12.5	21.4	32.3
Valley (M)	2	—	6.8	25.7	34.6	43.2
Valley (M)	3	—	2.8	5.8	10.7	17.8
Trinidad	6	2.2	6.9	10.4	19.8	18.8
Sweetwater	4	11.4	36.8	23.0	—	—
Sweetwater CT	1	12.4	18.2	23.8	—	—
Sweetwater CT	2	12.3	38.6	5.2	—	—
Sweetwater CT	3	10.8	43.9	37.1	—	—

(R) Retired during 2004.                         (M) Mothballed                        (RMR) Reliability Must Run for ERCOT

15

OPERATING STATISTICS – TXU POWER

Net Heat Rates – Texas

Btu/kWh

Plant	Unit	Low	High
Comanche Peak	1	10,200	10,500
Comanche Peak	2	9,500	10,500
Big Brown	1	10,587	11,517
Big Brown	2	10,587	11,517
Monticello	1	10,587	11,517
Monticello	2	10,587	11,517
Monticello	3	10,587	11,517
Martin Lake	1	10,587	11,517
Martin Lake	2	10,587	11,517
Martin Lake	3	10,587	11,517
Sandow	4	10,587	11,517
Collin	1	10,430	32,426
DeCordova	1	9,812	13,316
Decordova CT’s		9,250	9,800
Eagle Mountain	1	10,430	32,426
Eagle Mountain	2	10,430	32,426
Eagle Mountain	3	10,430	32,426
Graham	1	10,430	32,426
Graham	2	9,812	13,316
Lake Creek	1	10,430	32,426
Lake Creek	2	10,430	32,426
Lake Hubbard	1	10,430	32,426
Lake Hubbard	2	9,812	13,316
Morgan Creek (R)	2	10,430	32,426
Morgan Creek (R)	3	10,430	32,426
Morgan Creek (R)	4	10,430	32,426
Morgan Creek	5	10,430	32,426
Morgan Creek	6	9,812	13,316
Morgan Creek CT’s		9,250	9,800
North Lake	1	10,430	32,426
North Lake	2	10,430	32,426
North Lake	3	10,430	32,426
North Main (R)	4	10,430	32,426
Parkdale (R)	1	10,430	32,426
Parkdale (R)	2	10,430	32,426
Parkdale (R)	3	10,430	32,426
Permian Basin	5	10,430	32,426
Permian Basin	6	9,812	13,316
Permian Basin CT’s		9,250	9,800
River Crest (R)	6	10,430	32,426
Stryker Creek	1	10,430	32,426
Stryker Creek	2	9,812	13,316
Tradinghouse	1	9,812	13,316
Tradinghouse	2	9,812	13,316
Valley	1	10,430	32,426
Valley	2	9,812	13,316
Valley	3	10,430	32,426
Trinidad	6	10,430	32,426
Sweetwater	4	11,500	12,000
Sweetwater CT	1	11,500	12,000
Sweetwater CT	2	11,500	12,000
Sweetwater CT	3	11,500	12,000

(R) Retired during 2004.

16

OPERATING STATISTICS – TXU POWER

Fuel Mix and Average Cost – Texas

For the years ended December 31, 2000 – 2004; Mixed measures

Statistic	2004		2003		2002		2001		2000
Generation (MWh)
Nuclear	19,052,643		17,749,343		16,579,084		18,322,265		18,487,842
Lignite/Coal	44,116,439		43,240,756		39,817,056		39,506,193		40,993,945
Gas/Oil	4,673,910		13,098,982		18,733,486		24,371,090		32,102,173
Gas/Oil Divested	—		—		854,232		3,626,265		5,292,578
Total	67,842,992		74,089,081		75,983,858		85,825,813		96,876,538
Generation Mix (%)
Nuclear	28	%	24	%	22	%	21	%	19	%
Lignite/Coal	65	%	58	%	52	%	46	%	42	%
Gas/Oil	7	%	18	%	26	%	33	%	39	%
Total	100	%	100	%	100	%	100	%	100	%
Fuel Cost ($000)1
Nuclear	81,748		79,503		76,365		88,796		99,151
Lignite/Coal	548,650		517,470		482,811		543,498		464,558
Total Base Load	630,398		596,973		559,176		632,294		563,709
Average Fuel Cost ($/MWh)1
Nuclear	4.29		4.48		4.61		4.85		5.36
Lignite/Coal	12.43		11.97		12.13		13.76		11.33
Total Base Load	9.98		9.79		9.92		10.93		9.48

¹ Based on settled volumes, which exclude company use and sales to Alcoa. Includes depreciation and amortization of lignite mining plant and equipment and related asset retirement obligations which are reported as depreciation and amortization expense but are part of overall fuel costs.

17

OPERATING STATISTICS – TXU POWER

O&M/SG&A

For the years ended December 31, 2000 – 2004; $ thousands

Plant Type	2004	2003	2002	2001	2000
Nuclear	235,786	213,725	236,305	194,300	208,571
Lignite/Coal	208,805	218,272	195,458	163,925	146,978
Gas/Oil	92,070	111,283	105,904	120,016	125,123
Other	143,049	57,773	98,973	133,359	103,223
Total	679,710	601,053	636,640	611,600	583,895

Depreciation Rates

For the years ended December 31, 2000 – 2004, except as noted; %

Plant Type	2004	Apr-Dec 2003	Jan - Mar 2003	2002	2001	2000
Nuclear	1.70	1.83	2.51	2.51	2.51	2.51
Lignite/Coal	1.98	2.97	2.46	2.46	2.46	2.46
Gas/Oil	2.31	2.31	2.00	2.00	2.00	2.00

Net Heat Rate

For the years ended December 31, 2000 – 2004; Btu/kWh

Plant Type	2004	2003	2002	2001	2000
Nuclear	10,280	10,399	10,470	9,983	10,401
Lignite/Coal	11,237	11,220	11,192	11,216	11,119
Gas/Oil	12,040	11,201	10,998	10,698	10,715

Outage Management (Base Load)

For the years ended December 31, 2000 – 2004; TWh

Category	2004	2003	2002	2001	2000
Total
Planned	3.8	3.3	5.1	3.1	3.3
Unplanned	3.5	5.6	6.6	6.8	4.6
Total	7.3	8.9	11.7	9.9	7.9
Nuclear
Planned	1.1	0.7	2.2	0.8	1.0
Unplanned	0.1	1.1	0.6	0.4	0.0
Total	1.2	1.8	2.8	1.2	1.0
Lignite/Coal
Planned	2.7	2.6	2.9	2.3	2.3
Unplanned	3.4	4.5	6.0	6.4	4.6
Total	6.1	7.1	8.9	8.7	6.9

18

OPERATING STATISTICS – TXU ENERGY – WHOLESALE MARKETS

Wholesale Markets optimizes the value of the TXU Energy Holdings portfolio by balancing customer demand for energy with the supply of energy in an economically efficient and effective manner. This effort includes hedging and risk management as well as other value creation activities. Retail and wholesale demand has generally been greater than volumes that can be supplied by the base load (nuclear and lignite/coal-fired) production; however, the supply demand relationship will evolve over time as market fundamentals and the retail competitive landscape change. The wholesale markets operation acts to provide additional supply balancing through the gas/oil-fired generation assets or purchases of power. These operations manage the commodity volume and price risks inherent in TXU Energy Holdings’ generation and sales operations through supply structuring, pricing and hedging activities, including hedging both future power sales and purchases of fuel supplies for the generation plants. These operations are also responsible for the efficient dispatch of power from the generation plants.

Commodity Market Prices

For periods ended 2002 – 2004; Mixed measures

				Power Prices (MWD)1						Heat Rates
		NYMEX (GDD)2		5 X 16		5 X 8		7 X 24		5 X 16	5 X 8	7 X 24
2004	Q1	$	5.612	$	39.862	$	28.727	$	34.197	7.115	5.119	6.098
	Q2	$	6.085	$	48.496	$	34.037	$	41.134	7.963	5.559	6.760
	Q3	$	5.450	$	47.530	$	31.451	$	39.374	8.714	5.762	7.217
	Q4	$	6.254	$	48.907	$	31.592	$	40.124	7.802	5.003	6.382
	Total 2004	$	5.850	$	46.210	$	31.455	$	38.707	7.901	5.371	6.614
2003	Q1	$	5.878	$	52.796	$	37.348	$	45.781	8.982	6.354	7.789
	Q2	$	5.738	$	51.098	$	31.964	$	44.224	8.905	5.571	7.707
	Q3	$	4.897	$	42.873	$	28.794	$	36.913	8.755	5.880	7.538
	Q4	$	5.498	$	38.535	$	24.695	$	34.368	7.009	4.491	6.251
	Total 2003	$	5.503	$	46.326	$	30.700	$	40.322	8.413	5.574	7.321
2002	Q1	$	2.491	$	21.448	$	14.158	$	18.880	8.611	5.684	7.580
	Q2	$	3.405	$	29.885	$	15.145	$	24.499	8.777	4.448	7.195
	Q3	$	3.192	$	30.072	$	18.031	$	25.803	9.422	5.650	8.085
	Q4	$	4.325	$	34.796	$	22.449	$	30.308	8.046	5.191	7.008
	Total 2002	$	3.353	$	29.050	$	17.446	$	24.872	8.714	5.243	7.467

¹ Power Prices are the Megawatt Daily non zonal ERCOT day ahead cash prices in $/MWh.

² NYMEX gas price is the Gas Daily data for day ahead prices in the cash month in $/MMBtu.

19

OPERATING STATISTICS – TXU ENERGY

Selected Credit Statistics for Wholesale Sales¹

As of December 31, 2002 – 2004; $ millions, %

Statistic	2004			2003			2002
Gross Credit Exposure (Net of Collateral)	$	600		$	740		$	866
Investment Grade Credit Exposure (Net of Collateral)
Less than 2 years	$	317		$	424		$	624
2 - 5 years		86			119			22
Greater than 5 years		77			119			4
Total	$	480		$	662		$	650
Non Investment Grade Credit Exposure (Net of Collateral)
Less than 2 years	$	79		$	50		$	195
2 - 5 years		22			14			21
Greater than 5 years		19			14			0.3
Total	$	120		$	78		$	216
% Investment Grade (Net of Collateral)		80	%		89	%		75	%
% Non Investment Grade (Net of Collateral)		20	%		11	%		25	%
Total		100	%		100	%		100	%
Credit Exposure Maturities (Net of Collateral)
Less than 2 years		66	%		64	%		94	%
2 - 5 years		18	%		18	%		5	%
Greater than 5 years		16	%		18	%		1	%
Total		100	%		100	%		100	%

Selected Credit Statistics For Large Business Retail Sales¹

As of December 31, 2002 – 2004; $ millions, %

Statistic	2004			2003			2002
Gross Credit Exposure (Net of Collateral)	$	184		$	226		$	319
Investment Grade Credit Exposure
(Net of Collateral)
Less than 2 years	$	148		$	155		$	139
2 - 5 years		3			10			28
Greater than 5 years		0			0			0
Total	$	151		$	165		$	167
Non Investment Grade Exposure (Net of Collateral)
Less than 2 years	$	33		$	57		$	152
2 - 5 years		0			4			0
Greater than 5 years		0			0			0
Total	$	33		$	61		$	152
% Investment Grade		82	%		73	%		52	%
% Non Investment		18	%		27	%		48	%
Total		100	%		100	%		100	%
Credit Exposure Maturities (Net of Collateral)
Less than 2 years		98	%		94	%		91	%
2 - 5 years		2	%		6	%		9	%
Greater than 5 years		0	%		0	%		0	%
Total		100	%		100	%		100	%

¹ The tables shown above present the distribution of credit exposure for trade accounts receivable from large business customers, commodity contract assets and other derivative assets that arise primarily from hedging activities.

20

OPERATING STATISTICS – TXU ENERGY

Financial and Operating Data

For the years ended December 31, 2002 – 2004; Mixed measures

Statistic	2004			2003			2002
Electric Operating Revenues ($ millions)
Residential	$	3,462		$	3,311		$	3,108
Small Business		1,137			1,238			1,330
Large Business		1,771			1,935			2,085
Total	$	6,370		$	6,484		$	6,523
Electric Energy Sales (GWh)
Residential		33,986			35,981			37,692
Small Business		10,839			12,986			15,907
Large Business		25,466			30,955			36,982
Total		70,291			79,922			90,581
Number of Electric Customers (thousands of meters)
Native Market:
Residential		1,951			2,059			2,204
Small Business		309			316			328
Total Native Market		2,260			2,375			2,532
Other Markets:
Residential		194			148			98
Small Business		6			5			5
Total Other Markets		200			153			103
Large Business		76			69			78
Total Electric Customers		2,536			2,597			2,713
Net Customer Change
Native Market		(4.8	)%		(6.2	)%		(3.5	)%
Other Markets		30.7	%		48.5	%		1,473	%
Call Center Metrics
Answer Speed (seconds)		39			268			93
Abandoned Calls		4	%		26	%		11	%
Credit and Collection Metrics
Average Receivables ($ millions)
Less than 30 days		262.4			302.7			341.7
30-60 days		37.1			55.9			88.3
60-90 days		8.8			19.5			55.2
Greater than 90 days		8.2			24.7			78.4
Bad Debt Expense ($ millions)		94.6			120.5			118.4
Bad Debt as % of Total Revenues		1.49	%		1.84	%		1.80	%

21

OPERATING STATISTICS – TXU ENERGY

Price to Beat and Gas Component Information – Residential

Affiliate REP	Docket No.		Effective	Gas Price As Filed		Gas Price Increase		Months	Fuel Factor	Average Price1 (¢/kWh)
TXU	24040		01/01/2002	$	3.111	—		—	—	8.26
	25802		08/27/2002	$	3.619	16.3	%	All	2.8935	8.66
	27281		03/11/2003	$	4.910	35.7	%	All	3.9265	9.69
	28191		08/22/2003	$	5.362	9.2	%	All	4.2877	10.06
	29516		05/20/2004	$	5.785	7.9	%	All	4.6264	10.39
	29837		08/04/2004	$	6.517	12.7	%	All	5.2140	10.98
	31004		05/12/2005	$	7.872	20.8	%	All	6.2985	12.07
First Choice	24194		01/01/2002	$	3.111	—		—	—	8.66
	25885		08/27/2002	$	3.817	22.7	%	All	2.67396	9.15
	27167		02/04/2002	$	4.526	18.6	%	All	3.17085	9.65
	27390		03/27/2003	$	5.166	14.1	%	All	3.61921	10.10
	27511		04/22/2003	$	5.958	15.3	%	All	4.17403	10.65
	29800		07/07/2004	$	6.454	8.32	%	All	4.52131	11.00
	30375		12/21/2004	$	7.450	15.4	%	All	5.21895	11.70
	30999		05/12/2005	$	7.845	5.3	%	All	5.49555	11.98
Mutual Energy - CPL	24195		01/01/2002	$	3.111	—		—	—	8.88
	25873		08/27/2002	$	3.795	22.0	%	Mar-Jun Jul-Oct Nov-Feb	4.2908 3.9793 3.3763	9.52
	27376		03/25/2003	$	5.123	35.0	%	Mar-Jun Jul-Oct Nov-Feb	5.7926 5.3721 4.5580	10.93
	29293		03/16/2004	$	5.586	9.0	%	Mar-Jun Jul-Oct Nov-Feb	6.3139 5.8556 4.9682	11.42
	29845		08/10/2004	$	6.517	16.7	%	Mar-Jun Jul-Oct Nov-Feb	7.3683 6.8335 5.7979	12.41
	30966		05/03/2005	$	7.603	16.7	%	Mar-Jun Jul-Oct Nov-Feb	8.5988 7.9747 6.7661	13.56
Mutual Energy - WTU	24335		01/01/2002	$	3.111	—		—	—	8.90
	25874		08/27/2002	$	3.795	22.0	%	Dec-Feb Mar-May Jun-Aug Sep-Nov	3.9894 6.0140 4.9507 3.8627	9.71
	27377		03/25/2003	$	5.123	35.0	%	Dec-Feb Mar-May Jun-Aug Sep-Nov	5.3857 8.1189 6.6834 5.2146	11.34
	29292		03/16/2004	$	5.586	9.0	%	Dec-Feb Mar-May Jun-Aug Sep-Nov	5.8704 8.8496 7.2849 5.6839	11.91
	29845		08/10/2004	$	6.517	16.7	%	Dec-Feb Mar-May Jun-Aug Sep-Nov	6.8508 10.3275 8.5015 6.6331	13.46
Reliant	23950		01/01/2002	$	3.111	—		—	—	8.62
	25840		08/27/2002	$	3.729	19.9	%	All	3.0377	9.12
	26933		12/20/2002	$	4.017	7.7	%	All	3.2716	9.35
	27320		03/11/2003	$	4.956	23.4	%	All	4.0372	10.12
	27956		07/26/2003	$	6.100	23.1	%	All	4.9698	11.05
	30378		12/21/2004	$	7.500	23.0	%	All	6.1079	12.19
	30774	2	050/2/2005	$	7.500	N/A		All	6.1079	12.80

¹ Average price calculated based on 1000 KWh/month.

² Increase due to elimination of EMC credit and addition of transition charge reflected in an increased base rate.

22

OPERATING STATISTICS – TXU ENERGY

Native Market Price Comparison¹

Various dates; ¢/kWh

Retail Electric Provider	06/01/05	12/31/04	12/31/03	06/03/03	12/31/02
TXU – PTB	12.07	10.98	10.06	9.69	8.66
Reliant	11.58	10.21	9.05	8.73	8.23
Direct Energy	10.10	10.10	9.60	9.28	8.48
First Choice (TNMP)	10.80	10.80	10.75	10.75	8.20
Entergy Solutions	10.80	10.50	8.80	8.60	8.15
Green Mountain (Pollution Free)	10.99	10.99	10.66	10.30	9.00

¹ Rates calculated for residential customer using 12,000 KWh/year.

23

OPERATING STATISTICS – TXU ENERGY HOLDINGS SEGMENT

Financial and Operating Data

For the years ended December 31, 2002 – 2004; Mixed measures

Statistic	2004			2003			20021
Operating Statistics – Volumes
Retail Electricity (GWh)
Residential		33,986			35,981			37,692
Small Business2		10,839			12,986			15,907
Large Business and Other		25,466			30,955			36,982
Total Retail Electricity		70,291			79,922			90,581
Wholesale Electricity (GWh)		48,309			36,809			29,649
Production and Purchased Power (GWh)
Nuclear and Lignite/Coal (Base Load)		61,318			59,028			54,738
Gas/Oil and Purchased Power		60,733			63,165			70,118
Total Production and Purchased Power		122,051			122,193			124,856
Customer Counts
Retail Electricity Customers (end of period and in thousands – based on number of meters):
Residential		2,145			2,207			2,302
Small Business		315			321			333
Large Business and Other		76			69			78
Total Retail Electricity Customers		2,536			2,597			2,713
Operating Revenues ($ millions)
Retail Electricity Revenues
Residential	$	3,462		$	3,311		$	3,108
Business and Other		2,908			3,173			3,415
Total Retail Electricity Revenues		6,370			6,484			6,523
Wholesale Electricity Revenues		1,886			1,258			841
Hedging and Risk Management Activities		(103	)		30			147
Other Revenues		342			214			167
Total Operating Revenues	$	8,495		$	7,986		$	7,678
Weather (Average for Service Territory)
Percent of Normal:
Cooling Degree Days		89.9	%		95.7	%		99.8	%
Heating Degree Days		89.2	%		98.1	%		102.0	%

¹ Adjusted from previous report due to reclassification of discontinued operations.

² Customers with demand of less than 1MW annually

24

ERCOT/TEXAS MARKET/REGULATORY HIGHLIGHTS

Electric Reliability Council of Texas (ERCOT)

The Electric Reliability Council of Texas is the Independent System Operator and the regional reliability coordinator of the various electricity systems in Texas. ERCOT is one of ten regional reliability councils in North America. As one of the largest control areas in the United States, the organization serves seven million customers and oversees the operation of over 78,000 megawatts of generation and 38,000 miles of transmission lines in Texas. ERCOT serves approximately 85 percent of the state’s electric load and 75 percent of the geographic land area in Texas.

	2004
Market Peak Demand – Summer (MWs)	58,528
Total Installed Capacity (MWs)	75,056
Interconnection Capacity (MWs)	856
Reserve Margin	28	%
Number of Competitive Customers (millions)	5.13

	North Texas	South Texas
Usage Per Residential Customer (kWh)	1,326	1,402

ERCOT Summer 2004 Fuel Types

25

ERCOT/TEXAS MARKET/REGULATORY HIGHLIGHTS

Transmission Congestion Management in ERCOT

Transmission congestion is the additional cost associated with operating generation in a less than perfect economic manner due to the reality of a less than perfect transmission system. There are two sides to congestion costs: the cost of additional transmission versus the cost of less-than-optimal generation dispatch. The desired result is to minimize combined cost.

When the Texas competitive retail electricity market opened in 2002, the method of dealing with transmission congestion was referred to as “zonal”. ERCOT is divided into zones for transmission purposes, and currently uses “zonal” congestion management. Zonal congestion involves competitive solutions between different regions within the state. A competitive solution exists when multiple owners of generation can compete to resolve the congestion problem by making offers to increase or decrease their generation output. Costs for relieving congestion between transmission zones are charged to the companies that schedule load.

Local congestion occurs within the zones. Typically, there are not enough generation owners in the area to compete to resolve the congestion. Costs to resolve local congestion within zones are shared by all companies on a proportional basis. The congestion costs shared by all consumers within zones totaled $210 million in 2002, $409 million in 2003 and $282 million in 2004.

The challenge for ERCOT is to balance this cost against the cost of additional transmission investment to relieve this congestion. As indicated by the reduction of congestion costs from 2003 to 2004, transmission companies are actively addressing local congestion in a cost-effective manner by adding new transmission facilities in those locations identified by high local congestion costs.

The Texas market is now considering adoption of a “nodal market design” for transmission congestion management. This method differs from the zonal model primarily in the level of granularity used in dealing with generators. The nodal market makes no distinction between zonal and local congestion. As directed by the Public Utility Commission of Texas (PUC), a cost-benefit study designed to assess the potential nodal market design against the current zonal market design was filed with the PUC on December 21, 2004. The results of this study indicate that under the current assumptions regarding nodal market operation, changing to a nodal market in ERCOT should result in a net benefit of approximately $1 billion to ERCOT customers as a whole, although impacts will vary across the state. As with any estimate, its results should be considered as being within a range of possibilities, rather than the one definitive outcome. When comparing the 2003 actual operation of the zonal market to a 2003 optimal operation of the zonal market, TXU believes that as much as half of the $1 billion cost reduction indicated in the cost-benefit analysis has already been achieved by market participants through more disciplined commitment and dispatch versus from the market design change. Much of the recent mothballing of existing generating capacity has been further evidence of this. Additionally, a set of Protocols to implement this new nodal market design was filed with the PUC on March 18, 2005. It is expected that the PUC will make a decision regarding the Texas Nodal Market design by the third quarter of 2005.

ERCOT Congestion Zones

26

ERCOT/TEXAS MARKET/REGULATORY HIGHLIGHTS

Market Rules Overview

Rule	Definition	Impact to TXU
Price to Beat	TXU Energy may not charge rates to those customers that are different from the price to beat rates until the earlier of: (a)      January 1, 2005 or (b)      Until 40% of the electric power consumed by customers in those respective customer classes is supplied by competing REPs Thereafter, TXU Energy may offer rates different from the price-to-beat to customers in that class, but must also continue to make the price-to-beat rate available for residential and small business customers until January 1, 2007.	In December 2003, TXU Energy met the 40% requirement to be allowed to offer alternatives to the price-to-beat rate for small business customers in the native market.
PTB Fuel Factor Adjustment	Twice per year, affiliated REPs may request that the PUC adjust the fuel factor component of the price-to-beat rate based on changes in the market price of natural gas. Under amended rules, a request for a change in the fuel factor can be petitioned if natural gas futures move more than 5% (10% if the petition is filed after November 15 of any year) from the level used to set the existing price-to-beat fuel factor rate.	Subsequent to PUC approval, TXU Energy has exercised its right to increase the fuel factor components of its price-to-beat rates in August 2002, March and August 2003, May and August 2004, and May 2005.
Unregulated Pricing on ERCOT Wholesale Power Transactions	Power generation companies affiliated with electric delivery utilities may charge unregulated prices in connection with ERCOT wholesale power transactions.
Provider of Last Resort (POLR)	Under the POLR framework, the POLR provides electric service only to customers who request POLR service, whose selected REP goes out of business, or who are transferred to the POLR by other REPs for reasons other than non-payment.	TXU Energy did not bid to be the POLR, but was designated POLR through lottery for residential and small business customers in certain West Texas service areas and for small business customers in the Houston service area. TXU Energy’s obligation to serve as POLR in those areas ceased on December 31, 2004. However, the REPs selected by the Commission to assume the POLR obligation in those areas on January 1, 2005 initially objected to that selection. To ensure continuity of POLR service, TXU Energy voluntarily agreed to continue providing POLR service in those areas until March 31, 2005, at which time Energy’s POLR obligations ceased. Under the current rule, the Commission will use a competitive bid process in late 2006 to determine POLR providers for 2007 and 2008.

27

ERCOT/TEXAS MARKET/REGULATORY HIGHLIGHTS

Summary of Settlement Plan¹

Major Element	Description
Excess Mitigation Credit	Over the two year period ended December 21, 2003, TXU Electric Delivery implemented a stranded cost excess mitigation credit in the amount of $389 million, plus $26 million in interest, applied as a reduction to delivery rates charged to all REPs, including TXU Energy.
Regulatory Asset Securitization	TXU US Holdings received a financing order authorizing the issuance of securitization bonds up to $1.3 billion to recover regulatory asset stranded costs and other qualified costs. TXU Electric Delivery, through its bankruptcy remote financing subsidiary, issued an initial $500 million of securitization bonds in August 2003 and the remaining $790 million in June 2004. The principal and interest on the bonds is recoverable through a delivery fee surcharge to all REPs, including TXU Energy.
Retail Clawback Credit	A retail clawback credit related to residential customers was implemented in January 2004. The amount of the credit is equal to the number of residential customers retained by TXU Energy in the native market on January 1, 2004, less the number of new residential customers TXU Energy has added outside of the native market as of January 1, 2004 multiplied by $90. The estimated credit of $161 million will be applied to residential delivery rates charged by TXU Electric Delivery to all REPs, including TXU Energy over the period from 2004 through 2005.
Stranded Costs and Fuel Cost Recovery	TXU Energy’s stranded costs, not including regulatory assets, are fixed at zero. The Company will not seek to recover its unrecovered fuel costs which existed at December 31, 2001 nor pursue a final fuel cost reconciliation which would have covered the period from July 1998 until the beginning of competition in January 2002.

¹ For detailed information related to various regulatory proceedings in which TXU is or has recently been involved, please see our Annual Reports filed with the SEC on Form 10-K or our most recent Quarterly Reports filed with the SEC on Form 10-Q.

28

ERCOT/TEXAS MARKET/REGULATORY HIGHLIGHTS

Public Utility Commission of Texas

1701 N. Congress Avenue

P.O. Box 13326

Austin, Texas 78711-3326

(512) 936-7000

The PUC of Texas is responsible for:

• Ensuring that Texans have access to high-quality competitive alternatives for electric service

• Providing exemplary customer service in disseminating educational information, assisting customers to resolve disputes concerning electric service and ensuring compliance with relevant law and regulations

• Implementing the Public Utility Regulatory Act in a way that observes the letter and captures the spirit of the legislative directives

• Resolving contested matters efficiently, emphasizing collaboration and consensus

The Commission consists of three members appointed by the Governor and confirmed by the state senate for six-year staggered terms of office. A chairperson is designated by the Governor.

Commissioner	Term Expires	Background
Paul Hudson (Chair)	September 2009	Previously, Director of Policy for the Office of the Governor; a bachelor’s degree from University of Texas and a master’s degree from Arizona State University
Julie Parsley	September 2005	Previously, Solicitor General of Texas in the Office of the Attorney General; a graduate of Texas A&M with law degree from Texas Tech University School of Law
Barry T. Smitherman	September 2007	Previously, served as Harris County Assistant District Attorney; a graduate of Texas A&M with law degree from University of Texas School of Law and master’s degree from Harvard University

29

SCHEDULE OF LONG-TERM DEBT

As of December 31, 2004; $ millions

Issue	Year Due	Fixed/ Floating	2005	2006	2007	2008	2009 & Beyond		Total		Date of Next Redemption		Next Redemption Price
TXU Corp.
Senior Notes
Series C, 6.375% (a)	2008	Fixed				200			200		01/01/08		100.00
Series J, 6.375% (a)	2006	Fixed		683					683		(b)		T+20
Series K, 4.446%	2006	Fixed		50					50
Series L, 5.45% (c)	2007	Fixed			101				101
Series M, 5.80% (c)	2008	Fixed				184			184
Series O, 4.80% (a)	2009	Fixed					1,000		1,000		(b)		T+25
Series P, 5.55%	2014	Fixed					1,000		1,000		(b)		T+30
Series Q, 6.50% (a)	2024	Fixed					750		750		(b)		T+35
Series R, 6.55%	2034	Fixed					750		750		(b)		T+35
Conv Senior Notes, 3.57% (e)	2033	Floating					25		25		07/15/08		100.00
Other
Building Financing, 8.820%	2022	Fixed	9	9	9	9	84		120
Unamortized Prem and Disc							(11	)	(11	)
Total TXU Corp.			9	742	110	393	3,598		4,852
TXU Energy Company LLC
Pollution Control Revenue Bonds(PCRBs)
Brazos River Authority:
3.00% Series 1994A (f)	2029	Fixed					39		39		05/01/05	(g)	100.00
5.40% Series 1994B (f)	2029	Fixed					39		39		05/01/06	(g)	100.00
5.40% Series 1995A (f)	2030	Fixed					50		50		05/01/06	(g)	100.00
5.05% Series 1995B (f)	2030	Fixed					114		114		06/19/06	(g)	100.00
7.70% Series 1999A	2033	Fixed					111		111		04/01/13		101.00
6.75% Series 1999B (f)	2034	Fixed					16		16		04/01/13	(g)	100.00
7.70% Series 1999C	2032	Fixed					50		50		04/01/13		101.00
4.75% Series 2001B (f)	2029	Fixed					19		19		11/01/06	(g)	100.00
5.75% Series 2001C (f)	2036	Fixed					217		217		11/01/11	(g)	100.00
2.03% Series 2001D (h)	2033	Floating					268		268		(b)		100.00
2.45% Series 2001I (h)	2036	Floating					62		62		(b)		100.00
2.03% Series 2002A (h)	2037	Floating					45		45		(b)		100.00
6.75% Series 2003A (f)	2038	Fixed					44		44		04/01/13	(g)	100.00
6.30% Series 2003B	2032	Fixed					39		39		07/01/13		101.00
6.75% Series 2003C	2038	Fixed					52		52		10/01/13		101.00
5.40% Series 2003D (f)	2029	Fixed					31		31		10/01/14	(g)	100.00
Sabine River Authority:
6.45% Series 2000A	2021	Fixed					51		51		06/01/10		101.00
5.50% Series 2001A (f)	2022	Fixed					91		91		11/01/11	(g)	100.00
5.75% Series 2001B (f)	2030	Fixed					107		107		11/01/11	(g)	100.00
5.80% Series 2003A	2022	Fixed					12		12		07/01/13		101.00
6.15% Series 2003B	2022	Fixed					45		45		08/01/13		101.00
Trinity River Authority:
6.25% Series 2000A	2028	Fixed					14		14		05/01/13		101.00
5.00% Series 2001A (f)	2027	Fixed					37		37		11/01/06	(g)	100.00
Total PCRBs			—	—	—	—	1,553		1,553
Senior Notes
6.875% Senior Notes – Mining	2005	Fixed	30						30		(d)
6.125% Senior Notes (a)	2008	Fixed				250			250		(b)		T+37.5
7.00% Senior Notes	2013	Fixed					1,000		1,000		(b)		T+50
2.838% Senior Notes (e)	2006	Floating		400					400		(b)		100.00
Other
Capital Lease Obligations	Various						9		9
Fair Value Adjustments – int. rate swaps - various					15	15
Unamortized Prem and Disc
Total TXU Energy Company LLC			30	400	—	250	2,577		3,257
TXU Electric Delivery
First Mortgage Bonds
6.75% due 7/01/05	2005	Fixed	92						92		(d)		100.00
Senior Secured Notes
6.375%	2012	Fixed					700		700		(b)		T+25
7.00%	2032	Fixed					500		500		(b)		T+30

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SCHEDULE OF LONG-TERM DEBT (CONT.)

As of December 31, 2004; $ millions

Issue	Year Due	Fixed/ Floating	2005	2006	2007	2008	2009 & Beyond	Total	Date of Next Redemption	Next Redemption Price
TXU Electric Delivery
6.375% (a)	2015	Fixed					500	500	(b)	T+30
7.25%	2033	Fixed					350	350	(b)	T+35
Debentures
5.00% (a)	2007	Fixed			200			200	(b)	T+20
7.00%	2022	Fixed					800	800	(b)	T+30
Unamortized Prem and Disc							19	19
Sub-total			92	—	200	—	2,831	3,123
TXU Electric Delivery Transition Bond Company(i)
2.26% Series 2003	2007	Fixed			80			80	(j)	100.00
4.03% Series 2003	2010	Fixed					122	122	(j)	100.00
4.95% Series 2003	2013	Fixed					130	130	(j)	100.00
5.42% Series 2003	2015	Fixed					145	145	(j)	100.00
3.52% Series 2004	2009	Fixed					270	270	(d)
4.81% Series 2004	2012	Fixed					221	221	(d)
5.29% Series 2004	2016	Fixed					290	290	(d)
Sub-total			—	—	80	—	1,178	1,258
Total TXU Electric Delivery			92	—	280	—	4,009	4,381
TXU US Holdings
Senior Debentures
7.17%	2007	Fixed			10			10	(b)	T+10
Notes
9.58% semi-annual	2019	Fixed					68	68	(d)
8.254% quarterly	2021	Fixed					64	64	(d)
Junior Subord Debentures
2.494%, Series D (e)	2037	Floating					1	1	(b)	100.00
8.175%, Series E	2037	Fixed					8	8	02/01/07	104.09
Total TXU US Holdings			—	—	10	—	141	151
Total Long-Term Debt			131	1,142	400	643	10,325	12,641

(a) Interest rates swapped to floating on an aggregate $2.3 billion principal amount.

(b) Redeemable with prior notice.

(c) Equity-linked.

(d) No redemption prior to maturity.

(e) Interest rate in effect at 12/31/04

(f) These series are in the multiannual mode and are subject to mandatory tender prior to maturity on the mandatory remarketing date. On such date, the interest rate and interest rate period will be reset for the bonds.

(g) Redemption date represents mandatory remarketing date

(h) Interest rates in effect at 12/31/04. These series are in a weekly rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(i) Nonrecourse to TXU Electric Delivery. Due in biannual installments through due date.

(j) Not redeemable unless 5% or less of initial principal balance is outstanding and only after last scheduled payment date.

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SCHEDULE OF PREFERRED SECURITIES

As of December 31, 2004; $ millions

Issue	Year Due	Fixed/ Floating	Total	Redemption Price at 12/31/04
TXU Corp.
Preference Stock, 7.24%1	Perpetual	Fixed	300
Total TXU Corp.			300
TXU US Holdings
Preferred Stock
$4.00 Series – TPL	Perpetual	Fixed	3	102.00
$4.44 Series – TPL	Perpetual	Fixed	3	102.61
$4.56 Series – TPL	Perpetual	Fixed	5	112.00
$4.76 Series – TPL	Perpetual	Fixed	2	102.00
$4.84 Series – TPL	Perpetual	Fixed	2	101.79
$4.00 Series – TES	Perpetual	Fixed	7	102.00
$4.56 Series – TES	Perpetual	Fixed	2	112.00
$4.64 Series – TES	Perpetual	Fixed	3	103.25
$5.08 Series – TES	Perpetual	Fixed	3	102.00
$4.00 Series – DPL	Perpetual	Fixed	2	103.56
$4.24 Series – DPL	Perpetual	Fixed	2	103.50
$4.50 Series – DPL	Perpetual	Fixed	2	110.00
$4.80 Series – DPL	Perpetual	Fixed	2	102.79
Total TXU US Holdings			38
Total Preferred Securities			338

¹ Called for redemption effective 06/15/05.

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COMMON STOCK DATA¹

For years ended December 31, 2000 – 2004; $ per share unless otherwise noted

Measure	2004			2003			2002			2001			2000
Earnings Per Share from continuing operations (before extraordinary items and cumulative effect of changes in accounting principles):
Basic	$	0.27		$	1.76		$	0.37		$	2.05		$	2.12
Dilutive	$	0.27	2	$	1.63		$	0.37		$	2.05		$	2.12
Earnings Per Share:
Basic	$	(1.29	)	$	1.74		$	(15.23	)	$	2.52		$	3.43
Dilutive	$	(1.29	)	$	1.62		$	(15.23	)	$	2.52		$	3.43
Shares Outstanding (year end - millions)		240			324			322			265			258
Weighted Average Shares Outstanding (millions):
Basic		300			322			278			259			264
Dilutive		300			379			278			259			264
Dividends Paid ($ millions)	$	150		$	160		$	652		$	621		$	634
Dividends Paid	$	0.50		$	0.50		$	2.40		$	2.40		$	2.40
Dividend Payout Ratio (percent)		—			30.9	%		—			95.2	%		70.0	%
Book Value	$	1.26		$	17.34		$	14.80		$	28.88		$	28.97
Historical Stock Prices
Market Price:
High	$	67.00		$	23.96		$	57.05		$	50.00		$	45.25
Low	$	23.35		$	15.00		$	10.10		$	34.81		$	25.94
Close	$	64.56		$	23.72		$	18.68		$	47.15		$	44.31

CREDIT RATINGS³

As of April 2005

Company/Bonds	Moody’s	S&P	Fitch
TXU Corp.
Senior Unsecured	Ba1	BBB-	BBB-
Preference Stock	Ba2	BB+	BB+
TXU US Holdings
Senior Unsecured	Baa3	BBB-	BBB-
TXU Electric Delivery
Secured	Baa1	BBB	A-/BBB+
Senior Unsecured	Baa2	BBB-	BBB+
TXU Energy Company LLC
Senior Unsecured	Baa2	BBB	BBB

¹ Prior year periods have been reclassified to reflect certain operations as discontinued operations.

² Operational earnings (diluted) per share for 2004 were $2.82. Excluding special items, earnings (diluted) from continuing operations before extraordinary items, and changes in accounting principles were $2.89. For the diluted operational earnings calculation, weighted average shares were 321 million.

³ A rating reflects only the view of a rating agency, and is not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward at any time by a rating agency if such agency decides that circumstances warrant such a change.

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LIQUIDITY

As of April 29, 2005 and December 31, 2004; $ millions

Liquidity Component	Borrower	Maturity	4/29/05	12/31/04
Cash and Cash Equivalents			10	106
$1.4 billion credit facility	TXU Energy/TXU Electric Delivery Co.	June 08	966	1,172
$1.6 billion credit facility	TXU Energy/TXU Electric Delivery Co.	March 10	1,560	—
$500 million credit facility	TXU Energy/TXU Electric Delivery Co.	June 10	375	500
$500 million credit facility	TXU Energy	December 09	—	500
Terminated facilities				531
Total Available Liquidity			2,911	2,809

CAPITAL EXPENDITURES¹

For the years ended December 31, 2001 – 2004; $ millions

Segment	2004	2003	2002	2001
TXU Energy Holdings	281	163	284	327
TXU Electric Delivery	600	543	513	635
Corporate and Other	31	15	16	26
Total	912	721	813	988

¹ Prior year periods have been reclassified to reflect certain operations as discontinued operations.

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DEFINITIONS

OPERATIONAL PERFORMANCE MEASURES

Base Load – Generation category including both nuclear and lignite/coal-fired generation representing the most cost efficient generation in an area that is generally economical to run at all times.

CAIDI – Customer Average Interruptible Duration Index.

DART – Days Away, Restricted Duty or Transferred. The number of lost time and restricted duty injuries, plus the number of employee transfers due to injury, per 200,000 employee hours worked.

Fuel Factor – The initial Price to Beat fuel factors, set in 2001, were based on typical integrated utility fuel filings, adjusted for the 10-day rolling average price of the NYMEX 12-month strip for the last 5 trading days prior to, and first 5 trading days after September 11, 2001. Prior to revisions in the Price to Beat rule in April 2003, increases in the fuel factors were permitted only after a 4% increase in the 10-day rolling average price of the NYMEX 12-month strip. Currently, increases must reflect at least a 5% increase in the 20-day rolling average of the NYMEX 12-month strip

Heat Rate – A measure of generating station thermal efficiency, generally expressed in Btu per new kWh. It is computed by dividing the total Btu content of fuel burned for electric generation by the resulting net kWh generation.

IDR – An IDR meter is an interval data recorder. It records a customer’s electrical demand and consumption in 15 minute intervals (or 96 times a day).

Installed Capacity – The full-load continuous rating of a generator under specified conditions as designated by the manufacturer.

Large Business – The Large Business Market is comprised of customer having aggregate demands of one megawatt or greater (annual spend generally $250K or higher), Large business customers span commercial, industrial, government, and education sectors. Large Business customers typically sign contracts with 1 to 5 year terms that are transacted through a direct sales force and channel partners.

Native Market – An Affiliated Retail Electric Provider’s (AREP) native market is the geographic boundaries of the area and associated retail customers served by the former integrated utility from which an AREP was created.

Net Customer Change – Gross customer gains due to move ins and win-back plus the gross customer losses caused by switching, move-outs and disconnects.

Net Generation – The amount of electric energy produced by the generating units in a generating station, less the kilowatt-hours consumed for that station’s use.

NIDR – A non-IDR meter is a meter that records a customer’s electrical demand and consumption over a monthly period.

SAIDI– (System Average Interruptible Duration Index) – Defined as the number of minutes the average customer is out of service in a year. Determined by summing the customer-minutes off for each interruption during a specified time period and dividing the sum by the average number of customers served during the period.

SAIFI– (System Average Interruptible Frequency Index) – Defined as the number of times in a year that the average customer experiences an interruption (non-transient) to service. Determined by dividing the total number of customers interrupted in a time period by the average number of customers served.

FINANCIAL PERFORMANCE MEASURES

Available Capacity – Amount of undrawn capacity on corporate and subsidiary short-term borrowing facilities.

Book Value Per Share – Common equity divided by end of period shares outstanding.

Liquidity – Measures how easily assets can be turned into cash to pay bills, pay dividends to shareholders, and make future investments in the growth of the business.

Preferred Securities – Sum of preference stock, exchangeable preferred membership interests, and preferred stock of subsidiaries.

Operational Earnings Per Share - (a non-GAAP measure) – Income from continuing operations, less special items and preference stock dividends. TXU believes that operational earnings is a useful measure of underlying results because of the magnitude and scope of the performance improvement program and the significant effect of the special items on reported results. TXU relies on operational earnings for evaluation of performance and believes that analysis of the business by external users is enhanced by visibility to both reported GAAP earnings and operational earnings.

Total Debt – Sum of short-term and long-term debt and capital leases on the balance sheet less non-recourse debt.

Total Liquidity – Sum of cash and available credit facility capacity.

35

INVESTOR INFORMATION

The Board of Directors meets quarterly, generally on the third Friday of February, May, August and November. The Annual Shareholders Meeting is generally held on the 3^rd Friday in May of each year.

TXU’s quarterly earnings results, and other news and information of investor interest may be obtained by accessing the company’s website at www.txucorp.com.

For copies of TXU’s 10-K and 10-Q reports filed with the Securities & Exchange Commission or for other investor information, access the website at www.txucorp.com or write to:

TXU Corp.

Investor Relations

Energy Plaza

1601 Bryan Street

Dallas, Texas 75201

Securities analysts and representatives of financial institutions may contact Tim Hogan, Director of Investor Relations at 214-812-4641 or thogan@txu.com regarding TXU’s financial and operating performance.

COMMON STOCK INFORMATION

TXU Corp.’s common stock is listed on the New York, Chicago and Pacific stock exchanges under the symbol “TXU.” The TXU share price is reported daily in the financial press under “TXU” in most listings of New York Stock Exchange securities. TXU is a member of the following indices: S&P 500, S&P 500 Independent Power Producers and Electric Traders Index, Dow Jones Utilities Average, and the Philadelphia Utility Index, among others.

At year end 2004, there were 239,852,880 shares of TXU common stock outstanding. Shareholders of record totaled 58,585.

TXU COMMON STOCK PRICES

The high and low trading prices for each quarterly period in 2004 and 2003 were as follows (in dollars per share):

	2004				2003
Quarter	High		Low		High		Low
1	$	30.13	$	23.35	$	20.37	$	15.00
2	$	40.72	$	27.15	$	22.87	$	17.54
3	$	48.25	$	38.34	$	23.70	$	19.58
4	$	67.00	$	48.05	$	23.96	$	20.87

DIVIDEND PAYMENTS

Dividends paid during 2004 were taxable distributions. The Board of Directors declares dividends quarterly and sets the record and payment dates. Subject to Board discretion, those dates for 2005 are:

Declaration Date	Record Date	Payment Date
February 18, 2005	March 4, 2005	April 1, 2005
May 20, 2005	June 3, 2005	July 1, 2005
August 19, 2005	September 2, 2005	October 3, 2005
November 18, 2005	December 2, 2005	January 3, 2006

Dividend information will be updated according to the declaration schedule.

Quarterly dividend payments (in cents per share):

Quarter	2004	2003	2002	2001	2000
1	12.5	12.5	60.0	60.0	60.0
2	12.5	12.5	60.0	60.0	60.0
3	12.5	12.5	60.0	60.0	60.0
4	12.5	12.5	60.0	60.0	60.0

SHAREHOLDERS ACCOUNT INFORMATION

Effective June 1, 2005, Wachovia Bank, N. A. Shareholder Services Group is TXU’s transfer agent, registrar, dividend disbursing agent and direct stock purchase and dividend reinvestment plan administrator. Shareholders of record with questions about their account such as lost or stolen certificates, lost or missing dividend checks or notifications of change of address should contact Wachovia’s Shareholder Services Group at 1-866-876-2166, via email at equityservices@wachovia.com, or in writing at:

Wachovia Bank, N. A.

Shareholder Services Group

1525 West W. T. Harris Blvd., 3C3

Charlotte, NC 28262-8522

DIVIDEND REINVESTMENT/STOCK PURCHASE

TXU offers an automatic Dividend Reinvestment and Stock Purchase Plan administered by Wachovia Bank, N.A. Shareholder Services Group. The plan is designed to provide TXU shareholders and other investors with a convenient and economical method to purchase shares of the company’s common stock. The plan also accommodates payments of up to $250,000 per year for the purchase of TXU common shares. Contact Wachovia Bank, N.A. Shareholder Services Group by telephone (1-866-876-2166) or visit TXU’s website (www.txucorp.com) for information and an enrollment form.

www.txucorp.com

36