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Slide 1: 2004 Statistical Summary
Slide 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 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 THIS SUMMARY The consolidated financial data and statistics in this summary reflect the financial position and operating results of TXU through 2004. CONTENTS 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 Last Update: May 2005 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
Slide 3: TXU CORP. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME Year Ended December 31, 2004 2003 2002 (millions of dollars, except per share amounts) Operating revenues............................................................................................ Costs and expenses: Cost of energy sold and delivery fees .......................................................... Operating costs ............................................................................................. Depreciation and amortization ..................................................................... Selling, general and administrative expenses .............................................. Franchise and revenue-based taxes .............................................................. Other income ................................................................................................ Other deductions........................................................................................... Interest income ............................................................................................. Interest expense and related charges ............................................................ Total costs and expenses.......................................................................... Income from continuing operations before income taxes, extraordinary gain (loss) and cumulative effect of changes in accounting principles ....... Income tax expense ........................................................................................... Income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles ................................ Income (loss) from discontinued operations, net of tax effect ........................ Extraordinary gain (loss), net of tax effect ...................................................... Cumulative effect of changes in accounting principles, net of tax effect ........ Net income (loss) .............................................................................................. Exchangeable preferred membership interest buyback premium ................... Preference stock dividends ............................................................................... Net income (loss) available for common stock ................................................ Average shares of common stock outstanding (millions): Basic ............................................................................................................. Diluted .......................................................................................................... Per share of common stock─ Basic: Income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles ........................... Exchangeable preferred membership interest buyback premium................ Preference stock dividends........................................................................... Net income (loss) from continuing operations available for common stock Income (loss) from discontinued operations, net of tax effect .................... Extraordinary gain (loss), net of tax effect................................................... Cumulative effect of changes in accounting principles, net of tax effect ... Net income (loss) available for common stock ........................................... Per share of common stock─ Diluted: Income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles ........................... Exchangeable preferred membership interest buyback premium................ Preference stock dividends........................................................................... Net income (loss) from continuing operations available for common stock Income (loss) from discontinued operations, net of tax effect .................... Extraordinary gain (loss), net of tax effect................................................... Cumulative effect of changes in accounting principles, net of tax effect ... Net income (loss) available for common stock ........................................... Dividends declared............................................................................................ $9,308 3,847 1,429 760 1,091 367 (148) 1,172 (28) 695 9,185 123 42 81 378 16 10 485 849 22 $ (386) 300 300 $ $ 8,600 3,640 1,389 724 907 390 (58) 42 (36) 784 7,782 818 252 566 74 ─ (58) 582 ─ 22 560 322 379 $ 8,094 3,199 1,354 733 1,046 428 (41) 533 (33) 693 7,912 182 77 105 (4,181) (134) ─ (4,210) ─ 22 $(4,232) 278 278 $ 0.27 (2.83) (0.07) (2.63) 1.26 0.05 0.03 $ (1.29) $ 1.76 ─ (0.07) 1.69 0.23 ─ (0.18) $ 1.74 $ 0.37 ─ (0.08) 0.29 (15.04) (0.48) ─ $ (15.23) $ 0.27 (2.83) (0.07) (2.63) 1.26 0.05 0.03 $ (1.29) $ 0.938 $ 1.63 ─ (0.06) 1.57 0.20 ─ (0.15) $ 1.62 $ 0.50 $ 0.37 ─ (0.08) 0.29 (15.04) (0.48) ─ $ (15.23) $ 1.925 2
Slide 4: 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 Net income (loss) to common Discontinued operations Extraordinary gain Cum. effect of changes in accounting principles Premium on EPMIs Preference stock dividends Income (loss) from continuing operations Preference stock dividends Effect of diluted shares calculation Special items Operational earnings 04 (1.29) (1.26) (0.05) (0.03) 2.83 0.07 0.27 (0.07) 0.04 2.58 2.82 03 1.62 (0.20) 0.15 0.06 1.63 (0.06) 0.01 1.58 Description of Special Items For the year ended December 31, 2004; $millions and $ per share after tax Special Item Energy segment: Software projects write-off Severance and related expenses Inventory/gas plant write-downs Lease termination expense Power contract settlement expense Disposition of property Other charges Electric Delivery segment: Rate case settlement reserve Severance/other expenses Corporate and Other: One-time compensation expense Transaction professional fees Litigation settlement expense Liability management expense Severance charges and other Income tax benefit Total Main Earnings Category Other deductions Other deductions Other deductions Other deductions Other deductions Other income Other deductions Other deductions Other deductions SG&A SG&A Other deductions Other deductions income/deductions Other deductions Income tax expense Amount 69 72 55 117 66 (50) 10 14 19 51 35 56 384 5 (75) 828 Per Share 0.22 0.22 0.17 0.37 0.20 (0.15) 0.03 0.04 0.06 0.16 0.11 0.17 1.20 0.02 (0.24) 2.58 Cash 45 15 112 (12) 10 11 51 35 382 5 654 Non-Cash2 69 27 55 102 (46) (38) 14 8 56 2 (75) 174 1 2 Operational earnings is a non-GAAP measure that adjusts net income for special items. See Definitions for a detailed definition of operational earnings. 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
Slide 5: TXU CORP. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS 2004 Year Ended December 31, 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...................................................................... 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...................................................................................... Deferred income taxes and investment tax credits — net............................................ Losses on early extinguishment of debt ....................................................................... Asset writedowns and lease-related charges ................................................................ Net gain from sales of assets ........................................................................................ Net effect of unrealized mark-to-market valuations of commodity contracts ............. Litigation settlement charge ......................................................................................... Bad debt expense .......................................................................................................... Stock-based compensation expense ............................................................................. Net equity (income) loss from unconsolidated affiliates and joint ventures ............... Change in regulatory-related liabilities ........................................................................ Changes in operating assets and liabilities: Accounts receivable - trade.................................................................................... Impact of accounts receivable sales program ........................................................ Inventories.............................................................................................................. Accounts payable - trade........................................................................................ Commodity contract assets and liabilities ............................................................. Margin deposits - net ............................................................................................. Other – net assets ................................................................................................... Other – net liabilities.............................................................................................. Cash provided by operating activities............................................................... Cash flows — financing activities Issuances of securities: Long-term debt............................................................................................................. Common stock ............................................................................................................. Retirements/repurchases of securities: Long-term debt held by subsidiary trusts .................................................................... Equity-linked debt securities........................................................................................ Other long-term debt .................................................................................................... Exchangeable preferred membership interests ............................................................ Preferred securities of subsidiaries .............................................................................. Common stock ............................................................................................................. Change in notes payable: Commercial paper......................................................................................................... Banks ........................................................................................................................... Cash dividends paid: Common stock .............................................................................................................. Preference stock............................................................................................................ Premium paid for redemption of exchangeable preferred membership interests............. Redemption deposits applied to debt retirements ............................................................. Debt premium, discount, financing and reacquisition expenses Cash provided by (used in) financing activities................................................ $ 81 $ 566 $ 105 826 (11) 416 376 (135) 109 84 90 56 (1) (70) (246) (73) 15 185 (5) 34 (133) 160 1,758 791 (40) ─ ─ (45) 100 ─ 119 25 17 (144) 173 100 (46) (24) 24 25 290 482 2,413 804 21 40 237 (30) 113 ─ 160 1 255 34 (632) (15) (48) 108 (45) ─ (97) 41 1,052 5,090 112 (546) (1,105) (3,088) (750) (75) (4,687) ─ 210 (150) (22) (1,102) ─ (406) (6,519) 2,846 23 ─ ─ (2,187) ─ (98) ─ ─ (2,305) (160) (22) ─ 210 (38) (1,731) 4,446 1,274 ─ ─ (3,407) ─ ─ ─ (854) 1,490 (652) (22) ─ (210) (283) 1,782 4
Slide 6: TXU CORP. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.) Year Ended December 31, 2003 2002 (millions of dollars) 2004 Cash flows — investing activities Capital expenditures.......................................................................................................... Dispositions of businesses................................................................................................. Acquisition of telecommunications partner’s interest ...................................................... Proceeds from sales of assets ............................................................................................ Change in collateral trust .................................................................................................. Nuclear fuel ....................................................................................................................... Other, including transaction costs..................................................................................... Cash provided by (used in) investing activities ................................................ Discontinued operations Cash provided by (used in) operating activities................................................................ Cash provided by (used in) financing activities................................................................ Cash used in investing activities ....................................................................................... Effect of exchange rate changes........................................................................................ Cash provided by (used in) discontinued operations........................................ Net change in cash and cash equivalents.............................................................................. Cash and cash equivalents ─ beginning balance ................................................................. Cash and cash equivalents ─ ending balance ...................................................................... $ (912) 4,814 ─ 27 525 (87) (87) 4,280 (79) (10) (153) ─ (242) (723) 829 106 $ (721) 14 (150) 10 (525) (44) 16 (1,400) 338 97 (409) 8 34 (684) 1,513 829 (813) ─ ─ 447 ─ (51) (186) (603) 203 (966) (210) 60 (913) 1,318 195 $ 1,513 5
Slide 7: TXU CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31, 2004 2003 (millions of dollars) ASSETS Current assets: Cash and cash equivalents.................................................................................................................... Restricted cash ..................................................................................................................................... Accounts receivable — trade ............................................................................................................... Income taxes receivable ....................................................................................................................... Inventories ........................................................................................................................................... Commodity contract assets .................................................................................................................. Accumulated deferred income taxes.................................................................................................... Assets of telecommunications holding company ................................................................................ Other current assets .............................................................................................................................. Total current assets....................................................................................................................... Investments: Restricted cash ..................................................................................................................................... Other investments................................................................................................................................. Property, plant and equipment — net ........................................................................................................ Goodwill..................................................................................................................................................... Regulatory assets — net............................................................................................................................ Commodity contract assets ........................................................................................................................ Cash flow hedge and other derivative assets ............................................................................................ Other noncurrent assets .............................................................................................................................. Assets held for sale .................................................................................................................................... Total assets ................................................................................................................................... $ 106 49 1,274 25 320 546 224 ─ 249 2,793 47 664 16,676 542 1,891 315 6 283 24 $ 23,241 $ 829 12 1,016 ─ 419 548 94 110 196 3,224 582 632 16,803 558 1,872 109 88 214 7,202 $31,284 LIABILITIES, PREFERRED SECURITIES OF SUBSIDIARIES AND SHAREHOLDERS’ EQUITY Current liabilities: Notes payable - banks .......................................................................................................................... Long-term debt due currently .............................................................................................................. Accounts payable — trade ................................................................................................................... Commodity contract liabilities............................................................................................................. Litigation and other settlement accruals .............................................................................................. Liabilities of telecommunications holding company........................................................................... Other current liabilities ........................................................................................................................ Total current liabilities ................................................................................................................. Accumulated deferred income taxes.......................................................................................................... Investment tax credits ................................................................................................................................ Commodity contract liabilities................................................................................................................... Cash flow hedge and other derivative liabilities ....................................................................................... Long-term debt held by subsidiary trusts ................................................................................................. All other long-term debt, less amounts due currently................................................................................ Other noncurrent liabilities and deferred credits ...................................................................................... Liabilities held for sale .............................................................................................................................. Total liabilities.............................................................................................................................. Preferred securities of subsidiaries ............................................................................................................ Contingencies Shareholders’ equity .................................................................................................................................. Total liabilities, preferred securities of subsidiaries and shareholders’ equity ........................... $ 210 229 950 491 391 ─ 1,445 3,716 2,721 405 347 195 ─ 12,412 2,762 6 22,564 38 $ ─ 678 790 502 ─ 603 1,322 3,895 3,599 430 47 240 546 10,608 2,289 2,952 24,606 759 639 $ 23,241 5,919 $31,284 6
Slide 8: 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. Tra nsm ission Lines S ervice Are a 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 Transformer Capacity (MVA) Circuit Miles of Line Count of Load Serving Substations Distribution Feeders Electric Delivery Owned Poles 2 Third Party Poles3 2004 49,462 99,638 785 2,943 1,898,312 295,468 2003 47,991 98,286 780 2,914 1,886,284 297,188 2002 46,722 96,847 776 2,884 1,877,954 296,218 2001 45,503 95,793 774 2,867 1,893,714 270,649 2000 43,949 94,644 772 2,831 1,885,040 270,620 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 2 3 TXU Electric Delivery operated under the name ‘Oncor Electric Delivery’ during 2003 and 2002. Approximately 30,000 poles sold during the 2000 to 2002 timeframe. Count of third party poles contacted. 7
Slide 9: OPERATING STATISTICS – ELECTRIC DELIVERY Transmission Facts As of December 31, 2000 – 2004; Mixed measures Item Transformer Capacity (MVA) Circuit Miles of Line Count of Substations, Switching Stations and Plant Switchyards Transmission Circuit Breakers Interconnection to Generation Facilities Interconnection to Other Transmission Providers 2004 75,533 14,191 950 5,825 40 248 2003 70,890 14,180 950 5,749 43 241 2002 68,385 14,137 946 5,633 41 200 2001 68,089 14,010 941 5,569 38 217 2000 66,893 13,815 935 5,466 34 211 Key Operational Metrics For years ended December 31, 2000 – 2004; Mixed measures Metric 2004 2003 Non-Storm SAIDI (minutes)1 75.54 74.15 Non-Storm SAIFI (frequency)1 1.10 1.17 Non-Storm CAIDI (minutes)1 68.67 63.30 Meter Reading Accuracy 99.91% 99.89% DART Incident Rate 1.96 1.73 Regulatory Complaints2 484 367 Selected Financial Metrics For years ended December 31, 2000 – 2004; $ millions, % Metric 2004 Total Operating Revenues 2,226 Total Operating Expenses 1,697 Net Income Before Extraordinary Items 255 Property, Plant & Equipment – Net 6,609 Capital Expenditures 600 Capitalization Ratios Long-term debt, less amounts due currently 61.0% Shareholder Equity 39.0% Capitalization Ratios (without transition bonds)4 Long-term debt, less amounts due currently 53.2% Shareholder Equity 46.8% 2002 90.36 1.39 64.81 99.92% 1.87 394 2001 81.77 1.23 66.48 99.91% 2.35 852 2000 87.46 1.37 63.84 99.90% 2.30 297 2003 2,087 1,565 258 6,333 543 58.2% 41.8% 55.1% 44.9% 2002 1,994 1,517 245 6,056 513 60.6% 39.4% 60.6% 39.4% 20013 2,314 1,820 228 5,802 635 54.9% 45.1% 54.9% 45.1% 20003 2,081 1,597 226 5,445 517 52.1% 47.9% 52.1% 47.9% 1 2 3 4 Based on all outages greater than one minute in duration. 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. 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. 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
Slide 10: 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 Scheduling of Switches Scheduling of Move-ins On Schedule Completion of Switches On Schedule Completion of Move-ins Providing Historical Usage Loading of IDR Metering Data Loading of NIDR Metering Data ERCOT Report Market Average 99.7% Unavailable 86.6% 85.9% 98.0% 99.7% 99.7% TXU 99.8% 99.97% 98.3% 91.6% 97.0% 99.8% 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 utilities 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 2 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. Investor Owned Utilities (IOU’s) and other entities participating in customer choice. 9
Slide 11: 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 Customer Charge Metering Charge Merger Savings/Rate Reduction Charge Subtotal, Fixed Charges Distribution System Charge Transmission System Charge Transmission Cost Recovery Factor Subtotal, Basic Wires Charges System Benefit Fund Nuclear Decommissioning Charge Transition Charge Excess Mitigation Credit Merger Savings/Rate Reduction Riders Customer Charge and Wires Charge (no non-by passable charges) for 1,000 kWh Customer Charge and Wires Charge (no non-by passable charges) for 1,300 kWh Total Wires Charge for 1,000 kWh Total Wires Charge for 1,300 kWh TXU $ 2.74/cust/month $ 2.21/cust/month $ 0.00/cust/month $ 4.95/cust/month $ 0.014070/kWh $ 0.004493/kWh $ 0.000899/kWh $ 0.019462/kWh $ 0.000655/kWh $ 0.000169/kWh $ 0.000712/kWh Expired 12/31/03 n/a $ 24.41 $30.25 $ 25.95 $ 32.25 CenterPoint $ 2.39/cust/month $ 1.91/cust/month $ 0.00/cust/month $ 4.30/cust/month $ 0.018870/kWh $ 0.004310/kWh $ 0.000752/kWh $ 0.023932/kWh $ 0.000655/kWh Included in base chges $ 0.000939/kWh ($0.004873)/kWh n/a $ 28.23 $ 35.41 $ 24.95 $ 31.15 AEP Central $ 2.58/cust/month $ 2.38/cust/month ($ 0.28)/cust/month $ 4.68/cust/month $ 0.015628/kWh $ 0.003712/kWh $ 0.000705/kWh $ 0.020045/kWh $ 0.000662/kWh n/a $ 0.004241/kWh ($ 0.000822)/kWh ($ 0.001095)/kWh $ 24.73 $ 30.74 $ 27.71 $ 34.62 AEP North $ 4.58/cust/month $ 4.78/cust/month ($ 0.48)/cust/month $ 8.88/cust/month $ 0.019863/kWh $ 0.004638/kWh $ 0.000972/kWh $ 0.025473/kWh $ 0.000660/kWh n/a n/a n/a ($ 0.001248/)kWh $ 34.35 $ 41.99 $ 33.77 $ 41.23 TNMP $ 0.33/cust/month $ 3.58/cust/month $ 0.00/cust/month $ 3.91/cust/month $ 0.017291/kWh $ 0.004150/kWh $ 0.000866kWh $ 0.022307/kWh $ 0.000654/kWh n/a n/a n/a n/a $ 26.22 $ 32.91 $ 26.87 $ 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
Slide 12: 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 Number of Generating Units 2004 Installed Capacity (MWs) Annual Generation (3 year average MWhs) Nuclear 2 2,300 17,793,690 Lignite/Coal 9 5,837 42,391,417 Gas/Oil 45 10,228 12,168,793 Total 56 18,365 72,353,900 Generating Plant Locations – Texas As of 12/31/04 11
Slide 13: OPERATING STATISTICS – TXU POWER Unit Statistics and Information – Texas As of 12/31/04; MW Plant Comanche Peak Comanche Peak Subtotal Big Brown Big Brown Monticello Monticello Monticello Martin Lake Martin Lake Martin Lake Sandow Subtotal Collin (M) DeCordova DeCordova 4 CT's2 Eagle Mountain (M) Eagle Mountain (M) Eagle Mountain (RMR) Graham Graham Lake Creek Lake Creek Lake Hubbard Lake Hubbard Morgan Creek (M) Morgan Creek (M) Morgan Creek 6 CT's2 North Lake (M) North Lake (M) North Lake (M) Permian Basin Permian Basin Permian Basin 5 CT's2 Stryker Creek Stryker Creek Tradinghouse Tradinghouse Valley (M) Valley (M) Valley (M) Trinidad Sweetwater Sweetwater 3 CTs2 Diesels3 Subtotal Total (M) – Mothballed Unit 1 2 1 2 1 2 3 1 2 3 4 1 1 1 2 3 1 2 1 2 1 2 5 6 1 2 3 5 6 1 2 1 2 1 2 3 6 4 Fuel type Nuclear Nuclear Lignite/Coal Lignite/Coal Lignite/Coal Lignite/Coal Lignite/Coal Lignite/Coal Lignite/Coal Lignite/Coal Lignite/Coal Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Gas/Oil Type Base load Base load Base load Base load Base load Base load Base load Base load Base load Base load Base load Gas - Cycling Gas - Intermediate Gas - Peaking Gas - Cycling Gas - Cycling Gas - Cycling Gas - Cycling Gas - Intermediate Gas - Cycling Gas - Cycling Gas - Cycling Gas - Intermediate Gas - Cycling Gas - Intermediate Gas - Peaking Gas - Cycling Gas - Cycling Gas - Cycling Gas - Cycling Gas - Intermediate Gas - Peaking Gas - Cycling Gas - Intermediate Gas - Intermediate Gas - Intermediate Gas - Cycling Gas - Intermediate Gas - Cycling Gas - Cycling Gas - Cycling Gas - Peaking Year in Service1 1990 1993 1971 1972 1974 1975 1978 1977 1978 1979 1981 1955 1975 1990 1954 1956 1971 1960 1969 1953 1959 1970 1973 1959 1966 1988 1959 1961 1964 1959 1973 1990 1958 1965 1970 1972 1962 1967 1971 1965 1989 1989 County Somervell Somervell Freestone Freestone Titus Titus Titus Rusk Rusk Rusk Milam Collin Hood Hood Tarrant Tarrant Tarrant Young Young McLennan McLennan Dallas Dallas Mitchell Mitchell Mitchell Dallas Dallas Dallas Ward Ward Ward Cherokee Cherokee McLennan McLennan Fannin Fannin Fannin Henderson Nolan Nolan Installed Capacity 1,150 1,150 2,300 575 575 565 565 750 750 750 750 557 5,837 153 818 260 115 175 375 240 390 87 230 393 528 175 511 390 175 175 365 115 540 325 175 500 565 818 175 550 390 240 85 175 20 10,228 18,365 (RMR) – Reliability Must Run for ERCOT 1 2 3 Average useful lives: nuclear (60 years), lignite (50 years), gas (51 years), and gas CT’s (27 years) CT – Combustion Turbine; DeCordova and Permian Basin CT capacity is under a purchase power agreement. Diesels are located at Lake Creek (3), Stryker Creek (5) and Trinidad (2). 12
Slide 14: OPERATING STATISTICS – TXU POWER Nuclear Plant Statistics Item Commercial Operation Date License Expiration Date Architect/Engineer Reactor Manufacturer Reactor Type Turbine Generator Manufacturer Maximum Dependable Capacity (MW) Refueling Data Last Date # of Days Next Scheduled Refueling CPSES Unit 1 August 1990 February 2030 Gibbs & Hill Westinghouse PWR Siemens 1,150 March 27, 2004 38 Fall 2005 CPSES Unit 2 August 1993 February 2033 Gibbs & Hill Westinghouse PWR Siemens 1,150 March 26, 2005 32 Fall 2006 13
Slide 15: OPERATING STATISTICS – TXU POWER Net Generation – Texas For years ended December 31, 2000 – 2004; MWh Plant Comanche Peak Comanche Peak Subtotal Big Brown Big Brown Monticello Monticello Monticello Martin Lake Martin Lake Martin Lake Sandow Subtotal Collin (M) DeCordova DeCordova CT's Eagle Mountain (M) Eagle Mountain(M) Eagle Mountain (RMR) Graham Graham Lake Creek Lake Creek Lake Hubbard Lake Hubbard Morgan Creek (R) Morgan Creek (R) Morgan Creek (R) Morgan Creek (M) Morgan Creek (M) Morgan Creek CT's North Lake(M) North Lake (M) North Lake (M) North Main (R) Parkdale (R) Parkdale (R) Parkdale (R) Permian Basin Permian Basin Permian Basin CT's River Crest (R) Stryker Creek Stryker Creek Tradinghouse Tradinghouse Valley (M) Valley (M) Valley (M) Trinidad Sweetwater Sweetwater CT Sweetwater CT Sweetwater CT Subtotal Total Unit 1 2 1 2 1 2 3 1 2 3 4 1 1 1 2 3 1 2 1 2 1 2 2 3 4 5 6 1 2 3 4 1 2 3 5 6 6 1 2 1 2 1 2 3 6 4 1 2 3 2004 9,013,792 10,038,851 19,052,643 3,837,349 4,464,491 4,305,393 4,465,894 5,277,059 5,958,153 5,339,493 5,941,004 4,527,603 44,116,439 (1,217) 206,385 97,164 20,071 23,719 208,557 117,645 396,060 (2,223) 69,041 129,333 576,784 (347) (177) (418) 39,166 42,720 80,773 83,889 89,555 340,276 (181) (285) (169) (195) 17,241 904,003 72,416 (140) 3,820 506,676 121,069 186,958 5,851 (989) 823 45,330 76,293 44,560 92,595 81,478 4,673,910 67,842,992 2003 9,625,953 8,123,390 17,749,343 4,587,394 3,875,181 4,134,558 3,704,847 5,666,922 4,847,711 5,781,564 5,855,120 4,787,459 43,240,756 98,879 1,414,916 54,144 57,865 79,830 479,676 186,907 575,707 1,858 83,025 400,926 1,235,607 (1,561) (626) (1,569) 121,329 629,540 38,492 226,630 167,805 479,022 (832) 12,203 21,096 30,029 40,019 1,802,737 35,266 (833) 72,005 1,019,363 552,739 1,548,337 141,253 325,731 95,422 144,262 244,802 65,316 290,888 330,777 13,098,982 74,089,081 2002 7,785,265 8,793,819 16,579,084 4,362,128 3,558,722 3,711,998 4,030,192 5,385,687 5,148,997 5,079,555 4,596,454 3,943,323 39,817,056 74,572 2,974,511 68,125 101,874 193,175 526,756 564,898 651,729 29,460 281,967 414,224 1,270,631 (1,478) (719) 6,343 232,540 842,029 43,183 352,048 309,276 610,546 56,863 62,470 99,219 124,749 95,770 2,136,339 31,412 (584) 56,704 1,058,502 1,483,468 1,578,856 192,241 1,236,428 199,461 218,517 153,002 85,440 39,504 279,435 18,733,486 75,129,626 2001 8,444,318 9,877,947 18,322,265 3,733,166 3,539,669 3,646,758 4,024,631 4,904,882 5,104,000 4,812,971 5,305,204 4,434,912 39,506,193 191,886 3,338,979 102,052 74,725 197,646 317,572 452,737 803,227 64,960 472,369 462,944 1,584,785 1,492 3,812 37,413 365,920 1,979,522 68,387 339,274 378,195 608,939 14,775 50,900 81,301 120,699 221,266 2,367,173 62,367 8,348 312,232 1,417,285 1,520,938 3,568,742 327,436 1,668,866 366,490 415,436 – – – – 24,371,090 82,199,548 2000 9,619,797 8,868,045 18,487,842 4,230,742 4,314,241 4,143,518 3,478,659 4,748,085 5,596,189 5,433,020 5,492,880 3,556,611 40,993,945 297,464 3,911,118 181,854 148,244 256,133 531,411 931,078 1,362,246 208,005 691,554 802,460 1,863,522 22,510 16,203 127,195 568,993 2,687,161 174,584 337,409 461,831 1,120,695 145,506 141,342 209,655 263,059 321,259 2,607,556 165,561 183,042 449,959 1,921,490 1,806,095 3,595,258 496,770 2,086,165 610,776 397,010 – – – – 32,102,173 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
Slide 16: OPERATING STATISTICS – TXU POWER Unit Capacity Factors – Texas For years ended December 31, 2000 – 2004; % Plant Comanche Peak Comanche Peak Big Brown Big Brown Monticello Monticello Monticello Martin Lake Martin Lake Martin Lake Sandow Collin (M) DeCordova Decordova CT's Eagle Mountain (M) Eagle Mountain (M) Eagle Mountain (RMR) Graham Graham Lake Creek Lake Creek Lake Hubbard Lake Hubbard Morgan Creek (R) Morgan Creek (R) Morgan Creek (R) Morgan Creek (M) Morgan Creek (M) Morgan Creek CT's North Lake (M) North Lake (M) North Lake (M) North Main (R) Parkdale (R) Parkdale (R) Parkdale (R) Permian Basin Permian Basin Permian Basin CT's River Crest (R) Stryker Creek Stryker Creek Tradinghouse Tradinghouse Valley (M) Valley (M) Valley (M) Trinidad Sweetwater Sweetwater CT Sweetwater CT Sweetwater CT (R) Retired during 2004. Unit 1 2 1 2 1 2 3 1 2 3 4 1 1 1 2 3 1 2 1 2 1 2 2 3 4 5 6 1 2 3 4 1 2 3 5 6 6 1 2 1 2 1 2 3 6 4 1 2 3 (M) Mothballed 2004 89.2 99.4 76.0 88.4 86.8 90.0 80.1 90.4 81.0 90.2 94.6 2.9 3.5 2.0 1.5 6.3 5.6 11.6 3.4 3.7 12.4 2.5 1.0 1.9 5.5 5.8 10.6 1.7 19.1 2.1 0.2 11.5 2.4 2.6 0.4 2.2 11.4 12.4 12.3 10.8 2003 95.6 80.6 91.1 76.9 83.5 74.9 86.3 73.8 88.0 89.1 100.3 7.4 19.7 1.9 5.7 5.2 14.6 8.9 16.9 0.2 4.1 11.6 26.7 7.9 14.1 0.9 14.8 10.9 15.0 1.6 2.1 2.7 4.0 38.1 1.0 4.7 23.3 11.2 21.6 9.2 6.8 2.8 6.9 36.8 18.2 38.6 43.9 2002 77.2 87.2 86.6 70.7 75.0 81.4 82.0 78.4 77.3 70.0 82.6 5.6 41.5 2.4 10.1 12.6 16.0 26.9 19.1 3.9 14.0 12.0 27.5 1.0 15.2 18.8 1.0 23.0 20.2 19.1 8.1 8.2 9.8 11.4 9.5 45.2 0.9 3.7 24.2 30.0 22.0 12.5 25.7 5.8 10.4 23.0 23.8 5.2 37.1 2001 83.8 98.1 74.1 70.3 73.7 81.3 74.7 77.7 73.3 80.7 92.9 14.3 46.6 3.6 7.4 12.9 9.7 21.5 23.5 8.5 23.4 13.4 34.3 0.8 1.0 6.1 23.9 44.2 1.6 22.1 24.7 19.0 2.1 6.7 8.1 11.0 22.0 50.0 1.8 0.9 20.4 32.4 30.7 49.8 21.4 34.6 10.7 19.8 – – – – 2000 95.2 87.7 83.8 85.4 83.5 70.1 72.1 84.9 82.5 83.4 74.3 22.1 54.4 6.5 14.7 16.7 16.1 44.2 39.8 27.2 34.2 23.2 40.2 11.6 4.2 20.7 37.0 59.9 4.1 22.0 30.0 35.0 20.7 18.5 20.8 24.0 31.8 55.0 4.7 18.9 29.3 43.8 36.4 50.0 32.3 43.2 17.8 18.8 – – – – (RMR) Reliability Must Run for ERCOT 15
Slide 17: OPERATING STATISTICS – TXU POWER Net Heat Rates – Texas Btu/kWh Plant Comanche Peak Comanche Peak Big Brown Big Brown Monticello Monticello Monticello Martin Lake Martin Lake Martin Lake Sandow Collin DeCordova Decordova CT's Eagle Mountain Eagle Mountain Eagle Mountain Graham Graham Lake Creek Lake Creek Lake Hubbard Lake Hubbard Morgan Creek (R) Morgan Creek (R) Morgan Creek (R) Morgan Creek Morgan Creek Morgan Creek CT's North Lake North Lake North Lake North Main (R) Parkdale (R) Parkdale (R) Parkdale (R) Permian Basin Permian Basin Permian Basin CT's River Crest (R) Stryker Creek Stryker Creek Tradinghouse Tradinghouse Valley Valley Valley Trinidad Sweetwater Sweetwater CT Sweetwater CT Sweetwater CT (R) Retired during 2004. Unit 1 2 1 2 1 2 3 1 2 3 4 1 1 1 2 3 1 2 1 2 1 2 2 3 4 5 6 1 2 3 4 1 2 3 5 6 6 1 2 1 2 1 2 3 6 4 1 2 3 Low 10,200 9,500 10,587 10,587 10,587 10,587 10,587 10,587 10,587 10,587 10,587 10,430 9,812 9,250 10,430 10,430 10,430 10,430 9,812 10,430 10,430 10,430 9,812 10,430 10,430 10,430 10,430 9,812 9,250 10,430 10,430 10,430 10,430 10,430 10,430 10,430 10,430 9,812 9,250 10,430 10,430 9,812 9,812 9,812 10,430 9,812 10,430 10,430 11,500 11,500 11,500 11,500 High 10,500 10,500 11,517 11,517 11,517 11,517 11,517 11,517 11,517 11,517 11,517 32,426 13,316 9,800 32,426 32,426 32,426 32,426 13,316 32,426 32,426 32,426 13,316 32,426 32,426 32,426 32,426 13,316 9,800 32,426 32,426 32,426 32,426 32,426 32,426 32,426 32,426 13,316 9,800 32,426 32,426 13,316 13,316 13,316 32,426 13,316 32,426 32,426 12,000 12,000 12,000 12,000 16
Slide 18: OPERATING STATISTICS – TXU POWER Fuel Mix and Average Cost – Texas For the years ended December 31, 2000 – 2004; Mixed measures 2004 2003 2002 Statistic Generation (MWh) Nuclear Lignite/Coal Gas/Oil Gas/Oil Divested Total Generation Mix (%) Nuclear Lignite/Coal Gas/Oil Total Fuel Cost ($000)1 Nuclear Lignite/Coal Total Base Load Average Fuel Cost ($/MWh)1 Nuclear Lignite/Coal Total Base Load 19,052,643 44,116,439 4,673,910 – 67,842,992 17,749,343 43,240,756 13,098,982 – 74,089,081 16,579,084 39,817,056 18,733,486 854,232 75,983,858 2001 18,322,265 39,506,193 24,371,090 3,626,265 85,825,813 2000 18,487,842 40,993,945 32,102,173 5,292,578 96,876,538 28% 65% 7% 100% 24% 58% 18% 100% 22% 52% 26% 100% 21% 46% 33% 100% 19% 42% 39% 100% 81,748 548,650 630,398 79,503 517,470 596,973 76,365 482,811 559,176 88,796 543,498 632,294 99,151 464,558 563,709 4.29 12.43 9.98 4.48 11.97 9.79 4.61 12.13 9.92 4.85 13.76 10.93 5.36 11.33 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
Slide 19: OPERATING STATISTICS – TXU POWER O&M/SG&A For the years ended December 31, 2000 – 2004; $ thousands Plant Type Nuclear Lignite/Coal Gas/Oil Other Total 2004 235,786 208,805 92,070 143,049 679,710 2003 213,725 218,272 111,283 57,773 601,053 2002 236,305 195,458 105,904 98,973 636,640 2001 194,300 163,925 120,016 133,359 611,600 2000 208,571 146,978 125,123 103,223 583,895 Depreciation Rates For the years ended December 31, 2000 – 2004, except as noted; % Plant Type Nuclear Lignite/Coal Gas/Oil 2004 1.70 1.98 2.31 Apr-Dec 2003 1.83 2.97 2.31 Jan - Mar 2003 2.51 2.46 2.00 2002 2.51 2.46 2.00 2001 2.51 2.46 2.00 2000 2.51 2.46 2.00 Net Heat Rate For the years ended December 31, 2000 – 2004; Btu/kWh Plant Type Nuclear Lignite/Coal Gas/Oil 2004 10,280 11,237 12,040 2003 10,399 11,220 11,201 2002 10,470 11,192 10,998 2001 9,983 11,216 10,698 2000 10,401 11,119 10,715 Outage Management (Base Load) For the years ended December 31, 2000 – 2004; TWh Category Total Planned Unplanned Total Nuclear Planned Unplanned Total Lignite/Coal Planned Unplanned Total 2004 3.8 3.5 7.3 1.1 0.1 1.2 2.7 3.4 6.1 2003 3.3 5.6 8.9 0.7 1.1 1.8 2.6 4.5 7.1 2002 5.1 6.6 11.7 2.2 0.6 2.8 2.9 6.0 8.9 2001 3.1 6.8 9.9 0.8 0.4 1.2 2.3 6.4 8.7 2000 3.3 4.6 7.9 1.0 0.0 1.0 2.3 4.6 6.9 18
Slide 20: 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 2004 Q1 Q2 Q3 Q4 Total 2004 Q1 Q2 Q3 Q4 Total 2003 Q1 Q2 Q3 Q4 Total 2002 NYMEX (GDD)2 $ 5.612 $ 6.085 $ 5.450 $ 6.254 $ 5.850 $ 5.878 $ 5.738 $ 4.897 $ 5.498 $ 5.503 $ 2.491 $ 3.405 $ 3.192 $ 4.325 $ 3.353 5 X 16 $ 39.862 $ 48.496 $ 47.530 $ 48.907 $ 46.210 $ 52.796 $ 51.098 $ 42.873 $ 38.535 $ 46.326 $ 21.448 $ 29.885 $ 30.072 $ 34.796 $ 29.050 5X8 $ 28.727 $ 34.037 $ 31.451 $ 31.592 $ 31.455 $ 37.348 $ 31.964 $ 28.794 $ 24.695 $ 30.700 $ 14.158 $ 15.145 $ 18.031 $ 22.449 $ 17.446 7 X 24 $ 34.197 $ 41.134 $ 39.374 $ 40.124 $ 38.707 $ 45.781 $ 44.224 $ 36.913 $ 34.368 $ 40.322 $ 18.880 $ 24.499 $ 25.803 $ 30.308 $ 24.872 5 X 16 7.115 7.963 8.714 7.802 7.901 8.982 8.905 8.755 7.009 8.413 8.611 8.777 9.422 8.046 8.714 Heat Rates 5X8 5.119 5.559 5.762 5.003 5.371 6.354 5.571 5.880 4.491 5.574 5.684 4.448 5.650 5.191 5.243 7 X 24 6.098 6.760 7.217 6.382 6.614 7.789 7.707 7.538 6.251 7.321 7.580 7.195 8.085 7.008 7.467 2003 2002 1 2 Power Prices are the Megawatt Daily non zonal ERCOT day ahead cash prices in $/MWh. NYMEX gas price is the Gas Daily data for day ahead prices in the cash month in $/MMBtu. 19
Slide 21: OPERATING STATISTICS – TXU ENERGY Selected Credit Statistics for Wholesale Sales1 As of December 31, 2002 – 2004; $ millions, % Statistic Gross Credit Exposure (Net of Collateral) Investment Grade Credit Exposure (Net of Collateral) Less than 2 years 2 - 5 years Greater than 5 years Total Non Investment Grade Credit Exposure (Net of Collateral) Less than 2 years 2 - 5 years Greater than 5 years Total % Investment Grade (Net of Collateral) % Non Investment Grade (Net of Collateral) Total Credit Exposure Maturities (Net of Collateral) Less than 2 years 2 - 5 years Greater than 5 years Total 2004 $ 600 $ 317 86 77 $ 480 $ 79 22 19 $ 120 80% 20% 100% 66% 18% 16% 100% 2003 $ 740 $ 424 119 119 $ 662 $ 50 14 14 $ 78 89% 11% 100% 64% 18% 18% 100% 2002 $ 866 $ 624 22 4 $ 650 $ 195 21 0.3 $ 216 75% 25% 100% 94% 5% 1% 100% Selected Credit Statistics For Large Business Retail Sales1 As of December 31, 2002 – 2004; $ millions, % Statistic Gross Credit Exposure (Net of Collateral) Investment Grade Credit Exposure (Net of Collateral) Less than 2 years 2 - 5 years Greater than 5 years Total Non Investment Grade Exposure (Net of Collateral) Less than 2 years 2 - 5 years Greater than 5 years Total % Investment Grade % Non Investment Total Credit Exposure Maturities (Net of Collateral) Less than 2 years 2 - 5 years Greater than 5 years Total 2004 $ 184 $ 148 3 0 $ 151 $ 33 0 0 $ 33 82% 18% 100% 98% 2% 0% 100% 2003 $ 226 $ 155 10 0 $ 165 $ 57 4 0 $ 61 73% 27% 100% 94% 6% 0% 100% 2002 $ 319 $ 139 28 0 $ 167 $ 152 0 0 $ 152 52% 48% 100% 91% 9% 0% 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
Slide 22: OPERATING STATISTICS – TXU ENERGY Financial and Operating Data For the years ended December 31, 2002 – 2004; Mixed measures Statistic Electric Operating Revenues ($ millions) Residential Small Business Large Business Total Electric Energy Sales (GWh) Residential Small Business Large Business Total Number of Electric Customers (thousands of meters) Native Market: Residential Small Business Total Native Market Other Markets: Residential Small Business Total Other Markets Large Business Total Electric Customers Net Customer Change Native Market Other Markets Call Center Metrics Answer Speed (seconds) Abandoned Calls Credit and Collection Metrics Average Receivables ($ millions) Less than 30 days 30-60 days 60-90 days Greater than 90 days Bad Debt Expense ($ millions) Bad Debt as % of Total Revenues 2004 $3,462 1,137 1,771 $6,370 33,986 10,839 25,466 70,291 1,951 309 2,260 194 6 200 76 2,536 (4.8)% 30.7% 39 4% 2003 $3,311 1,238 1,935 $6,484 35,981 12,986 30,955 79,922 2,059 316 2,375 148 5 153 69 2,597 (6.2)% 48.5% 268 26% 2002 $3,108 1,330 2,085 $6,523 37,692 15,907 36,982 90,581 2,204 328 2,532 98 5 103 78 2,713 (3.5)% 1,473% 93 11% 262.4 37.1 8.8 8.2 94.6 1.49% 302.7 55.9 19.5 24.7 120.5 1.84% 341.7 88.3 55.2 78.4 118.4 1.80% 21
Slide 23: OPERATING STATISTICS – TXU ENERGY Price to Beat and Gas Component Information – Residential Affiliate REP TXU Docket No. 24040 25802 27281 28191 29516 29837 31004 24194 25885 27167 27390 27511 29800 30375 30999 24195 25873 27376 29293 29845 30966 Mutual Energy - WTU 24335 25874 Effective 01/01/2002 08/27/2002 03/11/2003 08/22/2003 05/20/2004 08/04/2004 05/12/2005 01/01/2002 08/27/2002 02/04/2002 03/27/2003 04/22/2003 07/07/2004 12/21/2004 05/12/2005 01/01/2002 08/27/2002 03/25/2003 03/16/2004 08/10/2004 05/03/2005 01/01/2002 08/27/2002 Gas Price As Filed $ 3.111 $ 3.619 $ 4.910 $ 5.362 $ 5.785 $ 6.517 $ 7.872 $ 3.111 $ 3.817 $ 4.526 $ 5.166 $ 5.958 $ 6.454 $ 7.450 $ 7.845 $ 3.111 $ 3.795 $ 5.123 $ 5.586 $ 6.517 $ 7.603 $ 3.111 $ 3.795 Gas Price Increase – 16.3% 35.7% 9.2% 7.9% 12.7% 20.8% – 22.7% 18.6% 14.1% 15.3% 8.32% 15.4% 5.3% – 22.0% 35.0% 9.0% 16.7% 16.7% – 22.0% Months – All All All All All All – All All All All All All All – Mar-Jun Jul-Oct Nov-Feb Mar-Jun Jul-Oct Nov-Feb Mar-Jun Jul-Oct Nov-Feb Mar-Jun Jul-Oct Nov-Feb Mar-Jun Jul-Oct Nov-Feb – Dec-Feb Mar-May Jun-Aug Sep-Nov Dec-Feb Mar-May Jun-Aug Sep-Nov Dec - Feb Mar-May Jun-Aug Sep-Nov Dec - Feb Mar-May Jun-Aug Sep-Nov – All All All All All All Fuel Factor – 2.8935 3.9265 4.2877 4.6264 5.2140 6.2985 – 2.67396 3.17085 3.61921 4.17403 4.52131 5.21895 5.49555 – 4.2908 3.9793 3.3763 5.7926 5.3721 4.5580 6.3139 5.8556 4.9682 7.3683 6.8335 5.7979 8.5988 7.9747 6.7661 – 3.9894 6.0140 4.9507 3.8627 5.3857 8.1189 6.6834 5.2146 5.8704 8.8496 7.2849 5.6839 6.8508 10.3275 8.5015 6.6331 – 3.0377 3.2716 4.0372 4.9698 6.1079 6.1079 Average Price1 (¢/kWh) 8.26 8.66 9.69 10.06 10.39 10.98 12.07 8.66 9.15 9.65 10.10 10.65 11.00 11.70 11.98 8.88 9.52 10.93 11.42 12.41 13.56 8.90 9.71 First Choice Mutual Energy - CPL 27377 03/25/2003 $ 5.123 35.0% 11.34 29292 03/16/2004 $ 5.586 9.0% 11.91 29845 08/10/2004 $ 6.517 16.7% 13.46 Reliant 23950 25840 26933 27320 27956 30378 3077422 01/01/2002 08/27/2002 12/20/2002 03/11/2003 07/26/2003 12/21/2004 050/2/2005 $ 3.111 $ 3.729 $ 4.017 $ 4.956 $ 6.100 $ 7.500 $ 7.500 – 19.9% 7.7% 23.4% 23.1% 23.0% N/A 8.62 9.12 9.35 10.12 11.05 12.19 12.80 1 2 Average price calculated based on 1000 KWh/month. Increase due to elimination of EMC credit and addition of transition charge reflected in an increased base rate. 22
Slide 24: OPERATING STATISTICS – TXU ENERGY Native Market Price Comparison1 Various dates; ¢/kWh Retail Electric Provider TXU – PTB Reliant Direct Energy First Choice (TNMP) Entergy Solutions Green Mountain (Pollution Free) 06/01/05 12.07 11.58 10.10 10.80 10.80 10.99 12/31/04 10.98 10.21 10.10 10.80 10.50 10.99 12/31/03 10.06 9.05 9.60 10.75 8.80 10.66 06/03/03 9.69 8.73 9.28 10.75 8.60 10.30 12/31/02 8.66 8.23 8.48 8.20 8.15 9.00 1 Rates calculated for residential customer using 12,000 KWh/year. 23
Slide 25: OPERATING STATISTICS – TXU ENERGY HOLDINGS SEGMENT Financial and Operating Data For the years ended December 31, 2002 – 2004; Mixed measures Statistic Operating Statistics – Volumes Retail Electricity (GWh) Residential Small Business2 Large Business and Other Total Retail Electricity Wholesale Electricity (GWh) Production and Purchased Power (GWh) Nuclear and Lignite/Coal (Base Load) Gas/Oil and Purchased Power Total Production and Purchased Power Customer Counts Retail Electricity Customers (end of period and in thousands – based on number of meters): Residential Small Business Large Business and Other Total Retail Electricity Customers Operating Revenues ($ millions) Retail Electricity Revenues Residential Business and Other Total Retail Electricity Revenues Wholesale Electricity Revenues Hedging and Risk Management Activities Other Revenues Total Operating Revenues Weather (Average for Service Territory) Percent of Normal: Cooling Degree Days Heating Degree Days $ 3,462 2,908 6,370 1,886 (103) 342 $ 8,495 $ 3,311 3,173 6,484 1,258 30 214 $ 7,986 $ 3,108 3,415 6,523 841 147 167 $ 7,678 2004 2003 20021 33,986 10,839 25,466 70,291 48,309 61,318 60,733 122,051 35,981 12,986 30,955 79,922 36,809 59,028 63,165 122,193 37,692 15,907 36,982 90,581 29,649 54,738 70,118 124,856 2,145 315 76 2,536 2,207 321 69 2,597 2,302 333 78 2,713 89.9% 89.2% 95.7% 98.1% 99.8% 102.0% 1 2 Adjusted from previous report due to reclassification of discontinued operations. Customers with demand of less than 1MW annually 24
Slide 26: 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. Market Peak Demand – Summer (MWs) ............................................................................. Total Installed Capacity (MWs) ........................................................................................... Interconnection Capacity (MWs) ......................................................................................... Reserve Margin .................................................................................................................... Number of Competitive Customers (millions) ..................................................................... North Texas 1,326 2004 58,528 75,056 856 28% 5.13 South Texas 1,402 Usage Per Residential Customer (kWh) ............................. ERCOT Summer 2004 Fuel Types 1% 3% 11% 39% 46% Coal and Lignite Natural Gas Nuclear Renewable Other 25
Slide 27: 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 Northeast 923 North West 971 South 1565 Houston 26
Slide 28: ERCOT/TEXAS MARKET/REGULATORY HIGHLIGHTS Market Rules Overview Rule Price to Beat Definition 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. Impact to TXU 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. Power generation companies affiliated with electric delivery utilities may charge unregulated prices in connection with ERCOT wholesale power transactions. 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. 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 Provider of Last Resort (POLR) 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
Slide 29: ERCOT/TEXAS MARKET/REGULATORY HIGHLIGHTS Summary of Settlement Plan1 Major Element Excess Mitigation Credit Description 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. 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. 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. 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. Regulatory Asset Securitization Retail Clawback Credit Stranded Costs and Fuel Cost Recovery 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
Slide 30: 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 sixyear staggered terms of office. A chairperson is designated by the Governor. Commissioner Paul Hudson (Chair) Term Expires September 2009 Background 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 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 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 Julie Parsley September 2005 Barry T. Smitherman September 2007 29
Slide 31: SCHEDULE OF LONG-TERM DEBT As of December 31, 2004; $ millions Issue TXU Corp. Senior Notes Series C, 6.375% (a) Series J, 6.375% (a) Series K, 4.446% Series L, 5.45% (c) Series M, 5.80% (c) Series O, 4.80% (a) Series P, 5.55% Series Q, 6.50% (a) Series R, 6.55% Conv Senior Notes, 3.57% (e) Other Building Financing, 8.820% Unamortized Prem and Disc Total TXU Corp. TXU Energy Company LLC Pollution Control Revenue Bonds(PCRBs) Brazos River Authority: 3.00% Series 1994A (f) 2029 5.40% Series 1994B (f) 2029 5.40% Series 1995A (f) 2030 5.05% Series 1995B (f) 2030 7.70% Series 1999A 2033 6.75% Series 1999B (f) 2034 7.70% Series 1999C 2032 4.75% Series 2001B (f) 2029 5.75% Series 2001C (f) 2036 2.03% Series 2001D (h) 2033 2.45% Series 2001I (h) 2036 2.03% Series 2002A (h) 2037 6.75% Series 2003A (f) 2038 6.30% Series 2003B 2032 6.75% Series 2003C 2038 5.40% Series 2003D (f) 2029 Sabine River Authority: 6.45% Series 2000A 2021 5.50% Series 2001A (f) 2022 5.75% Series 2001B (f) 2030 5.80% Series 2003A 2022 6.15% Series 2003B 2022 Trinity River Authority: 6.25% Series 2000A 2028 5.00% Series 2001A (f) 2027 Total PCRBs Senior Notes 6.875% Senior Notes – Mining 2005 6.125% Senior Notes (a) 2008 7.00% Senior Notes 2013 2.838% Senior Notes (e) 2006 Year Due Fixed/ Floating 2005 2006 2007 2008 2009 & Beyond Total Date of Next Redemption Next Redemption Price 2008 2006 2006 2007 2008 2009 2014 2024 2034 2033 2022 Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Floating Fixed 9 200 683 50 101 184 1,000 1,000 750 750 25 9 9 9 84 (11) 3,598 200 683 50 101 184 1,000 1,000 750 750 25 120 (11) 4,852 01/01/08 (b) 100.00 T+20 (b) (b) (b) (b) 07/15/08 T+25 T+30 T+35 T+35 100.00 9 742 110 393 Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Floating Floating Floating Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Floating 30 250 - 39 39 50 114 111 16 50 19 217 268 62 45 44 39 52 31 51 91 107 12 45 14 37 1,553 39 39 50 114 111 16 50 19 217 268 62 45 44 39 52 31 51 91 107 12 45 14 37 1,553 30 250 1,000 400 9 15 3,257 05/01/05 (g) 05/01/06 (g) 05/01/06 (g) 06/19/06 (g) 04/01/13 04/01/13 (g) 04/01/13 11/01/06 (g) 11/01/11 (g) (b) (b) (b) 04/01/13 (g) 07/01/13 10/01/13 10/01/14 (g) 06/01/10 11/01/11 (g) 11/01/11 (g) 07/01/13 08/01/13 05/01/13 11/01/06 (g) (d) (b) (b) (b) 100.00 100.00 100.00 100.00 101.00 100.00 101.00 100.00 100.00 100.00 100.00 100.00 100.00 101.00 101.00 100.00 101.00 100.00 100.00 101.00 101.00 101.00 100.00 1,000 400 9 15 30 400 250 2,577 T+37.5 T+50 100.00 Other Capital Lease Obligations Various Fair Value Adjustments – int. rate swaps - various Unamortized Prem and Disc Total TXU Energy Company LLC TXU Electric Delivery First Mortgage Bonds 6.75% due 7/01/05 Senior Secured Notes 6.375% 7.00% 2005 2012 2032 Fixed Fixed Fixed 92 700 500 92 700 500 (d) (b) (b) 100.00 T+25 T+30 30
Slide 32: SCHEDULE OF LONG-TERM DEBT (CONT.) As of December 31, 2004; $ millions Year Due Fixed/ Floating 2009 & Beyond 500 350 200 200 80 122 130 145 270 221 290 1,178 4,009 800 19 2,831 Date of Next Redemption (b) (b) (b) (b) Next Redemption Price T+30 T+35 T+20 T+30 Issue 2005 TXU Electric Delivery 6.375% (a) 2015 Fixed 7.25% 2033 Fixed Debentures 5.00% (a) 2007 Fixed 7.00% 2022 Fixed Unamortized Prem and Disc Sub-total 92 TXU Electric Delivery Transition Bond Company(i) 2.26% Series 2003 2007 Fixed 4.03% Series 2003 2010 Fixed 4.95% Series 2003 2013 Fixed 5.42% Series 2003 2015 Fixed 3.52% Series 2004 2009 Fixed 4.81% Series 2004 2012 Fixed 5.29% Series 2004 2016 Fixed Sub-total Total TXU Electric Delivery 92 TXU US Holdings Senior Debentures 7.17% Notes 9.58% semi-annual 8.254% quarterly Junior Subord Debentures 2.494%, Series D (e) 8.175%, Series E Total TXU US Holdings 2006 2007 2008 Total 500 350 200 800 19 3,123 80 122 130 145 270 221 290 1,258 4,381 (j) (j) (j) (j) (d) (d) (d) 100.00 100.00 100.00 100.00 - 80 280 - 2007 2019 2021 2037 2037 Fixed Fixed Fixed Floating Fixed - 10 68 64 1 8 141 10 68 64 1 8 151 (b) (d) (d) (b) 02/01/07 T+10 100.00 104.09 10 - 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. 31
Slide 33: SCHEDULE OF PREFERRED SECURITIES As of December 31, 2004; $ millions Redemption Price at 12/31/04 Issue TXU Corp. Preference Stock, 7.24%1 Total TXU Corp. TXU US Holdings Preferred Stock $4.00 Series – TPL $4.44 Series – TPL $4.56 Series - TPL $4.76 Series - TPL $4.84 Series - TPL $4.00 Series - TES $4.56 Series - TES $4.64 Series - TES $5.08 Series - TES $4.00 Series - DPL $4.24 Series - DPL $4.50 Series - DPL $4.80 Series - DPL Total TXU US Holdings Year Due Fixed/ Floating Total Perpetual Fixed 300 300 Perpetual Perpetual Perpetual Perpetual Perpetual Perpetual Perpetual Perpetual Perpetual Perpetual Perpetual Perpetual Perpetual Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed Fixed 3 3 5 2 2 7 2 3 3 2 2 2 2 38 102.00 102.61 112.00 102.00 101.79 102.00 112.00 103.25 102.00 103.56 103.50 110.00 102.79 Total Preferred Securities 338 1 Called for redemption effective 06/15/05. 32
Slide 34: 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 $0.272 $1.63 $0.37 $2.05 $2.12 Earnings Per Share: Basic Dilutive Shares Outstanding (year end - millions) Weighted Average Shares Outstanding (millions): Basic Dilutive Dividends Paid ($ millions) Dividends Paid Dividend Payout Ratio (percent) Book Value Historical Stock Prices Market Price: High Low Close $(1.29) $(1.29) 240 300 300 $150 $0.50 – $1.26 $1.74 $1.62 324 322 379 $160 $0.50 30.9% $17.34 $(15.23) $(15.23) 322 278 278 $652 $2.40 – $14.80 $2.52 $2.52 265 259 259 $621 $2.40 95.2% $28.88 $3.43 $3.43 258 264 264 $634 $2.40 70.0% $28.97 $67.00 $23.35 $64.56 $23.96 $15.00 $23.72 $57.05 $10.10 $18.68 $50.00 $34.81 $47.15 $45.25 $25.94 $44.31 CREDIT RATINGS3 As of April 2005 Company/Bonds TXU Corp. Senior Unsecured Preference Stock TXU US Holdings Senior Unsecured TXU Electric Delivery Secured Senior Unsecured TXU Energy Company LLC Senior Unsecured Moody’s Ba1 Ba2 Baa3 Baa1 Baa2 Baa2 S&P BBBBB+ BBBBBB BBBBBB Fitch BBBBB+ BBBA-/BBB+ BBB+ BBB 1 2 3 Prior year periods have been reclassified to reflect certain operations as discontinued operations. 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. 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. 33
Slide 35: LIQUIDITY As of April 29, 2005 and December 31, 2004; $ millions Liquidity Component Cash and Cash Equivalents $1.4 billion credit facility $1.6 billion credit facility $500 million credit facility $500 million credit facility Terminated facilities Total Available Liquidity Borrower TXU Energy/TXU Electric Delivery Co. TXU Energy/TXU Electric Delivery Co. TXU Energy/TXU Electric Delivery Co. TXU Energy Maturity June 08 March 10 June 10 December 09 4/29/05 10 966 1,560 375 – 2,911 12/31/04 106 1,172 500 500 531 2,809 CAPITAL EXPENDITURES1 For the years ended December 31, 2001 – 2004; $ millions Segment TXU Energy Holdings TXU Electric Delivery Corporate and Other Total 2004 281 600 31 912 2003 163 543 15 721 2002 284 513 16 813 2001 327 635 26 988 1 Prior year periods have been reclassified to reflect certain operations as discontinued operations. 34
Slide 36: 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
Slide 37: 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 3rd 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. 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 February 18, 2005 May 20, 2005 August 19, 2005 November 18, 2005 Record Date March 4, 2005 June 3, 2005 September 2, 2005 December 2, 2005 Payment Date April 1, 2005 July 1, 2005 October 3, 2005 January 3, 2006 Dividend information will be updated according to the declaration schedule. Quarterly dividend payments (in cents per share): Quarter 1 2 3 4 2004 12.5 12.5 12.5 12.5 2003 12.5 12.5 12.5 12.5 2002 60.0 60.0 60.0 60.0 2001 60.0 60.0 60.0 60.0 2000 60.0 60.0 60.0 60.0 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. 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 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 Quarter 1 2 3 4 High $30.13 $40.72 $48.25 $67.00 Low $23.35 $27.15 $38.34 $48.05 2003 High $20.37 $22.87 $23.70 $23.96 Low $15.00 $17.54 $19.58 $20.87 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

   
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