Texas Competitive Electric 8-K Departure of Directors or Principal Officers

Exhibit 99.1

FORWARD-LOOKING STATEMENTS

This Current Report on Form 8-K contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that are included in this Current Report on Form 8-K, or made in presentations, in response to questions or otherwise, that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as projections, capital allocation and cash distribution policy, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power production assets, market and industry developments and the growth of our business and operations (often, but not always, identified through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “projection,” “target,” “outlook” and our use of the conditional and future tenses), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors discussed under “Risk Factors” and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:

• governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the U.S. Congress, the Federal Energy Regulatory Commission (“FERC”), the Public Utility Commission of Texas (“PUCT”), the Railroad Commission of Texas, the U.S. Nuclear Regulatory Commission (“NRC”), the U.S. Environmental Protection Agency (“EPA”) and the Texas Commission on Environmental Quality (“TCEQ”), with respect to, among other things:

• allowed prices;

• allowed rates of return;

• industry, market and rate structure;

• purchased power and recovery of investments;

• operations of nuclear generating facilities;

• acquisitions and disposal of assets and facilities;

• development, construction and operation of facilities;

• decommissioning costs;

• present or prospective wholesale and retail competition;

• changes in tax laws and policies; and

• changes in and compliance with environmental and safety laws and policies, including climate change initiatives;

• continued implementation of the legislation that restructured the electric utility industry in Texas to provide for retail competition (“1999 Restructuring Legislation”);

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• legal and administrative proceedings and settlements;

• general industry trends;

• our ability to attract and retain customers;

• our ability to profitably serve our customers given our announced price protection and price cuts;

• restrictions on competitive retail pricing;

• changes in wholesale electricity prices or energy commodity prices;

• unanticipated changes in market heat rates in the Texas electricity market;

• our ability to effectively hedge against changes in commodity prices and market heat rates;

• weather conditions and other natural phenomena, and acts of sabotage, wars or terrorist activities;

• unanticipated population growth or decline, and changes in market demand and demographic patterns;

• changes in business strategy, development plans or vendor relationships;

• access to adequate transmission facilities to meet changing demands;

• unanticipated changes in interest rates, fuel prices, commodity prices, rates of inflation or foreign exchange rates;

• unanticipated changes in operating expenses, liquidity needs and capital expenditures;

• commercial bank market and capital market conditions;

• competition for new energy development and other business opportunities;

• inability of various counterparties to meet their obligations with respect to our financial instruments;

• changes in technology used by and services offered by us;

• significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur;

• changes in assumptions used to estimate future executive compensation payments;

• significant changes in critical accounting policies;

• actions by credit rating agencies;

• our ability to implement cost reduction initiatives;

• with respect to our lignite coal-fueled generation construction and development program, more specifically, our ability to fund such investments, changes in competitive market rules, changes in environmental laws or regulations, changes in electric generation and emissions control technologies, changes in projected demand for electricity, our ability and the ability of our contractors to attract and retain, at projected rates, skilled labor for constructing the new generating units, changes in wholesale electricity prices or energy commodity prices, transmission capacity and constraints, supplier performance risk, changes in the cost and availability of materials necessary for the construction program and our ability to manage the significant construction program to a timely conclusion with limited cost overruns; and

• with respect to the Merger (as defined below), the outcome of any legal proceedings that have been or may be instituted against the Issuer and others related to the Merger; risks that the Merger and related transactions disrupt current plans and operations and the potential difficulties in management and employee retention as a result of the Merger; the amount of the costs, fees, expenses and charges related to the Merger; and the impact of the substantial indebtedness incurred to finance the consummation of the Merger.

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Any forward-looking statement speaks only as of the date on which it is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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Summary Historical and Unaudited Pro Forma Consolidated Financial and Other Data of Energy Future Holdings Corp. and its Subsidiaries

The following table sets forth our summary historical consolidated financial data and summary unaudited pro forma consolidated financial data as of and for the periods indicated. The historical financial data as of December 31, 2005 and 2006 and for the three years ended December 31, 2004, 2005 and 2006 have been derived from our audited historical consolidated financial statements and related notes. The historical financial data as of December 31, 2004 has been derived from our historical consolidated financial statements. The historical financial data as of June 30, 2007 and for the six months ended June 30, 2006 and 2007 have been derived from our unaudited historical interim condensed consolidated financial statements and related notes which have been prepared on a basis consistent with our audited historical consolidated financial statements. In the opinion of our management, such unaudited interim financial data reflects all adjustments, consisting only of normal and recurring adjustments, necessary for the fair presentation of the results for those periods. The results of operations for the interim periods, for seasonal and other factors, are not necessarily indicative of the results to be expected for the full year or any future period.

As required by GAAP, Oncor Electric Delivery Holdings and its subsidiaries are consolidated with Energy Future Holdings Corp. for financial reporting purposes and, therefore, the results of these entities are reflected in the financial and other data presented below. However, Oncor Electric Delivery Holdings and its subsidiaries are ring-fenced from Energy Future Holdings Corp. and its other subsidiaries as described under “The Transactions—Ring Fencing,” which means there are restrictions on the ability of Oncor Electric Delivery Holdings and its subsidiaries to make dividends, distributions or other payments to us.

The summary unaudited pro forma condensed consolidated financial data as of and for the twelve months ended June 30, 2007 have been prepared to give effect to the Transactions in the manner described under “Energy Future Holdings Corp. Unaudited Pro Forma Condensed Consolidated Financial Statements” as if the Transactions had occurred on January 1, 2006, in the case of the unaudited pro forma condensed consolidated income statement and related data, and on June 30, 2007, in the case of the unaudited pro forma condensed consolidated balance sheet and related data. The pro forma adjustments are based upon available information and certain assumptions that we believe are reasonable. The summary unaudited pro forma consolidated financial and other data are for informational purposes only and do not purport to represent what our results of operations, balance sheet data or other financial information actually would have been if the Transactions had occurred at any date. In addition, this data does not purport to project the results of operations for any future period.

The summary historical and unaudited pro forma consolidated financial and other data should be read in conjunction with “Energy Future Holdings Corp. Unaudited Pro Forma Condensed Consolidated Financial Statements,” “Energy Future Holdings Corp. Selected Historical Consolidated Financial Data,” “Energy Future Holdings Corp. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited and unaudited consolidated financial statements and related notes appearing elsewhere in this Current Report on Form 8-K.

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	Historical															Pro Forma Twelve Months Ended June 30,
	Year Ended December 31,									Six Months Ended June 30,
	2004			2005			2006			2006			2007			2007
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues	$	9,216		$	10,662		$	10,856		$	4,971		$	3,691		$	9,599
Income (loss) from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles		81			1,775			2,465			1,013			(388	)		(1,040	)
Income from discontinued operations, net of tax effect		378			5			87			60			11
Extraordinary gain (loss), net of tax effect		16			(50	)		—			—			—
Cumulative effect of changes in accounting principles, net of tax effect		10			(8	)		—			—			—
Exchangeable preferred membership interest buyback premium		849			—			—			—			—
Preference stock dividends		22			10			—			—			—
Net income (loss) available for common stock		(386	)		1,712			2,552			1,073			(377	)
Dividends declared per share	$	0.47		$	1.26		$	1.67		$	0.83		$	0.87
Ratio of earnings to fixed charges(a)		1.16	x		3.80	x		5.11	x		4.41	x		—
Ratio of earnings to combined fixed charges and preference dividends(a)		1.11x			3.74x			5.11x			4.41x			—
Pro forma ratio of earnings to fixed charges(a)(b)		N/A			N/A			1.27	x		1.11	x		—			—
Balance Sheet Data (at end of period):
Total assets	$	23,189		$	25,539		$	25,922					$	26,988		$	63,925
Property, plant & equipment—net		16,676			17,192			18,756						19,387			26,686
Total intangible assets and goodwill		732			736			747						738			28,867
Total debt		12,851			13,380			12,607						15,059			40,318
Total preferred stock and stock of subsidiaries(c)		338			—			—						—			—
Total stockholders’ equity		639			475			2,140						1,045			8,300

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	Historical															Pro Forma Twelve Months Ended June 30, 2007
	Year Ended December 31,									Six Months Ended June 30,
	2004			2005			2006			2006			2007
	(millions of dollars, except ratios and per share amounts)
Statement of Cash Flows Data:
Cash flows provided by (used in) operating activities of continuing operations	$	1,758		$	2,793		$	4,954		$	1,904		$	(55	)
Cash flows provided by (used in) investing activities of continuing operations		4,280			(1,038	)		(2,664	)		(1,062	)		(1,506	)
Cash flows provided by (used in) financing activities of continuing operations		(6,519	)		(1,563	)		(2,332	)		(806	)		1,934
Other Financial Data:
Capital expenditures, including nuclear fuel	$	999		$	1,104		$	2,297		$	855		$	1,641
EBITDA(d)		1,982			3,932			5,475			2,478			150			3,015
Adjusted EBITDA(d)(e)		2,942			4,066			5,627			2,646			2,254			5,235
Ratio of Adjusted to total interest expense(d)(e)(f)		4.2	x		5.1	x		6.8	x		6.1	x		5.4	x		1.5	x
Ratio of Adjusted EBITDA to cash interest expense(d)(e)		4.2	x		5.3	x		6.8	x		6.1	x		5.8	x		1.5	x
Ratio of net debt to Adjusted EBITDA(d)(e)(g)		4.3	x		3.3	x		2.2	x		5.1	x		6.5	x		7.4	x
Other Financial Data (excluding Oncor Electric Delivery):
Adjusted EBITDA(d)(h)	$	1,843		$	2,811		$	4,671		$	2,211		$	1,815		$	4,275
Ratio of Adjusted EBITDA to total interest expense(d)(f)(h)		4.4	x		5.3	x		8.6	x		7.6	x		6.9	x		1.3	x
Ratio of Adjusted EBITDA to cash interest expense(d)(h)		4.5	x		5.6	x		8.6	x		7.4	x		7.6	x		1.4	x
Ratio of net debt to Adjusted EBITDA(d)(g)(h)		4.5	x		3.2	x		1.7	x		3.9	x		5.3	x		7.9	x

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	Year Ended December 31,						Six Months Ended June 30,
	2004		2005		2006		2006		2007
	(millions of dollars, except ratios and per share amounts)
Operating Data (at period end):
Total power generation capacity (in MW)(i)		18,353		18,365		18,190		18,365		18,365
Nuclear power generation capacity (in MW)		2,300		2,300		2,300		2,300		2,300
Lignite/Coal-fired generation capacity (in MW)		5,825		5,837		5,837		5,837		5,837
Total baseload capacity (in MW)		8,125		8,137		8,137		8,137		8,137
Available baseload capacity (in MW)		7,192		7,345		7,474		7,398		7,332
Baseload capacity by plant (in MW):
Comanche Peak		2,300		2,300		2,300		2,300		2,300
Monticello		1,880		1,880		1,880		1,880		1,880
Martin Lake		2,250		2,250		2,250		2,250		2,250
Big Brown		1,150		1,150		1,150		1,150		1,150
Sandow 4		545		557		557		557		557
Available baseload capacity by plant (in MW):
Comanche Peak		2,169		2,105		2,272		2,355		1,973
Monticello		1,600		1,690		1,708		1,574		1,839
Martin Lake		1,962		2,083		2,034		1,984		2,083
Big Brown		945		976		1,017		990		1,045
Sandow 4		516		491		443		495		392
Average power price ($ per MW)(j)	$	39.03	$	53.97	$	61.70	$	54.64	$	60.84

(a) For purposes of computing the ratio of earnings to fixed charges and ratio of earnings to combined fixed charges and preference dividends, (1) earnings consist of net income plus income taxes plus fixed charges less capitalized expenses related to indebtedness and (2) fixed charges consists of interest expense and capitalized expenses related to indebtedness. For purposes of computing the ratio of earnings to combined fixed charges and preference dividends, preference share dividends are included in fixed charges. For the six months ended June 30, 2007, fixed charges and combined fixed charges and preference dividends exceeded earnings by $682 million.

(b) For purposes of computing the pro forma ratio of earnings to fixed charges, the historical calculations were adjusted for the estimated increase in interest expense as contemplated by the Transactions. On a pro forma basis, for the six months ended June 30, 2007 and the twelve months ended June 30, 2007, fixed charges would have exceeded earnings by $2,060 million and $1,285 million, respectively.

(c) Preferred stock outstanding at June 30, 2007, December 31, 2006 and December 31, 2005 has a stated amount of $51,000.

(d) EBITDA, a measure used by management to evaluate operating performance, is defined as net income plus (i) provision for income taxes, (ii) interest expense and (iii) depreciation and amortization. EBITDA is not a recognized term under GAAP and does not purport to be an alternative to net income as a measure of operating performance or to cash flows from operating activities as a measure of liquidity or any other measure of financial performance presented in accordance with GAAP. Additionally, EBITDA is not intended to be a measure of free cash flow available for management’s discretionary use, as it does not consider certain cash requirements such as interest payments, tax payments and other debt service requirements. Management believes EBITDA is helpful in highlighting trends because EBITDA excludes the results of decisions that are outside the control of operating management and that can differ significantly from company to company depending on long-term strategic decisions regarding capital structure, the tax jurisdictions in which companies operate and capital investments. In addition, EBITDA provides more comparability between our historical results and results that reflect the new capital structure. Management compensates for the limitations of using non-GAAP financial measures by using

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them to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone. Because not all companies use identical calculations, our presentation of EBITDA may not be comparable to similarly titled measures of other companies.

Adjusted EBITDA (excluding Oncor Electric Delivery) and Adjusted EBITDA are defined as EBITDA adjusted to exclude noncash items, unusual items and other adjustments permitted in calculating covenant compliance under certain of our indebtedness. We believe that the inclusion of supplementary adjustments to EBITDA applied in presenting Adjusted EBITDA (excluding Oncor Electric Delivery) and Adjusted EBITDA are appropriate to provide additional information to investors about how the covenants in certain of our indebtedness will operate and about certain noncash items, unusual items that we do not expect to continue at the same level in the future and other items. Such supplementary adjustments to EBITDA may not be in accordance with current SEC practice or with regulations adopted by the SEC that apply to registration statements filed under the Securities Act and periodic reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Accordingly, the SEC may require that Adjusted EBITDA (excluding Oncor Electric Delivery) and Adjusted EBITDA be presented differently in filings made with the SEC than as presented in this Current Report on Form 8-K, or not be presented at all.

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Set forth below is a reconciliation of net income to EBITDA and Adjusted EBITDA.

	Historical															Pro Forma Twelve Months Ended June 30, 2007
	Year Ended December 31,									Six Months Ended June 30,
	2004			2005			2006			2006			2007
	(millions of dollars)
Net income (loss)	$	485		$	1,722		$	2,552		$	1,073		$	(377	)	$	(1,002	)
Provision for income taxes		42			632			1,263			561			(294	)		(726	)
Interest expense and related charges		695			802			830			431			418			3,574
Depreciation and amortization		760			776			830			413			403			1,169
EBITDA	$	1,982		$	3,932		$	5,475		$	2,478		$	150		$	3,015
Oncor Electric Delivery EBITDA	$	(1,057	)	$	(1,241	)	$	(1,276	)	$	(597	)	$	(602	)	$	(1,281	)
Oncor Electric Delivery dividends		—			—			340			170			176			346
Interest income		(28	)		(48	)		(46	)		(20	)		(35	)		(60	)
Amortization of nuclear fuel		64			60			65			31			30			135
Purchase accounting adjustments		—			—			—			—			—			61
Impairment of assets and inventory write down		192			11			204			201			795			798
Unrealized net (gains) or losses resulting from hedging obligations		109			18			(272	)		(29	)		1,182			939
One-time customer appreciation bonus		—			—			165			—			—			165
Amount of loss on sales of accounts receivable and related assets in connection with the existing receivables facility		18			24			38			17			18			39
Income from discontinued operations, net of tax		(378	)		(5	)		(87	)		(60	)		(11	)		(38	)
Extraordinary (gain) loss, net of tax		—			50			—			—			—			—
Cumulative effect of changes in accounting principles, net of tax		(8	)		8			—			—			—			—
Non-cash compensation expenses (FAS 123R)		48			24			23			7			13			29
Severance expenses(1)		112			—			17			9			—			8
Equity losses of unconsolidated affiliate engaged in broadband over power lines		—			—			14			7			1			7
Losses on early extinguishment of debt and energy services contract		416			(4	)		1			1			—			—
Transition and business optimization costs(2)		10			17			—			—			12			12
Shareholder litigation charges (credit)		86			(35	)		(15	)		—			—			(15	)
Transaction and merger expenses(3)		—			—			28			5			77			100
Restructuring and other(4)		271			(6	)		(7	)		(12	)		5			10
Expenses incurred to upgrade or expand generation units(5)		6			6			4			3			4			5
Adjusted EBITDA (excluding Oncor Electric Delivery)(6)	$	1,843		$	2,811		$	4,671		$	2,211		$	1,815		$	4,275
Add back Oncor Electric Delivery adjustments	$	1,099		$	1,255		$	956		$	435		$	439		$	960
Adjusted EBITDA(7)	$	2,942		$	4,066		$	5,627		$	2,646		$	2,254		$	5,235

(1) Severance includes amounts incurred related to outsourcing, restructuring and other amounts deemed to be in excess of normal recurring amounts.

(2) Transition and business optimization costs include amounts related to outsourcing initiatives and system implementations.

(3) Transaction and merger expenses include costs incurred related to abandoned strategic transactions, new growth initiatives and merger expenses.

(4) Restructuring and other include charges and credits related to restructuring initiatives and other non-recurring activities.

(5) Expenses incurred to upgrade or expand a facility does not include costs incurred to purchase replacement power that should be included under the definition as we did not historically track these costs.

(6) Calculated pursuant to the terms of the EFH Senior Interim Facility, in particular the debt incurrence covenant. Excludes Oncor Electric Delivery’s EBITDA, except to the extent dividends are received from Oncor Electric Delivery.

(7) Calculated pursuant to the terms of the EFH Senior Interim Facility, in particular the restricted payments covenant. Includes Oncor Electric Delivery’s EBITDA.

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(e) Calculated pursuant to the terms of the EFH Senior Interim Facility, in particular the restricted payments covenant.

(f) Total interest expense includes cash interest plus amounts related to the amortization of discounts and premiums and amortization of deferred financing costs.

(g) Net debt is debt less cash and cash equivalents.

(h) Calculated pursuant to the terms of the EFH Senior Interim Facility, in particular the debt incurrence covenant.

(i) Includes 585 MW representing nine combustion turbine units currently operated for an unaffiliated third party’s benefit.

(j) Represents Luminant Energy’s average wholesale sales price.

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RISK FACTORS

You should carefully consider the risk factors set forth below as well as the other information contained in this Current Report on Form 8-K. This Current Report on Form 8-K contains forward-looking statements that involve risks and uncertainties. Any of the following risks could materially and adversely affect our business, prospects, financial condition or results of operations. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial may also materially and adversely affect our business, prospects, financial condition or results of operations.

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Risks Relating to Our Businesses

Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the future impact, our business and/or results of operations.

Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in the generation and sale of electricity. We will need to continually adapt to these changes. For example, the Texas retail electricity market became competitive as of January 1, 2002, and the introduction of competition has resulted in, and may continue to result in, declines in customer counts and sales volumes.

Our businesses are subject to changes in state and federal laws (including the Public Utility Regulatory Act (“PURA”), the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act and the Energy Policy Act of 2005) and changing governmental policy and regulatory actions (including those of the PUCT, the Electric Reliability Organization, the Texas Regional Entity, the Texas Railroad Commission, the TCEQ, the FERC, the EPA and the NRC) and also the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, construction and operation of transmission facilities, acquisition, disposal, depreciation and amortization of regulated assets and facilities, recovery of costs and investments, decommissioning costs, return on invested capital for our regulated businesses, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT, and, with respect to its wholesale power sales outside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. Changes in, revisions to, or reinterpretations of existing laws and regulations (particularly with respect to prices at which TCEH may sell electricity) may have an adverse effect on our businesses.

Although the recently concluded 2007 Texas Legislative Session closed without passage of legislation that significantly negatively impacted our businesses, the legislature did adopt legislation that likely requires prior PUCT approval for any future direct or indirect disposition of Oncor Electric Delivery, and ensures that the PUCT will have authority to enforce commitments made in a filing under PURA Section 14.101 (such as the filing made by Texas Holdings and Oncor Electric Delivery on April 25, 2007). Several pieces of legislation were introduced that, if passed, may have had a material impact on us and our financial prospects, including, for example, legislation that would have:

• required Energy Future Holdings Corp. to separate its subsidiaries into two or three stand-alone companies, which could have resulted in a significant tax cost to Energy Future Holdings Corp. or the sale by Energy Future Holdings Corp. of assets for an amount it would not have considered to be full value;

• required divestiture of significant wholesale power generation assets, which also could have resulted in a significant tax cost to Energy Future Holdings Corp. or the sale by Energy Future Holdings Corp. of assets for an amount it would not have considered to be full value; and

• given new authority to the PUCT to cap retail electric prices.

Although none of this legislation was passed, there can be no assurance that future action of the Texas Legislature, which could be similar or different from the proposals considered by the most recent Texas

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Legislature, will not have a material adverse effect on us and our financial prospects. In addition, the Sponsors have publicly indicated their intention to:

• spend more than $30 million per year over five years to provide relief for low-income residents and to pursue new demand side management initiatives in conservation, energy efficiency and weatherization;

• in the current regulatory system, hold a majority of their ownership in Energy Future Holdings Corp. for more than five years after closing of the Merger; and

• invest significant resources in emerging energy technologies, such as integrated gasification combined cycle coal plants, including an increased commitment to renewable energy.

Litigation or legal proceedings could expose us to significant liabilities, damage our reputation and have a material adverse effect on our results of operations, and the litigation environment in which we operate poses a significant risk to our businesses.

We and our subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, environmental and injuries and damages issues, among other matters. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these assessments and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These assessments and estimates are based on the information available to management at the time and involve a significant amount of management judgment. Actual outcomes or losses may differ materially from current assessments and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on our results of operations. For more information on legal proceedings, see “Business—Legal Proceedings.”

In addition, judges and juries in the state of Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage and business tort cases. We and our subsidiaries use legal and appropriate means to contest litigation threatened or filed against us, but the litigation environment in the state of Texas poses a significant business risk.

We are also exposed to the risk that we may become the subject of regulatory investigations. For example, in March 2007, the PUCT issued a Notice of Violation (“NOV”) stating that the PUCT Staff is recommending an enforcement action, including the assessment of administrative penalties, against us for alleged market power abuse in ERCOT–administered balancing energy auctions during certain periods of the summer of 2005. The PUCT Staff issued a revised NOV in September 2007, in which the proposed administrative penalty amount was reduced from $210 million to $171 million. The revised NOV was necessary, according to the PUCT Staff, to correct calculation errors in the initial NOV. As revised, the NOV is premised upon the PUCT Staff’s allegation that Luminant Energy’s bidding behavior was not competitive and increased market participants’ costs of balancing energy by approximately $57 million, including approximately $19 million in incremental revenues to us. A hearing requested by Luminant Energy to contest the alleged occurrence of a violation and the amount of the penalty in the NOV has been scheduled to start in April 2008. While we believe no market power abuse was committed, we are unable to predict the outcome of this matter.

TXU Energy may lose a significant number of retail customers in its historical service territory due to competitive marketing activity by retail electric providers and face competition from incumbent providers outside its historical service territory.

TXU Energy faces competition for customers within the service territory where we are the incumbent utility company, which we refer to as our historical service territory. Competitors may offer lower prices and other incentives, which, despite TXU Energy’s long-standing relationship with customers, may attract customers away from TXU Energy.

In most retail electric markets outside our historical service territory, TXU Energy’s principal competitor may be the retail affiliate of the local incumbent utility company. The incumbent retail affiliates have the advantage of long-standing relationships with their customers, including well-known brand recognition.

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In addition to competition from the incumbent utilities and their affiliates, TXU Energy may face competition in all of our service territories from a number of other energy service providers, or other energy industry participants, who may develop businesses that will compete with TXU Energy and nationally branded providers of consumer products and services. Some of these competitors or potential competitors may be larger or better capitalized than TXU Energy. If there is inadequate potential margin in these retail electric markets, it may not be profitable for TXU Energy to compete in these markets.

Our revenues and results of operations may be negatively impacted by decreases in market prices for power, decreases in natural gas prices, and/or decreases in market heat rates.

We are not guaranteed any rate of return on our capital investments in our competitive businesses. We market and trade electricity and natural gas, including electricity from our own generation facilities and generation contracted from third parties, as part of our wholesale markets management operation. Our results of operations depend in large part upon market prices for electricity, natural gas, lignite, uranium and coal in our regional market and other competitive markets and upon prevailing retail electricity rates, which may be impacted by actions of regulatory authorities. The prices we receive for the sale of electricity at wholesale could be impacted by the voluntary mitigation plan adopted by the PUCT. The voluntary mitigation plan is intended to be in place for one year, though it could be renewed or modified in a subsequent proceeding. Market prices may fluctuate substantially over relatively short periods of time. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, at times there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets. For example, as a result of Hurricane Katrina, such pressures in September and October of 2005 played a role in TXU Energy’s decision to moderate the implementation of a price increase in November and December 2005 and to voluntarily forego an increase in its price-to-beat retail price from January 1, 2006 through April 1, 2006. Further, TXU Energy has agreed to grant price discounts in connection with the Merger and provide price protection through December 2008.

Some of the fuel for Luminant’s generation facilities is purchased under short-term contracts or on the spot market. Prices of fuel, including natural gas, may also be volatile, and the price we can obtain for electricity sales may not change at the same rate as changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect our costs incurred in meeting our obligations.

Volatility in market prices for fuel and electricity may result from the following:

• severe or unexpected weather conditions;

• seasonality;

• changes in electricity and fuel usage;

• illiquidity in the wholesale power or other markets;

• transmission or transportation constraints, inoperability or inefficiencies;

• availability of competitively-priced alternative energy sources;

• changes in supply and demand for energy commodities, including nuclear fuel and related enrichment and conversion services;

• changes in generation efficiency and market heat rates;

• outages at our generation facilities or those of our competitors;

• changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;

• natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events; and

• federal, state and local energy, environmental and other regulation and legislation.

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All of Luminant’s generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market generally correlate with the price of natural gas because marginal demand is generally supplied by natural gas-fueled generation plants. Wholesale electricity prices also correlate with market heat rates (a measure of efficiency of the marginal price-setting generator of electricity), which could fall if demand for electricity were to decrease or if additional generation facilities are built in ERCOT. Accordingly, the contribution to earnings and the value of Luminant’s baseload (lignite/coal-fueled and nuclear) generation assets, which provided a substantial portion of our supply volumes in 2006, are dependent in significant part upon the price of natural gas and market heat rates. As a result, Luminant’s baseload generation assets could significantly decrease in profitability and value if natural gas prices fall or if market heat rates fall.

Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and our hedging transactions may not work as planned or hedge counterparties may default on their obligations to us.

We cannot fully hedge the risk associated with changes in natural gas prices or market heat rates because of the expected useful life of our generation assets and the size of our position relative to market liquidity. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations and financial position, either favorably or unfavorably.

To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of our purchase and sale commitments, weather positions, fuel requirements and inventories of natural gas, lignite, coal, crude oil and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Although we devote a considerable amount of management time and effort to the establishment of risk management procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place may not be followed or may not always function as planned and cannot eliminate all the risks associated with these activities. As a result of these and other factors, we cannot precisely predict the impact that risk management decisions may have on our business, results of operations or financial position.

To the extent we engage in hedging and risk management activities, we are exposed to the risk that counterparties that owe us money, energy or other commodities as a result of market transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. In such event, we might incur losses in addition to amounts, if any, already paid to the counterparties. ERCOT market participants are also exposed to risks that another ERCOT market participant may default in its obligations to pay ERCOT for power taken, in which case such costs, to the extent not offset by posted security and other protections available to ERCOT, may be allocated to various non-defaulting ERCOT market participants, including us.

In connection with its affiliates’ hedging and risk management activities, TCEH has guaranteed or indemnified the performance of a portion of its affiliates’ obligations relating to such activities. TCEH might not be able to satisfy all of these guarantees and indemnification obligations if they were to come due at the same time. In addition, reductions in credit quality or changes in the market prices of energy commodities could increase the cash collateral required to be posted in connection with hedging and risk management activities, which could materially impact our liquidity and financial position.

We may suffer material losses, costs and liabilities due to Luminant’s ownership and operation of the Comanche Peak nuclear generation plant.

The ownership and operation of a nuclear generation plant involves certain risks. These risks include:

• unscheduled outages or unexpected costs due to equipment, mechanical, structural or other problems;

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• inadequacy or lapses in maintenance protocols;

• the impairment of reactor operation and safety systems due to human error;

• the costs of storage, handling and disposal of nuclear materials;

• the costs of procuring nuclear fuel;

• the costs of securing the plant against possible terrorist attacks;

• limitations on the amounts and types of insurance coverage commercially available; and

• uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives.

The prolonged unavailability of Comanche Peak could materially affect our financial condition and results of operations, particularly when the cost to produce power at Comanche Peak is significantly less than market wholesale power prices. The following are among the more significant of these risks:

• Operational Risk—Operations at any nuclear generation plant could degrade to the point where the plant would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation plant could cause regulators to require a shut-down or reduced availability at Comanche Peak.

• Regulatory Risk—The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, the NRC operating licenses for Comanche Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

• Nuclear Accident Risk—Although the safety record of Comanche Peak and other nuclear generation plants generally has been very good, accidents and other unforeseen problems have occurred both in the United States and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impact and property damage. Any accident, or perceived accident, could subject us to significant liabilities and damage our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage.

The operation and maintenance of electricity generation and delivery facilities involves significant risks that could adversely affect our results of operations and financial condition.

The operation and maintenance of electricity generation and delivery facilities involves many risks, including, as applicable, start-up risks, breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in lost revenues and/or increased expenses. A significant number of Luminant’s facilities were constructed many years ago. In particular, older generating equipment and transmission and distribution equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive market, (b) any unexpected failure to generate electricity, including failure caused by breakdown or forced outage and (c) damage to facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events. Further, our ability to successfully and timely complete capital improvements

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to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs and/or the write-off of our investment in the project or improvement.

Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses, including the cost of replacement power. Likewise, our ability to obtain insurance, and the cost of and coverage provided by such insurance, could be affected by events outside our control.

Our cost of compliance with environmental laws and regulations and our commitments, and the cost of compliance with new environmental laws, regulations or commitments could materially adversely affect our results of operations and financial condition.

We are subject to extensive environmental regulation by governmental authorities. In operating our facilities, we are required to comply with numerous environmental laws and regulations and to obtain numerous governmental permits. We may incur significant additional costs beyond those currently contemplated to comply with these requirements. If we fail to comply with these requirements, we could be subject to civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions.

In conjunction with the building of three new generation units, we have committed to reduce emissions of mercury, nitrogen oxide (“NO_X”) and sulfur dioxide (“SO2”) associated with our baseload generation units so that the total of these emissions from both existing and new lignite coal-fueled units are 20% below 2005 levels. We may incur significantly greater costs than those contemplated in order to achieve this commitment. We may also make new environmental commitments and incur significant additional costs in order to achieve such commitments.

We will put in place a Sustainable Energy Advisory Board that will focus on assisting us in pursuing technology development opportunities that, among other things, are designed to reduce our impact on the environment. We may incur significant costs in addition to the costs referenced above as we pursue these opportunities.

We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain, maintain or comply with any such approval, the operation of our facilities could be stopped, curtailed or modified or become subject to additional costs.

In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that we have acquired, leased or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or fail to meet its indemnification obligations to us.

Increasing attention to potential environmental effects of “greenhouse” gas emissions may result in new regulation and restrictions on emissions of certain gasses that may be contributing to warming the earth’s atmosphere. Several bills addressing climate change have been introduced in the U.S. Congress and, in April 2007, the U.S. Supreme Court issued a decision ruling the EPA improperly declined to address carbon dioxide impacts in a rulemaking related to new motor vehicle emissions. While this decision is not directly applicable to power plant emissions, the reasoning of the decision could affect other regulatory programs. The impact on us of any future greenhouse gas legislation or other regulation will depend in large part on the details of the requirements and the timetable for mandatory compliance. Although we continue to assess the financial and operational risks posed by possible future legislative changes pertaining to greenhouse gas emissions, we are currently unable to predict any future impact on our financial condition and operations.

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The rates of Oncor Electric Delivery’s electric delivery business are subject to regulatory review.

The rates charged by Oncor Electric Delivery are regulated by the PUCT and certain cities and are subject to cost-of-service regulation and annual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Oncor Electric Delivery’s rates are regulated based on an analysis of Oncor Electric Delivery’s costs and capital structure, as reviewed and approved in a regulatory proceeding. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCT will judge all of Oncor Electric Delivery’s costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure that Oncor Electric Delivery’s rates are based upon or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of Oncor Electric Delivery’s costs, including regulatory assets reported in the balance sheet, and the return on invested capital allowed by the PUCT. The PUCT may reduce Oncor Electric Delivery’s rates to the extent the PUCT finds in a proceeding related to the Merger that the Merger is not in the public interest and disallow the effect of the Merger on rates if the PUCT finds that Merger will unreasonably affect Oncor Electric Delivery’s sales or service. The PUCT is currently reviewing the report of the Merger filed by Oncor Electric Delivery and Texas Holdings in a contested proceeding. Several of the parties to this proceeding, including Oncor Electric Delivery and the PUCT staff, have agreed on the terms of a settlement; however, a hearing on the merits to consider this non-unanimous settlement has been scheduled for December 12-13, 2007.

In 2004, certain cities within our historical service territory, acting in their role as a regulatory authority (with original jurisdiction), initiated inquiries to determine if Oncor Electric Delivery’s PUCT-established rates were just and reasonable. Oncor Electric Delivery has entered into settlements deferring rate action, but Oncor Electric Delivery will be required to file a rate case in 2008, based on a 2007 test year, unless Oncor Electric Delivery and the cities mutually agree that such a filing is unnecessary.

At the request of the PUCT, the PUCT Staff filed a petition in March 2007 requesting that the PUCT order Oncor Electric Delivery to file a rate case based on a test year ending December 31, 2006. PUCT Staff stated that it would be advantageous to review Oncor Electric Delivery’s costs prior to major ownership and organizational changes that are expected as a result of the Merger in order to establish a baseline from which to assess any cost changes resulting from the announced changes. In April 2007, the PUCT issued an order requiring Oncor Electric Delivery to file a rate case based on a test year ending December 31, 2006. On August 28, 2007, Oncor Electric Delivery made the required filing, and the filing supports a rate increase of approximately $85 million over current rates subject to the original jurisdiction of the PUCT. However, Oncor Electric Delivery requested that the PUCT enter an order abating the proceeding, except that the PUCT convene a technical conference to consider a final order in this Docket No. 34040 that would include the following provisions: (i) the PUCT will take “no action” on Oncor Electric Delivery’s proposed rate filing package and will enter an order confirming that Oncor Electric Delivery’s current rates will remain in effect until otherwise changed by a final order of the PUCT or other appropriate jurisdictional authority; (ii) Oncor Electric Delivery will be required to file a system-wide rate case with the Settlement Agreement between Oncor Electric Delivery and certain cities in its service territory; (iii) Oncor Electric Delivery will be required to file an Earnings Monitor Report (“EMR”) with the PUCT no later than March 15, 2008, for the calendar year 2007, and no later than March 15, 2009, for calendar year 2008, notwithstanding the pendency at the PUCT of this or any other Oncor Electric Delivery rate case; and (iv) the PUCT will enter an accounting order, or similar directive, providing that if Oncor Electric Delivery’s 2008 or 2009 EMR filings demonstrate that Oncor Electric Delivery earned more than 10.75% return on equity (“ROE”) during the relevant period covered by the EMR filing, on a weather normalized basis, Oncor Electric Delivery will record a credit to the underrecovery balance in its insurance reserve, such that the additional expense would result in Oncor Electric Delivery’s ROE for the relevant period being no higher than 10.75%. Many of the parties to this rate case have agreed to a settlement of this proceeding in conjunction with the settlement of the proceeding concerning the PUCT’s review of the Merger described above. A hearing on the merits to consider that non-unanimous settlement has been scheduled for December 12-13, 2007. We cannot predict the outcome of that hearing.

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Because the PUCT has original jurisdiction over only transmission rates and the distribution rates charged in unincorporated areas and within cities that have ceded original jurisdiction to the PUCT, Oncor Electric Delivery estimates that approximately one-third of its operating revenues may be subject to change in this rate proceeding.

While we believe Oncor Electric Delivery’s rates are just and reasonable, we cannot predict the results of any rate case.

Our growth strategy, including our investment in three new lignite coal-fueled generation facilities, may not be executed as planned which could adversely impact our financial condition and results of operations.

There can be no guarantee that the execution of our growth strategy will be successful. As discussed below, our growth strategy is dependent upon many factors. Changes in laws, regulations, markets, costs or other factors could negatively impact the execution of our growth strategy, including causing management to change the strategy. Even if we are able to execute our growth strategy, it may take longer than expected and costs may be higher than expected.

With respect to Luminant Construction’s lignite coal-fueled generation development program, there can be no guarantee that the execution of the program will be successful. While Luminant Construction has experience in operating lignite coal-fueled generation facilities, it has limited experience in developing and constructing such facilities. To the extent construction is not managed efficiently and to a timely conclusion, cost overruns may occur resulting in the overall program costing significantly more than anticipated. This may also result in delays in the expected online dates for the facilities resulting in less overall income than projected. While Luminant Construction believes it can acquire the resources needed to effectively execute this program, it is exposed to the risk that it may not be able to attract and retain skilled labor, at projected rates, for developing and constructing these new facilities.

Luminant Construction’s lignite coal-fueled generation development program is subject to changes in laws, regulations and policies that are beyond its control. Changes in law, regulation or policy regarding commodity prices, power prices, electric competition or solid-fuel generation facilities or other related matters could adversely impact this program. In recent months, global warming has received significant media attention, which has resulted in legislators focusing on environmental laws, regulations and policies. Changes in any environmental law, regulation or policy, such as regulations of emissions of carbon dioxide, could adversely impact this program.

Luminant Construction’s lignite coal-fueled generation development program is subject to changes in the electricity market, primarily ERCOT for its new build program in Texas, that are beyond its control. If demand growth is less than expected or if other generation companies build new generation assets in ERCOT, Luminant Construction’s program could impact market prices of power such that the new generation capacity becomes uneconomical. In addition, any unanticipated reduction in wholesale electricity prices, market heat rates and natural gas prices, which could occur for a variety of reasons, could adversely impact this program. Even if Luminant Construction enters into hedges to reduce such exposures, it would still be subject to the credit risk of its counterparties.

Luminant Construction’s lignite coal-fueled generation development program is subject to other risks that are beyond its control. For example, Luminant Construction is exposed to the risk that a change in technology for electricity generation facilities and/or emissions control technologies may make other generation facilities less costly and more attractive than Luminant Construction’s new lignite coal-fueled generation facilities. Luminant Construction is subject to risks relating to transmission capabilities and constraints. Luminant Construction is also exposed to the risk that its contractors may default on their obligations to Luminant Construction and compensation for damages received, if any, will not cover its losses.

With respect to Oncor Electric Delivery’s capital deployment program for its electric delivery facilities, there can be no guarantee that the execution of such program will be successful. There can be no assurance that

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the capital investments Oncor Electric Delivery intends to make in connection with its electric delivery business will produce the desired reductions in cost and improvements to service and reliability.

TXU Energy’s retail business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or the results of operations of the retail business.

TXU Energy’s retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank account information. TXU Energy’s retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. If a significant or widely publicized breach occurred, the reputation of TXU Energy’s retail business may be adversely affected, customer confidence may be diminished, or TXU Energy’s retail business may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and/or results of operations of the retail business.

Ongoing performance improvement initiatives may not achieve desired cost reductions and may instead result in significant additional costs if unsuccessful.

The implementation of performance improvement initiatives identified by management may not produce the desired reduction in costs and may result in disruptions arising from employee displacements and the rapid pace of changes to organizational structure and operating practices and processes. Specifically, we are subject to the risk that the joint venture outsourcing arrangement with Capgemini Energy LP (“Capgemini”), a subsidiary of Cap Gemini North America Inc., that provides business support services to us or other similar arrangements may not produce the desired cost savings. Should we wish to terminate or modify the arrangements with Capgemini or other providers, or if Capgemini or those other providers become financially unable to perform their obligations, we would incur transition costs, which would likely be significant, to switch to another vendor.

TXU Energy relies on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, its customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material negative impact on its business and results of operations.

TXU Energy depends on transmission and distribution facilities owned and operated by unaffiliated utilities, as well as Oncor Electric Delivery’s facilities, to deliver the electricity it sells to its customers. If transmission capacity is inadequate, TXU Energy’s ability to sell and deliver electricity may be hindered, it may have to forgo sales or it may have to buy more expensive wholesale electricity than is available in the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where TXU Energy has a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower profits. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to TXU Energy’s customers could negatively impact the satisfaction of its customers with its service.

TXU Energy offers bundled services to its retail customers, with some bundled services offered at fixed prices and for fixed terms. If TXU Energy’s costs for these bundled services exceed the prices paid by its customers, TXU Energy’s results of operations could be materially adversely affected.

TXU Energy offers its customers a bundle of services that include, at a minimum, electricity plus transmission, distribution and related services. The prices TXU Energy charges for its bundle of services or for the various components of the bundle, any of which may be fixed by contract with the customer for a period of time, could fall below TXU Energy’s underlying cost to provide the components.

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TXU Energy’s retail business is subject to the risk that it will not be able to profitably serve its customers given the announced price protection and price cuts, which could result in an adverse impact to its reputation and/or results of operations of TXU Energy’s retail business.

In connection with the Merger, TXU Energy announced a 15% price reduction for residential customers in its historical service territory who have not already switched to one of the many pricing plans other than the basic month-to-month plan. These customers received a six percent reduction beginning in late March 2007, an additional four percent reduction in June 2007 and an additional five percent reduction in October 2007. In addition, TXU Energy announced that it will provide price protection for these customers through December 2008, ensuring that these customers receive the benefits of these savings through two summer seasons of peak energy usage. The prices TXU Energy charges during this period could fall below TXU Energy’s underlying cost to provide electricity.

Although the PUCT does not have the right to approve the REP certification pursuant to the Merger, the PUCT may at anytime initiate an investigation into whether TXU Energy has met all of the requirements for REP certification including financial requirements, so that it can maintain its REP certification. Any removal or revocation of a REP certification would mean that TCEH or TXU Energy, as applicable, would no longer be allowed to provide electric service to retail customers.

Changes in technology may reduce the value of Luminant’s generation plants and/or Oncor Electric Delivery’s electric delivery facilities and may significantly impact our business in other ways as well.

Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines and photovoltaic (solar) cells. It is possible that advances in these or other technologies will reduce the costs of electricity production from these technologies to a level that will enable these technologies to compete effectively with the traditional generation plants owned by Luminant. While demand for electric energy services is generally increasing throughout the United States, the rate of construction and development of new, more efficient generation facilities may exceed increases in demand in some regional electric markets. Consequently, where we have facilities, the profitability and market value of Luminant’s generation assets could be significantly reduced. Also, electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewise significantly reduce the value of Luminant’s generation assets and Oncor Electric Delivery’s electric delivery facilities. Changes in technology could also alter the channels through which retail electric customers buy electricity. To the extent self-generation facilities become a more cost-effective option for certain customers, our revenues could be reduced.

Our future results of operations may be negatively impacted by settlement adjustments determined by ERCOT related to prior periods.

ERCOT is the independent system operator that is responsible for maintaining reliable operation of the bulk electric power supply system in the ERCOT market. Its responsibilities include the clearing and settlement of electricity volumes and related ancillary services among the various participants in the deregulated Texas market. Settlement information is due from ERCOT within two months after the operating day, and true-up settlements are due from ERCOT within six months after the operating day. As a result, we are subject to settlement adjustments from ERCOT related to prior periods, which may result in charges or credits impacting our future reported results of operations.

Our results of operations and financial condition could be negatively impacted by any development or event beyond our control that causes economic weakness in the ERCOT market.

We derive substantially all of our revenues from our operations in the ERCOT market, which covers approximately 75% of the geographical area in the state of Texas. As a result, regardless of the state of the economy in areas outside the ERCOT market, economic weakness in the ERCOT market could lead to reduced

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demand for electricity in the ERCOT market. Such a reduction could have a material negative impact on our results of operations and financial condition.

Our (or an applicable subsidiary’s) credit ratings could negatively affect our (or the pertinent subsidiary’s) ability to access capital and could require us or our subsidiaries to post collateral or repay certain indebtedness.

Downgrades in our or any of our subsidiaries’ long-term debt ratings generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease and might trigger liquidity demands pursuant to the terms of a number of commodity contracts, leases and other agreements. On October 8, 2007, Fitch Ratings downgraded our long term debt ratings and on October 9, 2007, both Moody’s Investors Services, Inc. and Standard & Poor’s Ratings Services, a division of the McGraw Hill Companies, also downgraded our long term debt ratings.

Most of our large customers, suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions with us. As our (or an applicable subsidiary’s) credit ratings decline, the costs to operate our business will likely increase because counterparties may require the posting of collateral in the form of cash-related instruments, or counterparties may decline to do business with us.

In addition, in connection with the Merger, Oncor Electric Delivery has committed to the PUCT that it will, in its 2007 and 2008 rate cases, support a cost of debt that does not exceed its actual cost of debt immediately prior to the announcement of the Merger. As such, in connection with these rate cases, in certain circumstances Oncor Electric Delivery may not be able to recover additional debt costs caused by a credit rating downgrade.

Our liquidity needs could be difficult to satisfy under some circumstances, particularly during times of uncertainty in the financial markets and/or during times when there are significant increases in natural gas prices. The inability to access liquidity, particularly on favorable terms, could materially adversely affect our results of operations and/or financial condition.

Our businesses are capital intensive. We and our subsidiaries rely on access to financial markets as a significant source of liquidity for capital requirements not satisfied by cash-on-hand or operating cash flows. The inability to raise capital on favorable terms, particularly during times of uncertainty in the financial markets similar to that which is currently being experienced in the financial markets, could impact our ability to sustain and grow our businesses and would likely increase capital costs. Our access to the financial markets could be adversely impacted by various factors, such as:

• changes in financial markets that reduce available credit or the ability to obtain or renew liquidity facilities on acceptable terms;

• economic weakness in the ERCOT market;

• changes in interest rates;

• a deterioration of our credit or the credit of our subsidiaries or a reduction in our credit ratings or the credit ratings of our subsidiaries;

• volatility in commodity prices that increases margin or credit requirements;

• a material breakdown in our risk management procedures; and

• the occurrence of material adverse changes in our businesses that restrict our ability to access our liquidity facilities.

Although we expect to actively manage the liquidity exposure of existing and future hedging arrangements, given the size of our long-term hedging program, any significant increase in the price of natural gas could result in our subsidiaries being required to provide cash or letter of credit collateral in substantial amounts. In addition, any perceived reduction in our or one of our subsidiary’s credit quality could result in clearing agents or other counterparties requesting additional collateral.

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In addition, given the size of our long-term hedging program, any significant increase in the price of natural gas could result in our subsidiaries being required to provide cash or letter of credit collateral (i.e. margin) in very large amounts. In addition, any perceived reduction in our or one of our subsidiary’s credit quality could result in clearing agents or other counterparties requesting additional margin. In the event our liquidity facilities are being used largely to support our long-term hedging program as a result of a significant increase in the price of natural gas or significant reduction in credit quality, we and our subsidiaries may have to forego certain capital expenditures or other investments in our businesses or other business opportunities.

Further, a lack of available liquidity could adversely impact the evaluation of our and our subsidiaries’ creditworthiness by counterparties and rating agencies. In particular, such concerns by existing and potential counterparties could significantly limit TCEH’s wholesale markets activities, including its long-term hedging program.

The loss of the services of our key management and personnel could adversely affect our ability to operate our business.

Our future success will depend on our ability to continue to attract and retain other highly qualified personnel. We compete for such personnel with many other companies, in and outside our industry, government entities and other organizations. We may not be successful in retaining our current personnel or in hiring or retaining qualified personnel in the future. Additionally, the Merger may have a negative impact on our ability to attract and retain key management and other employees. Our failure to attract new personnel or retain our existing personnel could have a material adverse effect on our business.

Our future success depends, to a significant extent, on the abilities and efforts of our executive officers and other members of our management team. Energy Future Holdings Corp.’s chief executive officer resigned following the consummation of the Merger. We have not yet identified a successor to Energy Future Holdings Corp.’s chief executive officer. In addition, one or more of Energy Future Holdings Corp.’s other executive officers may elect to leave the company as a result of the Merger. Energy Future Holdings Corp.’s chief executive officer and other executive officers have substantial experience and expertise in our industry, which we have relied upon significantly. We cannot assure you that we will be able to attract and retain new members of management to replace Energy Future Holdings Corp.’s chief executive officer and any other executive officers that may leave. If we are not successful in doing so, our business may be adversely affected.

The Sponsors control us and may have conflicts of interest with us or you in the future.

The Sponsors indirectly own approximately 62% of our capital stock on a fully-diluted basis through their investment in Texas Holdings. As a result, the Sponsors have control over our decisions to enter into any corporate transaction and will have the ability to prevent any transaction that requires the approval of stockholders regardless of whether noteholders believe that any such transactions are in their own best interests. For example, the Sponsors could cause us to make acquisitions that increase the amount of indebtedness that is secured or that is senior to certain of our indebtedness or to sell assets, which may impair our ability to make payments under the notes.

Additionally, the Sponsors are in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. The Sponsors may also pursue acquisition opportunities that may be complementary to our business and, as a result, those acquisition opportunities may not be available to us. So long as the Sponsors, or other funds controlled by or associated with the Sponsors, continue to indirectly own a significant amount of the outstanding shares of our common stock, even if such amount is less than 50%, the Sponsors will continue to be able to strongly influence or effectively control our decisions.

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THE TRANSACTIONS

The Merger

On October 10, 2007, Merger Sub, Texas Holdings’ wholly owned subsidiary, acquired Energy Future Holdings Corp. through a merger of Merger Sub with and into Energy Future Holdings Corp. under the terms and conditions of the Merger Agreement. Upon the effectiveness of the Merger, each share of Energy Future Holdings Corp. common stock outstanding immediately prior to the Merger (other than shares held by us or any of Energy Future Holdings Corp.’s subsidiaries or Texas Holdings or any of its subsidiaries, including Merger Sub, in each case not held on behalf of third parties, or shares held by holders who properly exercised their rights of dissent and appraisal under Texas law) was cancelled and converted into the right to receive $69.25 in cash, without interest and less any applicable withholding taxes.

Equity Contributions

At the closing of the Merger, Texas Holdings received an aggregate equity investment of approximately $8.3 billion. Investment funds affiliated with the Sponsors, or their respective assignees, contributed approximately $5.1 billion to Texas Holdings. In addition, Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated, or their respective affiliates each made equity investments of approximately $250 million in Texas Holdings. The Sponsors obtained approximately $2.3 billion in equity investments from other existing investors in KKR’s and TPG’s private equity funds and other third party investors. Following the closing of the Merger, the Sponsors owned approximately 62% of the limited partnership units issued by Texas Holdings in connection with the Merger. In addition, investment funds affiliated with LBI contributed approximately $412 million in equity investments. LBI’s equity contribution represents slightly less than 5% of the limited partnership units issued by Texas Holdings in connection with the Merger.

Debt Financing

In connection with the Merger, in addition to the Equity Contributions described above, we entered into the EFH Senior Interim Facility and TCEH entered into the TCEH Senior Secured Facilities and the TCEH Senior Interim Facility, in each case, arranged by a consortium of arrangers and bookrunners (the “Arranger Group”).

Also, in connection with the Merger, the Receivables Program was amended, and the special purpose entities established by the third party financial institutions that participate in the Receivables Program requested that Oncor Electric Delivery repurchase the receivables that it had previously sold under the Receivables Program. Finally, Oncor Electric Delivery also entered into the Oncor Electric Delivery Revolving Facility with the Arranger Group.

EFH Senior Interim Facility

The borrowings under the $4.5 billion EFH Senior Interim Facility were used to finance the Merger. Energy Future Intermediate Holding and Energy Future Competitive Holdings are guarantors of amounts borrowed under the EFH Senior Interim Facility. It is expected that a portion of the EFH Senior Interim Facility will be repaid with new long-term borrowings.

TCEH Senior Secured Facilities

The TCEH Senior Secured Facilities are comprised of:

(i) the $16.45 billion TCEH Initial Term Loan Facility;

(ii) the $4.1 billion TCEH Delayed Draw Term Loan Facility;

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(iii) the $1.25 billion TCEH Letter of Credit Facility;

(iv) the $2.7 billion TCEH Revolving Facility, under which amounts are available (A) in the form of letters of credit and (B) for borrowings on same-day notice, referred to as the swingline loans; and

(v) the TCEH Commodity Collateral Posting Facility, the size of which is determined by the out-of-the-money mark-to-market exposure, inclusive of any unpaid settlement amounts, of TCEH and its subsidiaries on a hypothetical portfolio of certain commodity swaps and futures transactions.

The TCEH Senior Secured Facilities are guaranteed by Energy Future Competitive Holdings and subsidiaries of TCEH. The TCEH Initial Term Loan Facility was used to finance the Merger, redeem, refinance or repay certain existing indebtedness of Energy Future Holdings Corp. and its subsidiaries and to pay fees premiums and expenses incurred in connection with the Transactions (collectively, the “Merger Funds”). The TCEH Delayed Draw Term Loan Facility will be used by TCEH and its subsidiaries during the two-year period commencing on the closing date of the Merger to fund certain capital expenditures. The letters of credit under the TCEH Letter of Credit Facility will be used by TCEH and its subsidiaries for general corporate purposes. Borrowings under the TCEH Revolving Facility will be used by TCEH and its subsidiaries for working capital and for other general corporate purposes. The proceeds of drawings under the TCEH Commodity Collateral Posting Facility will be used to fund margin payments due on natural gas and commodity swaps and hedging arrangements, and to the extent not used for the above purposes, for other general corporate purposes of TCEH and its subsidiaries.

TCEH Senior Interim Facility

The borrowings under the $6.75 billion TCEH Senior Interim Facility were used to finance the Merger. The TCEH Senior Interim Facility is jointly and severally guaranteed by Energy Future Competitive Holdings and each subsidiary of TCEH that guarantees obligations under the TCEH Senior Secured Facilities. It is expected that a portion of the TCEH Senior Interim Facility will be repaid with new long-term borrowings.

Receivables Program

The Receivables Program, a commercial paper-backed accounts receivables securitization program, was amended in connection with the Merger.

Oncor Electric Delivery Revolving Facility

The Oncor Electric Delivery Revolving Facility is comprised of a senior revolving credit facility in an aggregate principal amount of up to $2.0 billion, of which borrowings are available (a) in the form of letters of credit and (b) for borrowings on same-day notice, referred to as the swingline loans. In addition, subject to the satisfaction of certain conditions, Oncor Electric Delivery may increase the commitments under the Oncor Electric Delivery Revolving Facility in an amount up to $500 million. The letters of credit and proceeds of borrowings under the Oncor Electric Delivery Revolving Facility will be used by Oncor Electric Delivery and its subsidiaries for working capital and for other general corporate purposes.

Ring-Fencing

Upon the consummation of the Merger, we and Oncor Electric Delivery implemented several measures that are referred to as “ring-fencing.” Such measures included the following:

• the transfer of Energy Future Holdings Corp.’s ownership of Oncor Electric Delivery to Oncor Electric Delivery Holdings, a newly-formed special purpose, bankruptcy remote subsidiary, and immediately thereafter the transfer of Energy Future Holdings Corp.’s ownership of Oncor Electric Delivery Holdings to a newly-formed, wholly owned subsidiary, Energy Future Intermediate Holding;

25

• the conversion of Oncor Electric Delivery from a Texas corporation to a Delaware limited liability company;

• the inclusion of covenants in Oncor Electric Delivery Holdings’ and Oncor Electric Delivery’s limited liability company agreements intended to enhance the separation of Oncor Electric Delivery Holdings and its subsidiaries, including Oncor Electric Delivery, from Texas Holdings and its other subsidiaries, including Energy Future Intermediate Holding;

• the establishment of boards of directors for Oncor Electric Delivery Holdings and Oncor Electric Delivery with a majority of members who meet the New York Stock Exchange requirements for independence in all material respects and whose unanimous consent will be required to take certain material actions, including (i) to consolidate or merge (A) with the Issuer or any of the Issuer’s other subsidiaries or (B) with any other entity, if Oncor Electric Delivery Holdings or Oncor Electric Delivery, as applicable, would not be the surviving entity; (ii) to sell, transfer or dispose of all or substantially all of the assets of Oncor Electric Delivery Holdings or Oncor Electric Delivery, as applicable, without adequate provision for the payment of all of such entity’s creditors; (iii) to institute, or consent to the institution of, bankruptcy or insolvency proceedings in respect of Oncor Electric Delivery Holdings or Oncor Electric Delivery, as applicable; or (iv) to the fullest extent permitted by law, to dissolve or liquidate Oncor Electric Delivery Holdings or Oncor Electric Delivery, as applicable, without adequate provision for the payment of all of such entity’s creditors;

• the specific delegation to each of the board of directors and the independent directors of Oncor Electric Delivery, each acting by majority vote, of the right to prevent distributions, if it or they determine that it is in the best interests of Oncor Electric Delivery to retain such amounts to meet expected future requirements;

• after the appointment of the initial independent directors, the delegation of the ability to nominate, appoint, and fill vacancies in respect of the independent directors of Oncor Electric Delivery and Oncor Electric Delivery Holdings to a standing nominating committee of Oncor Electric Delivery Holdings’ board, a majority of whose members are independent directors; and

• the incurrence of new indebtedness, evidenced by the Oncor Electric Delivery Revolving Facility, the lenders of which will be specifically relying on the separateness of Oncor Electric Delivery Holdings and Oncor Electric Delivery, and their assets, from Texas Holdings and its other subsidiaries.

The ring-fencing measures are based on certain principles articulated by rating agencies and certain commitments made by Texas Holdings and Oncor Electric Delivery to the PUCT and the FERC intended to further separate Oncor Electric Delivery from Texas Holdings and its subsidiaries and to mitigate Oncor Electric Delivery’s credit exposure to those entities and to reduce the risk that the assets and liabilities of Oncor Electric Delivery Holdings or of any of its subsidiaries would be substantively consolidated with the assets and liabilities of Texas Holdings or of any of its other subsidiaries in the event of a bankruptcy of one or more of those entities. A number of ring-fencing measures put in place are expected to be incorporated into a PUCT order that would be legally binding on Oncor Electric Delivery. See “Regulation and Rates—Oncor Electric Delivery—Report Filed with the PUCT Regarding Merger.”

The Transactions do not provide for new pledges or encumbrances of the assets of Oncor Electric Delivery for the benefit of the Issuer and its subsidiaries (other than the ring-fenced entities). Oncor Electric Delivery will not incur, guarantee or pledge assets in respect of any incremental new debt related to the Transactions. There is neither new debt issued by nor borrowing at Oncor Electric Delivery to finance the Transactions. None of the ring-fenced entities will guarantee or otherwise hold out its credit as being available to support the obligations of the Issuer or any of its subsidiaries (other than the ring-fenced entities). In addition, lenders under the EFH Senior Interim Facility, the TCEH Senior Interim Facility and the TCEH Senior Secured Facilities have acknowledged the legal separateness of Oncor

26

Electric Delivery and its subsidiaries from the borrowers and guarantors under such financing documents. Lenders under the EFH Senior Interim Facility, the TCEH Senior Interim Facility and the TCEH Senior Secured Facilities also agreed that they will not initiate any bankruptcy proceedings against Oncor Electric Delivery Holdings or its subsidiaries and that Oncor Electric Delivery Holdings and its subsidiaries are entitled to enforce this non-petition covenant.

Debt Repayment

Pursuant to the terms of the Merger Agreement, we commenced offers to purchase and consent solicitations with respect to the Specified Notes. In connection with the Merger, we have redeemed and repaid or expect to repay an aggregate of approximately $5.5 billion of existing indebtedness of the Issuer and its subsidiaries (including the Specified Notes, but excluding indebtedness of Oncor Electric Delivery), including debt that became payable upon the consummation of the Merger.

Payments under Existing Stock Incentive Plans in Connection with the Merger

Long-Term Incentive Plan (“LTIP”) Performance Awards

Energy Future Holdings Corp.’s LTIP performance awards were designed to provide incentives for Energy Future Holdings Corp. management, over a three-year period, linked to total shareholder return (“TSR,” which is stock price appreciation/depreciation plus dividends) as compared to the companies in the S&P 500 Electric Utility Index and/or the S&P Multi-Utilities Index, and, for certain awards, in part on an absolute TSR over the relevant performance period. As the Merger caused Energy Future Holdings Corp.’s common stock to cease to be publicly-traded, the Organization and Compensation Committee of the Board of Directors of Energy Future Holdings Corp. had decided to end the performance periods under outstanding LTIP awards upon consummation of the Merger and make performance calculations based on relative TSR performance and/or absolute TSR performance through the consummation of the Merger measured by the $69.25 per share merger consideration (with awards measured on absolute TSR performance adjusted for the duration of the performance period through the closing). The cash amounts payable were determined by taking the number of shares of common stock issuable based upon the performance calculations, multiplied by $69.25. The amounts payable have vested and are not subject to forfeiture, provided that with respect to certain of our executive officers the payment of the vested amount will occur on January 2, 2008. For all other employees, amounts payable in respect of outstanding LTIP awards were paid at the closing of the Merger.

On October 10, 2007, Texas Holdings entered into an agreement with each of Michael McCall, Charles Enze, James Burke and Michael Greene pursuant to which such employee agreed to defer receipt of certain amounts in respect of 2005, 2006, and 2007 LTIP awards to which each would otherwise have been entitled as a result of the consummation of the Merger. In lieu of receipt of such amounts, each of Messrs. McCall, Enze, Burke and Greene received $3,000,000, $1,000,000, $2,500,000 and $3,000,000, respectively, worth of shares of common stock of Energy Future Holdings Corp.

The calculation of payout values as of the consummation of the Merger is based on Energy Future Holdings Corp.’s TSR relative to the other companies in the peer group indices referred to above and the defined absolute performance standard, as would be the case if the transaction never occurred. Factors that impact the ultimate payout level include the time it took to close the Merger and the shareholder returns of the other companies in the peer group indices through the closing date of the Merger. The maximum payments for LTIP awards for all participants would be equivalent to approximately 5.6 million shares of Energy Future Holdings Corp.’s common stock. The actual payouts for 2005, 2006 and 2007 awards were equivalent to approximately 5.3 million shares.

27

Directors’ Deferred Stock Units

Upon consummation of the Merger, all share units previously earned under the TXU Deferred Compensation Plan for Outside Directors were paid out in cash in an amount equal to each of Energy Future Holdings Corp.’s director’s number of units held multiplied by $69.25. The aggregate number of share units held by the directors (including Dr. de Planque, who resigned on March 2, 2007) is 110,277 and the aggregate cash out value is approximately $8 million.

Trust Funding

Within 30 days after the consummation of the Merger, Energy Future Holdings Corp. will be obligated to (1) fully fund into a trust all of the unfunded obligations under the TXU Salary Deferral Program and the TXU Second Supplemental Retirement Plan and (2) fund a trust to pay for the premiums on the vested portion of the TXU Split Dollar Life Insurance Program until such time as the cash surrender value is sufficient to maintain the policy. Such funding is for the benefit of all participants in such plans (including our executive officers) and the aggregate trust funding for such benefits is expected to be approximately $14 million.

In addition, Energy Future Holdings Corp. funded into a trust all amounts payable in respect of LTIP awards which were not paid out at the consummation of the Merger. For this purpose, prior to the consummation of the Merger, Energy Future Holdings Corp. established an irrevocable rabbi trust and immediately prior to the consummation of the Merger funded such trust with the amounts payable in respect of such LTIP awards, including any anticipated accrued dividend. The trust is expected to have an independent trustee, such as a trust company, which will administer all amounts held in the trust. The trust document provides that any funds in the trust associated with 2005, 2006 and 2007 LTIP awards will be paid out on January 2, 2008. LTIP award participants with funds in this trust would receive, as of the date of the consummation of the Merger, a statement listing the amount of the funds to which he or she is entitled and the timing of payment.

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ENERGY FUTURE HOLDINGS CORP. UNAUDITED PRO FORMA

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We derived the unaudited pro forma condensed consolidated financial statements set forth herein by the application of pro forma adjustments to our historical consolidated financial statements.

The unaudited pro forma condensed consolidated balance sheet as of June 30, 2007 gives effect to (a) the Transactions and (b) the incurrence of debt and the application of the proceeds therefrom to repay amounts outstanding under the EFH Senior Interim Facility and the TCEH Senior Interim Facility, respectively (which is referred to as the “Interim Facility Refinancing”), as if the Transactions and the Interim Facility Refinancing had occurred on such date. The unaudited pro forma condensed consolidated income statements for the six months ended June 30, 2007, the six months ended June 30, 2006, the twelve months ended June 30, 2007 and the year ended December 31, 2006, give effect to the Transactions and the Interim Facility Refinancing as if the Transactions and Interim Facility Refinancing had occurred on January 1, 2006. The unaudited pro forma condensed consolidated financial statements are provided for informational purposes only and are not necessarily indicative of what our financial position or results of operations would have been if the Transactions and the Interim Facility Refinancing had occurred as of the dates indicated, or what our financial position or results of operations will be for any future periods. Assumptions underlying the pro forma adjustments are described in the accompanying notes, which should be read in conjunction with these unaudited pro forma condensed consolidated financial statements and with the following information:

• unaudited condensed consolidated financial statements and accompanying notes of Energy Future Holdings Corp. as of June 30, 2007 and for the three- and six-month periods ended June 30, 2007 and 2006 in this Current Report on Form 8-K;

• audited consolidated financial statements and accompanying notes of Energy Future Holdings Corp. as of December 31, 2006 and 2005 and for each of the three years ended December 31, 2006 in this Current Report on Form 8-K; and

• “The Transactions” and “Energy Future Holdings Corp. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The Merger will be accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS No. 141. For purposes of the Merger, Energy Future Holdings Corp. is the acquired entity. Accordingly, we have adjusted the historical financial information of Energy Future Holdings Corp. to give effect to the impact of the consideration paid in connection with the Merger. In the Unaudited Condensed Consolidated Pro Forma Balance Sheet, Texas Holdings’ cost to acquire Energy Future Holdings Corp. has been allocated to the assets to be acquired and liabilities to be assumed based on management’s preliminary valuation estimates. For purposes of developing pro forma adjustments, we assumed that the historical values of current assets acquired and current liabilities assumed approximate their fair values, which may change as a result of fair valuation of certain of our assets, including intangible assets and liabilities. A final determination of the purchase accounting adjustments, including the allocation of the purchase price to the assets acquired and liabilities assumed based on their respective fair values, will not occur until the final determinations of fair values have been made. Accordingly, the purchase accounting adjustments with respect to the Merger made in connection with the development of these unaudited pro forma condensed consolidated financial statements are preliminary and have been made solely for purposes of developing such pro forma financial data. Therefore, final purchase accounting adjustments are subject to revisions based on final determinations of fair values following the close of the Merger, which may differ materially from the values used herein and may cause future results of operations to differ from the pro forma financial data presented.

29

These unaudited pro forma condensed consolidated financial statements do not reflect any pro forma adjustments related to Oncor Electric Delivery and its subsidiary’s regulated operations that are accounted for under SFAS No. 71, which are comprised of the transmission and distribution operations of Oncor Electric Delivery with the exception of items related to the proposed PUCT settlement in connection with the Merger. Under the regulated rate setting process and mandated recovery provisions set by the PUCT, the fair value of Oncor Electric Delivery’s assets and liabilities are estimated by their approximate carrying values. The estimated fair value of the assets and liabilities of these operations are materially affected by the current rate setting, and any future changes to, the rate structure set by the PUCT.

The impacts and adjustments in these unaudited pro forma condensed consolidated financial statements are based on events directly related to the Transactions and the Interim Facility Refinancing and do not represent projections or forward-looking statements. The unaudited pro forma financial data are for informational purposes only and should not be considered indicative of actual results that would have been achieved had these events actually been consummated on the dates indicated and do not purport to indicate results of operations as of any future date or for any future period. Further, the unaudited pro forma condensed consolidated financial statements do not reflect the impact of restructuring activities, cost savings, management compensation, nonrecurring charges, annual management fees, employee termination costs and other exit costs that may result from or in connection with the Merger. For example, the unaudited pro forma financial data do not give effect to the $35 million annual management fee to be paid to the Sponsors. See “Related Party Transactions.” The unaudited pro forma condensed consolidated financial statements do not include certain transaction costs that may be expensed versus capitalized as part of the purchase price. The historical results of Energy Future Holdings Corp. and its subsidiaries are not necessarily indicative of the results that may be expected in any future period after the close of the Merger.

In preparing the unaudited pro forma condensed consolidated financial statements, the primary adjustments to the historical financial statements of Energy Future Holdings Corp. and its subsidiaries were purchase accounting adjustments which include adjustments necessary to (i) allocate the estimated purchase price to the tangible and intangible assets and liabilities of Energy Future Holdings Corp. and its subsidiaries based on their estimated fair values; and (ii) adjust for the impacts related to debt and other financing expected to be issued and repaid to consummate the Transactions.

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ENERGY FUTURE HOLDINGS CORP.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED INCOME STATEMENT

FOR THE SIX MONTHS ENDED JUNE 30, 2007

	Historical(a)			Transaction Adjustments			Pro Forma
	(in millions)
Operating Revenues	$	3,691		$	11	(b)	$	3,702
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,404			78	(c)		1,482
Operating costs		714						714
Depreciation and amortization		403			174	(d)		577
Selling, general and administrative expenses		447						447
Franchise and revenue-based taxes		176						176
Other Income		(45	)					(45	)
Other deductions		891						891
Interest income		(35	)					(35	)
Interest expense and related charges		418			1,378	(e)		1,796
Total costs and expenses		4,373			1,630			6,003
Loss from continuing operations before income taxes		(682	)		(1,619	)		(2,301	)
Income tax benefit		(294	)		(567	)(f)		(861	)
Loss from continuing operations	$	(388	)	$	(1,052	)	$	(1,440	)

See accompanying Notes to Unaudited Pro Forma Condensed Consolidated Income Statements, which are an integral part of these statements.

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ENERGY FUTURE HOLDINGS CORP.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED INCOME STATEMENT

FOR THE SIX MONTHS ENDED JUNE 30, 2006

	Historical(a)			Transaction Adjustments			Pro Forma
	(in millions)
Operating Revenues	$	4,971		$	11	(b)	$	4,982
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,179			78	(c)		1,257
Operating costs		684						684
Depreciation and amortization		413			174	(d)		587
Selling, general and administrative expenses		370						370
Franchise and revenue-based taxes		174						174
Other Income		(55	)					(55	)
Other deductions		221						221
Interest income		(20	)					(20	)
Interest expense and related charges		431			1,378	(e)		1,809
Total costs and expenses		3,397			1,630			5,027
Income (loss) from continuing operations before income taxes		1,574			(1,619	)		(45	)
Income tax expense (benefit)		561			(567	)(f)		(6	)
Income (loss) from continuing operations	$	1,013		$	(1,052	)	$	(39	)

See accompanying Notes to Unaudited Pro Forma Condensed Consolidated Income Statements,

which are an integral part of these statements.

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ENERGY FUTURE HOLDINGS CORP.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED INCOME STATEMENT

FOR THE TWELVE MONTHS ENDED JUNE 30, 2007

	Historical			Transaction Adjustments			Pro Forma
	(in millions)
Operating Revenues	$	9,576		$	23	(b)	$	9,599
Costs and expenses:
Fuel, purchased power costs and delivery fees		3,009			156	(c)		3,165
Operating costs		1,403						1,403
Depreciation and amortization		821			348	(d)		1,169
Selling, general and administrative expenses		893						893
Franchise and revenue-based taxes		392						392
Other Income		(111	)					(111	)
Other deductions		940						940
Interest income		(60	)					(60	)
Interest expense and related charges		817			2,757	(e)		3,574
Total costs and expenses		8,104			3,261			11,365
Income (loss) from continuing operations before income taxes		1,472			(3,238	)		(1,766	)
Income tax expense (benefit)		407			(1,133	)(f)		(726	)
Income (loss) from continuing operations	$	1,065		$	(2,105	)	$	(1,040	)

See accompanying Notes to Unaudited Pro Forma Condensed Consolidated Income Statements, which are an integral part of these statements.

33

ENERGY FUTURE HOLDINGS CORP.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED INCOME STATEMENT

FOR THE YEAR ENDED DECEMBER 31, 2006

	Historical(a)			Transaction Adjustments			Pro Forma
	(in millions)
Operating Revenues	$	10,856		$	23	(b)	$	10,879
Costs and expenses:
Fuel, purchased power costs and delivery fees		2,784			156	(c)		2,940
Operating costs		1,373						1,373
Depreciation and amortization		830			348	(d)		1,178
Selling, general and administrative expenses		819						819
Franchise and revenue-based taxes		390						390
Other Income		(121	)					(121	)
Other deductions		269						269
Interest income		(46	)					(46	)
Interest expense and related charges		830			2,757	(e)		3,587
Total costs and expenses		7,128			3,261			10,389
Income (loss) from continuing operations before income taxes		3,728			(3,238	)		490
Income tax expense (benefit)		1,263			(1,133	)(f)		130
Income (loss) from continuing operations	$	2,465		$	(2,105	)	$	360

See accompanying Notes to Unaudited Pro Forma Condensed Consolidated Income Statements,

which are an integral part of these statements.

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ENERGY FUTURE HOLDINGS CORP.

Notes to Unaudited Pro Forma Condensed Consolidated Income Statements

(a) Historical presentation—the amounts presented for Energy Future Holdings Corp. are derived from Energy Future Holdings Corp.’s historical audited consolidated income statements for the year ended December 31, 2006 and Energy Future Holdings Corp.’s historical unaudited condensed consolidated income statements for the six month periods ended June 30, 2007 and June 30, 2006, in each case included elsewhere in this Current Report on Form 8-K.

(b) Revenues—represents the pro forma adjustments required to record the amortization related to the fair value of intangible liabilities related to sales contracts or other legal or economic rights. For purposes of this adjustment, amortization was determined based on straight-line method over an estimated useful life of 31 years. These adjustments increased revenues by approximately $11 million, $11 million, $23 million and $23 million for the six month period ended June 30, 2007, the six month period ended June 30, 2006, the twelve month period ended June 30, 2007 and the year ended December 31, 2006, respectively. These items are required to be made to the operating revenues line item in the income statement since the activity associated with the underlying contracts or other legal or economic rights have historically been reported as a component of operating revenues.

(c) Fuel, purchased power costs and delivery fees—represents pro forma adjustments required to record the amortization related to the fair value of intangible assets related to contracts and other legal or economic rights. For purposes of this adjustment, amortization was determined for different categories of intangible assets based on a straight-line method over useful lives ranging from 15 to 28 years. These adjustments increased costs and expenses by approximately $78 million, $78 million, $156 million and $156 million for the six month period ended June 30, 2007, the six month period ended June 30, 2006, the twelve month period ended June 30, 2007 and the year ended December 31, 2006, respectively. These adjustments were required to be made to the fuel, purchased power costs and delivery fees line item in the income statement since the activity associated with the underlying contracts or other legal or economic rights is reported as a component of costs. Adjustments also include additional amortization expense for adjustments to nuclear fuel balances included in property, plant and equipment in the unaudited pro forma condensed consolidated balance sheet.

(d) Depreciation and amortization expense—represents the pro forma adjustment required to adjust property, plant and equipment to record power generation assets and other tangible property at their estimated fair values, as well as to record amortization of the fair value of customer-based intangible assets. For purposes of this adjustment, depreciation and amortization was determined for different categories of property based on a straight-line method over estimated useful lives ranging from 7 to 45 years. These adjustments increased depreciation and amortization expense approximately $174 million, $174 million, $348 million and $348 million for the six month period ended June 30, 2007, the six month period ended June 30, 2006, the twelve month period ended June 30, 2007 and the year ended December 31, 2006, respectively. Transmission and distribution assets are considered to be at fair value due to the regulatory recovery of these assets based on historical costs; accordingly, there were no increases or decreases to depreciation expense related to the regulated assets of Oncor Electric Delivery. An increase or decrease in the fair value of these assets of $500 million would result in an increase or decrease in depreciation and amortization expense of approximately $21 million and $10 million on an annual and six months basis, respectively.

(e) Interest expense—represents pro forma adjustments related to the increase in interest expense as a result of the borrowings made to finance the Merger, less certain interest expense associated with the debt that was repaid as part of the Transactions. In connection with the Merger, approximately $31,787 million of new debt was incurred by Energy Future Holdings Corp. and its subsidiaries, with approximately $5,470 million of existing debt repaid, resulting in a net increase in debt of approximately $26,317 million. This increase in

35

ENERGY FUTURE HOLDINGS CORP.

Notes to Unaudited Pro Forma Condensed Consolidated Statements of Income—Continued

debt significantly increases the overall interest expense for the Issuer. The estimated increase in interest expense was calculated based on an assumed weighted-average interest rate of approximately 9.64% for the new debt to be issued in connection with the Merger. An incremental one-eighth percent increase or decrease in the assumed weighted average rates would increase or decrease interest expense by approximately $30 million on an annual basis and $15 million over a six month period.

Additionally, this adjustment includes interest amounts arising from the fair valuation of the existing debt of Energy Future Holdings Corp. and its subsidiaries that remained outstanding after the Merger. The final determination of the fair value of the debt will be based on the prevailing market interest rates as of the Merger and the necessary adjustment will be amortized as an increase (in the case of a discount to par value) or a decrease (in the case of a premium to par value) to interest expense over the remaining life of each debt issuance.

Further, this adjustment includes amounts to reduce interest expense for the removal of existing deferred financing costs, as well as the addition of interest expense associated with the estimated deferred financing costs of the Debt Financing in connection with the Merger.

	Six months		Twelve months
	(in millions of dollars)
Interest Expense
Cash interest	$	1,295	$	2,591
Amortization of deferred financing costs		41		83
Purchase accounting impacts		42		83
Total	$	1,378	$	2,757

(f) Income tax provision—represents the pro forma tax effect of the above adjustments based on an estimated statutory rate of approximately 35%. This estimate could change based on changes in the applicable tax rates and finalization of the tax position of the Issuer following the Merger.

36

ENERGY FUTURE HOLDINGS CORP.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

AS OF JUNE 30, 2007

	Historical(a)		Transaction Adjustments			Pro Forma
	(in millions)
Cash and cash equivalents	$	422	$	(287	)(b)	$	135
Restricted cash		54					54
Trade accounts receivable—net		1,016					1,016
Inventories		428					428
Commodity and other derivative contractual assets		299					299
Accumulated deferred income taxes		829					829
Margin deposits related to commodity positions		448		(148	)(c)		300
Other current assets		189					189
Total current assets		3,685		(435	)		3,250
Restricted cash		119		1,250	(d)		1,369
Investments		742		130	(e)		872
Property, plant and equipment—net		19,387		7,299	(f)		26,686
Goodwill		542		24,750	(g)		25,292
Intangible assets		—		3,575	(h)		3,575
Regulatory assets—net		1,935		(56	)(i)		1,879
Commodity and other derivative contractual assets		216					216
Other noncurrent assets		362		424	(j)		786
Total assets		26,988		36,937			63,925
Short-term borrowings		2,350		(2,195	)(k)		155
Long-term debt due currently		792		(250	)(k)		542
Trade accounts payable		1,014					1,014
Commodity and other derivative contractual liabilities		429					429
Margin deposits related to commodity positions		35					35
Other current liabilities		993		14	(l)		1,007
Total current liabilities		5,613		(2,431	)		3,182
Accumulated deferred income taxes		3,121		3,995	(m)		7,116
Investment tax credits		353					353
Commodity and other derivative contractual liabilities		876					876
Long-term debt, less amounts due currently		11,917		27,704	(k)		39,621
Other noncurrent liabilities and deferred credits		4,063		414	(l)		4,477
Total liabilities		25,943		29,682			55,625
Shareholders’ equity		1,045		7,255	(n)		8,300
Total liabilities and shareholders’ equity	$	26,988	$	36,937		$	63,925

See accompanying Notes to Unaudited Pro Forma Condensed Consolidated Balance Sheet, which are

an integral part of these statements.

37

ENERGY FUTURE HOLDINGS CORP.

Notes to Unaudited Pro Forma Condensed

Consolidated Balance Sheet—Continued

(a) Historical presentation—The amounts presented for Energy Future Holdings Corp. are derived from the historical unaudited consolidated balance sheet as of June 30, 2007 included elsewhere in this Current Report on Form 8-K.

(b) Cash and cash equivalents—represents the pro forma adjustments required to reflect cash changes resulting from payment of certain transaction fees, return of margin deposits and amounts related to the termination of a LESOP trust.

(c) Margin deposits related to commodity positions—represents pro forma adjustments for the return of certain margin deposits related to commodity positions that were returned to us as part of the implementation of the TCEH Commodity Collateral Posting Facility.

(d) Restricted cash—represents pro forma adjustment related to the increase in restricted cash representing cash received from the TCEH Letter of Credit Facility, which was fully funded at the close of the Merger.

(e) Investments—represents the pro forma adjustment required to adjust certain investments in real estate to their fair values.

(f) Property, plant and equipment—represents the pro forma adjustment required to record power generation assets, nuclear fuel and other property, plant and equipment at fair value. Transmission and distribution assets are considered to be at fair value due to the regulatory recovery of these assets based on historical costs. This adjustment also includes the elimination of existing accumulated depreciation recorded to date as the property will have a new cost basis to be depreciated after the completion of the Transactions. Additionally, this adjustment includes amounts related to fair value estimates for existing real estate and development projects. All of these adjustments were determined by using management’s estimates and assumptions related to the fair value of the assets based on current market indicators for fuel prices, emissions and regulatory costs, electricity prices, operation and maintenance costs, readily observable real estate transactions and other market factors. The estimated fair values used in this adjustment are preliminary and are significantly affected by assumptions that could change materially based on market factors at the time of the Merger. The net increase in property, plant and equipment will be depreciated over the estimated remaining useful lives of related depreciable assets, which range from 8 to 45 years, while the increase in value related to real estate will not be depreciated for financial reporting purposes.

(g) Goodwill—represents the excess of the purchase price for the Merger over the estimated fair values of the assets acquired and liabilities assumed. The total estimated purchase price is calculated based on the per share Merger consideration of $69.25 multiplied by the expected number of shares outstanding at the closing of the Merger, plus estimated transaction costs that are directly related to the Merger. The following table summarizes the purchase price calculation (in millions):

Number of effectively outstanding shares of Energy Future Holdings Corp. common stock as of June 30, 2007		467.6
Multiplied by $69.25 per share Merger consideration	$	32,384
Plus estimated direct transaction costs		597
Total purchase price	$	32,981

38

ENERGY FUTURE HOLDINGS CORP.

Notes to Unaudited Pro Forma

Condensed Consolidated Balance Sheet

Under the purchase method of accounting, the total estimated purchase price is allocated to all tangible and identifiable intangible assets acquired and liabilities assumed based on their respective fair values on the date the Merger is consummated (for purposes of this unaudited pro forma condensed consolidated balance sheet that date is assumed to be June 30, 2007). The fair value estimates of the assets and liabilities in these pro forma financial statements are preliminary and were developed solely to be used in these statements. Additionally, the fair value estimates are subject to revisions based on a multitude of factors and additional information that may come to our attention, any of which could have a material effect on the ultimate valuation. The following table summarizes the allocation of fair value to the assets and liabilities of Energy Future Holdings Corp.:

Item	Fair Value
	(in millions)
Property, plant and equipment	$	(26,686	)
Cash and restricted cash		(1,558	)
Commodity and other derivative contractual assets		(515	)
Other current assets		(2,762	)
Investments		(872	)
Intangibles		(3,575	)
Regulatory assets		(1,879	)
Other noncurrent assets		(786	)
Other current liabilities		2,056
Short-term borrowings and long-term debt due currently		697
Commodity and other derivative contractual liabilities		1,305
Accumulated deferred income taxes		7,116
Long-term debt, less amounts due currently		39,621
Other noncurrent liabilities		4,830
Shareholder’s equity		8,300
Goodwill	$	25,292

In accordance with SFAS No. 142, goodwill is not amortized but is required to undergo impairment tests at least annually or more frequently if facts and circumstances indicate an impairment may have occurred. If an impairment exists, goodwill is immediately written down to its fair value through a charge to earnings. Accordingly, goodwill arising from the Merger will be subject to an impairment test at least annually.

This pro forma adjustment includes the removal of previously existing goodwill on Energy Future Holdings Corp.’s balance sheet of approximately $542 million.

(h) Intangible assets—represents the pro forma adjustment required to recognize certain identifiable intangible assets of Energy Future Holdings Corp. and its subsidiaries. These intangible assets arise due to certain contractual, legal or other economic rights, as well as customer relationships that are separately identifiable from other assets. Several of the intangible assets relate to contracts in our power generation or wholesale business that are not accounted for under mark-to-market accounting since the contracts are not considered derivatives or have been elected to be treated as normal purchases or normal sales under SFAS No. 133. Additionally, an intangible asset will be recognized for the value of environmental emission credits allocated to our power generation fleet by regulatory bodies. The adjustment for emission credits was determined based on current market information utilizing a discounted cash flow valuation. All of the valuations of these intangibles are preliminary and could be materially affected by changes in market prices of fuel, electricity, emission credits, customer

39

ENERGY FUTURE HOLDINGS CORP.

Notes to Unaudited Pro Forma

Condensed Consolidated Balance Sheet—Continued

revenue streams and other market factors. The total amount of all intangible assets recognized in this adjustment is approximately $3,575 million.

The adjustments related to intangible assets will be amortized over the estimated remaining contractual terms ranging from four to 34 years, except for the trademark “TXU Energy,” which will not be amortized but will be subject to periodic impairment tests.

(i) Regulatory assets-net—represents pro forma adjustments related to the write-off of certain regulatory assets of Oncor Electric Delivery as part of the proposed settlement between Oncor Electric Delivery and various market participants that is currently before the PUCT.

(j) Other noncurrent assets—represents the pro forma adjustments to eliminate $97 million of deferred financing costs related to existing debt issuances and to recognize deferred financing costs of $581 million associated with new debt issued in connection with the Merger.

(k) Long-term debt and short term borrowings—represents pro forma adjustments for the issuance of new debt in the Transactions, as well as adjustments for the repayment of existing debt of Energy Future Holdings Corp. and its subsidiaries and the Interim Facility Refinancing. For more information, see “The Transactions—Debt Repayment.”

Also included in this adjustment is the effect of the fair valuation of the existing debt of Energy Future Holdings Corp. and its subsidiaries that remained outstanding after the Merger. Those adjustments resulted in an estimated net discount to debt of approximately $1,121 million. The final determination of the fair value of the debt will be based on prevailing market interest rates at the closing of the Merger and the necessary adjustment will be amortized as an increase (in the case of a discount to par value) or a decrease (in the case of a premium to par value) to interest expense over the remaining life of each debt issuance.

The total pro forma adjustments related to debt are as follows (in millions):

Expected repayment of debt due currently		$(2,445)
Expected repayment of long-term debt		(2,962	)
New long-term debt in connection with the Merger		31,787
Discount on existing debt		(1,121	)
Total adjustment	$	25,259

(l) Other current and noncurrent liabilities—represents pro forma adjustments to record various unfavorable operating contracts that contain unfavorable pricing terms. The amounts relate to power sales agreements, fuel procurement agreements, operating leases and other contracts that are not currently recognized in the historical financial statements. The aggregate adjustment is approximately $701 million for these contracts. These adjustments were developed using estimated fair values based on current market information. This adjustment also includes amounts related to certain deferred credits that are required to be removed by EITF Issue No. 01-03, “Accounting in a Business Combination for Deferred Revenue of an Acquiree.” Those amounts are approximately $345 million, of which $58 million was removed from other current liabilities and $287 million was removed from other noncurrent liabilities. These adjustments also include an additional accrual of $72 million for amounts related to a one-time credit for Oncor Electric Delivery customers related to a proposed settlement between Oncor Electric Delivery and various market participants that is currently before the PUCT.

(m) Deferred taxes—represents pro forma adjustments to record additional net deferred income tax liabilities to account for the differences between book and tax basis of net assets acquired arising from

40

ENERGY FUTURE HOLDINGS CORP.

Notes to Unaudited Pro Forma

Condensed Consolidated Balance Sheet—Continued

the fair value adjustments. This adjustment was based on an estimated statutory tax rate of approximately 35%, which could change based on changes in the applicable tax rates and finalization of the Issuer’s tax position.

(n) Shareholders’ equity—represents pro forma adjustments for eliminating the historical shareholders’ equity of Energy Future Holdings Corp. and the actual amount of cash contributed by the Sponsors and the Investors to Energy Future Holdings Corp.

41

ENERGY FUTURE HOLDINGS CORP.

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table sets forth our selected historical consolidated financial data as of and for the periods indicated. The selected financial data as of December 31, 2005 and 2006 and for each of the three years ended December 31, 2004, 2005 and 2006 have been derived from our audited historical consolidated financial statements and related notes included elsewhere in this Current Report on Form 8-K. The selected financial data as of December 31, 2002, 2003 and 2004 and for the two years ended December 31, 2002 and 2003 have been derived from our historical consolidated financial statements that are not included herein. The unaudited selected financial data as of June 30, 2007 and for the six months ended June 30, 2007 and June 30, 2006 were derived from our unaudited historical condensed consolidated financial statements included elsewhere in this Current Report on Form 8-K.

As required by GAAP, Oncor Electric Delivery Holdings and its subsidiaries are consolidated with Energy Future Holdings Corp. for financial reporting purposes. However, Oncor Electric Delivery Holdings and its subsidiaries are ring-fenced from Energy Future Holdings Corp. and its other subsidiaries as described under “The Transactions—Ring-Fencing,” which means there are restrictions on the ability of Oncor Electric Delivery Holdings and its subsidiaries to make dividends or distributions to us. The unaudited financial data presented have been prepared on a basis consistent with our audited consolidated financial statements. In the opinion of management, such unaudited financial data reflect all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of the results for those periods. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.

The selected historical consolidated financial data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes thereto appearing elsewhere in this Current Report on Form 8-K.

	Year Ended December 31,															Six Months Ended June 30,
	2002			2003			2004			2005			2006			2006			2007
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues	$	8,125		$	8,532		$	9,216		$	10,662		$	10,856		$	4,971		$	3,691
Income (loss) from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles		105			566			81			1,775			2,465			1,574			(682	)
Income (loss) from discontinued operations, net of tax effect		(4,181	)		74			378			5			87			60			11
Extraordinary gain (loss), net of tax effect		(134	)		—			16			(50	)		—			—			—
Cumulative effect of changes in accounting principles, net of tax effect		—			(58	)		10			(8	)		—			—			—
Exchangeable preferred membership interest buyback premium		—			—			849			—			—			—			—
Preference stock dividends		22			22			22			10			—			—			—
Net income (loss) available for common stock		(4,232	)		560			(386	)		1,712			2,552			1,073			(377	)
Dividends declared per share	$	0.96		$	0.25		$	0.47		$	1.26		$	1.67		$	0.83		$	0.87
Ratio of earnings to fixed charges(a)		1.22	x		1.94	x		1.16	x		3.80	x		5.11	x		4.41x			—
Ratio of earnings to combined fixed charges and preference dividends(a)		1.17	x		1.87	x		1.11	x		3.74	x		5.11	x		4.41	x		—

42

	Year Ended December 31,															Six Months Ended June 30, 2007
	2002			2003			2004			2005			2006
	(millions of dollars, except ratios and per share amounts)
Balance Sheet Data (at end of period):
Total assets	$	31,384		$	31,284		$	23,189		$	25,539		$	25,922		$	26,988
Property, plant & equipment—net		16,526			16,803			16,676			17,192			18,756			19,387
Total intangible assets		461			384			190			194			205			196
Capitalization:
Equity-linked debt securities		1,440			1,440			285			179			—			—
Exchangeable subordinated notes(b)		639			—			—			—			—			—
Long-term debt held by subsidiary trusts		546			546			—			—			—			—
All other long-term debt, less amounts due currently		8,003			9,168			12,127			11,153			10,631			11,917
Exchangeable preferred membership interests(b)		—			646			—			—			—			—
Preferred stock of subsidiaries:
Not subject to mandatory redemption(c)		190			113			38			—			—			—
Subject to mandatory redemption		21			—			—			—			—			—
Preference stock		300			300			300			—			—			—
Common stock equity		4,766			5,619			339			475			2,140			1,045
Total	$	15,905		$	17,832		$	13,089		$	11,807		$	12,771		$	12,962
Capitalization Percentages (at period end):
Equity-linked debt securities		9.1	%		8.1	%		2.2	%		1.5	%		—			—
Exchangeable subordinated notes		4.0	%		—			—			—			—			—
Long-term debt held by subsidiary trust		3.4	%		3.1	%		—			—			—			—
All other long-term debt, less amounts due currently		50.3	%		51.4	%		92.7	%		94.5	%		83.2	%		91.9	%
Exchangeable preferred membership interests		—			3.6	%		—			—			—			—
Preferred stock of subsidiaries(c)		1.3	%		0.6	%		0.2	%		—			—			—
Preference stock		1.9	%		1.7	%		2.3	%		—			—			—
Common stock equity		30.0	%		31.5	%		2.6	%		4.0	%		16.8	%		8.1	%
Total		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
Notes payable—commercial paper		—			—			—		$	358		$	1,296			—
Notes payable—banks		2,306			—			210			440			195			2,350
Long-term debt due currently		941			678			229			1,250			485			792
Embedded interest cost on long-term debt(d)		6.8	%		6.3	%		6.0	%		6.3	%		6.6	%		6.6	%
Embedded interest cost on long-term debt held by subsidiary trusts		7.8	%		6.4	%		—			—			—			—
Embedded dividend cost on preferred stock of subsidiaries(e)		6.5	%		9.7	%		4.4	%		—			—			—

43

	Year Ended December 31,															Six Months Ended June 30,
	2002			2003			2004			2005			2006			2006			2007
	(millions of dollars, except ratios and per share amounts)
Statement of Cash Flows Data:
Cash flows provided by (used in) operating activities from continuing operations	$	1,052		$	2,413		$	1,758		$	2,793		$	4,954		$	1,904		$	(55	)
Cash flows provided by (used in) investing activities from continuing operations		(603	)		(1,400	)		4,280			(1,038	)		(2,664	)		(1,062	)		(1,506	)
Cash flows provided by (used in) financing activities from continuing operations		1,782			(1,731	)		(6,519	)		(1,563	)		(2,332	)		(806	)		1,934
Other Financial Information:
Capital expenditures, including nuclear fuel		864			765			999			1,104			2,297			855			1,641

(a) For purposes of computing the ratio of earnings to fixed charges and ratio of earnings to combined fixed charges and preference dividends, (1) earnings consist of net income plus income taxes plus fixed charges less capitalized expenses related to indebtedness and (2) fixed charges consists of interest expense and capitalized expenses related to indebtedness. For purposes of computing the ratio of earnings to combined fixed charges and preference dividends, preference share dividends are included in fixed charges. For the six months ended June 30, 2007, fixed charges and combined fixed charges and preference dividends exceeded earnings by $682 million.

(b) Amount is net of discount.

(c) Preferred stock outstanding at June 30, 2007, December 31, 2006 and December 31, 2005 has a stated amount of $51,000.

(d) Represents the annual interest using year-end rates for variable rate debt and reflecting effects of interest rate swaps and amortization of any discounts, premiums, issuance costs and any deferred gains/losses on reacquisitions divided by the carrying value of the debt plus or minus the unamortized balance of any discounts, premiums, issuance costs and gains/losses on reacquisitions at the end of the year.

(e) Includes the unamortized balance of the loss on reacquired preferred stock and associated amortization. The embedded dividend cost excluding the effects of the loss on reacquired preferred stock is 6.0% for 2002.

Certain previously reported financial statistics reflect reclassifications to conform to current year classifications.

Prior year amounts have been reclassified for discontinued operations. Share and per share amounts reflect the 2005 two-for-one stock split which occurred on November 18, 2005.

Results from 2004 are significantly impacted by charges related to the comprehensive restructuring plan.

44

ENERGY FUTURE HOLDINGS CORP. MANAGEMENT’S DISCUSSION AND

ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations primarily covers periods prior to the closing of the Merger. Accordingly, other than in “—Financial Condition—Post Merger,” the discussion and analysis of historical periods does not reflect the significant impact that the Merger will have on us, including significantly increased leverage and liquidity requirements. You should read the following discussion of our results of operations and financial condition with the “Energy Future Holdings Corp. Unaudited Pro Forma Condensed Consolidated Financial Statements,” “Selected Historical Consolidated Financial Data” and the audited and unaudited historical consolidated financial statements and related notes included elsewhere in this Current Report on Form 8-K. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in the “Risk Factors” section of this Current Report on Form 8-K. Actual results may differ materially from those contained in any forward-looking statements.

Business

We are a Dallas-based energy company that manages a portfolio of competitive and regulated energy businesses in Texas. We are a holding company conducting our operations principally through our subsidiaries, TCEH, Oncor Electric Delivery and their respective subsidiaries. TCEH, in turn, is a holding company for our businesses engaged in competitive electricity market activities largely in Texas, including electricity generation conducted through Luminant Power, wholesale energy markets activities conducted through Luminant Energy, electricity generation construction conducted through Luminant Construction and the retail sale of electricity conducted through TXU Energy. Oncor Electric Delivery is engaged in regulated electricity transmission and distribution operations in Texas.

Operating Segments

Energy Future Holdings Corp. has aligned and reports its business activities as two operating segments: Competitive Electric and Regulated Delivery.

The Competitive Electric segment includes TCEH, consisting of the Luminant businesses and TXU Energy. This segment also includes the activities of a lease trust holding certain natural gas-fueled combustion turbines.

The Regulated Delivery segment includes the activities of Oncor Electric Delivery. This segment also includes its wholly owned bankruptcy-remote financing subsidiary and certain revenues and costs associated with broadband-over-powerlines equipment installation.

See Note 24 to the 2006 year-end Financial Statements for further information concerning reportable business segments.

Business Strategy

Overview

In 2004, Energy Future Holdings Corp. launched a three-phase restructuring program to restore financial strength, drive performance improvement with a competitive industrial company perspective and allocate capital in a disciplined and efficient manner.

• Phase one involved divesting of value-disadvantaged businesses and using the sales proceeds, operating cash flows and cash on hand to simplify the capital structure and improve financial flexibility. This phase also included changing pricing and commodity price hedging strategies to reflect rising natural gas prices, resolving significant litigation risks and lowering business process costs through a significant outsourcing arrangement. Phase one was completed in 2004. As discussed in

45

Note 8 to the 2006 year-end Financial Statements, these restructuring actions resulted in net charges to 2004 income from continuing operations totaling $1.2 billion ($828 million after-tax). Also see Note 3 to the 2006 year-end Financial Statements for the effect on results from discontinued operations.

• Phase two included implementation of initiatives to achieve operational excellence across the business, targeting industry-leading performance standards for productivity, reliability and customer service and embedding a high-performance industrial culture. Phase two work has been largely completed but remains ongoing as a basis for continuous process improvement.

• Phase three included development and implementation of the growth strategy for Energy Future Holdings Corp. and its two business segments. In 2006, actions were initiated to execute this strategy by way of several key initiatives launched during the year, including planned development of new generation facilities. Energy Future Holdings Corp. has agreed to modify this strategy in connection with the Merger.

Following is a discussion of key operating developments in the Competitive Electric and Regulated Delivery operating segments.

Significant Developments

Merger

On October 10, 2007, Energy Future Holdings Corp. completed its Merger with Merger Sub, a wholly-owned subsidiary of Texas Holdings. As a result of the Merger, Energy Future Holdings Corp. became a wholly-owned subsidiary of Texas Holdings. Texas Holdings is controlled by investment funds affiliated with KKR, TPG and Goldman, Sachs & Co. In connection with the Merger, C. John Wilder, Energy Future Holdings Corp.’s Chairman and Chief Executive Officer, resigned from Energy Future Holdings Corp.

The aggregate purchase price paid for all of the equity securities of Energy Future Holdings Corp. (on a fully-diluted basis) was approximately $32.4 billion, which purchase price was funded by the equity financing from the Sponsors and certain other investors and by the new credit facilities described below. This purchase amount is exclusive of costs directly associated with the Merger including legal, consulting and professional service fees and certain effects of the proposed regulatory settlement referred to below. For additional details regarding the effects of the completion of the Merger transaction, see Note 17 to the June 30, 2007 Financial Statements and Note 26 to the 2006 year-end Financial Statements. For additional details regarding the allocation of the purchase price to the fair value of the net assets acquired using purchase accounting, see the “Energy Future Holdings Corp. Unaudited Pro Forma Condensed Consolidated Financial Statements” section of this Current Report on Form 8-K.

Texas Generation Facilities Development

Luminant Construction is developing three lignite coal-fueled generation units in the state of Texas with a total estimated capacity of approximately 2,200 MW. The three units consist of one new generation unit at one of our existing lignite coal-fueled generation plant sites (Sandow) and two units at one of our sites (Oak Grove) that was originally slated for the construction of a generation plant a number of years ago.

Design and procurement activities for the three proposed units are at an advanced stage and site construction is well underway. Air permits for all three proposed units have been obtained. In June 2007, the TCEQ voted to approve the air permit for the two Oak Grove units. Certain opponents of the new units at Oak Grove appealed the TCEQ’s permit decision to district court in Travis County, Texas, but the permit remains in full force notwithstanding this action. Also, in December 2006, certain environmental organizations filed a lawsuit in federal court alleging that the permit application for the Oak Grove units had violated provisions of the federal Clean Air Act and Texas Health and Safety Code. In May 2007, the District Court granted our motion to dismiss the plaintiffs’ complaint, and the decision of that court has been appealed to the Fifth Circuit Court of

46

Appeals. In September 2007, a subsidiary of Energy Future Holdings Corp. acquired from Alcoa Inc. the air permit relating to the Sandow Facility that has been previously issued by the TCEH. Although a federal district court judge approved a settlement pursuant to which we acquired the permit, environmental groups opposed to the settlement have appealed the decision to the Fifth Circuit Court of Appeals. EPC agreements have been executed with leading EPC contractors to engineer and construct the Sandow and Oak Grove units. The expected on-line dates of the units are as follows: Sandow in 2009 and Oak Grove’s two units in 2009 and 2010.

In September 2007, subsidiaries of Energy Future Holdings Corp. acquired certain assets of Alcoa Inc. relating to the operation at the Three Oaks Mine (the lignite mine that serves the Sandow units), including partial ownership of the lignite reserves in the Three Oaks Mine, for approximately $135 million and assumed responsibility for mining operations at the Three Oaks Mine.

Nuclear Generation Development

Energy Future Holdings Corp. is proceeding with the preparation of a combined license application for two new nuclear generation facilities, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear generation site. Although Energy Future Holdings Corp. may select to develop additional sites at a later date subsequent to closing of the Merger, no work is being done on the development of nuclear generation facilities at additional sites at this time and there is no schedule for the submittal of additional combined license applications. It is currently anticipated that these new units would be developed by TCEH or its subsidiaries.

Investment in Cleaner Coal-Fueled Generation Technologies

In an initiative separate from but related to the planned generation development and related emissions controls investment spending, subsidiaries of Luminant expect to invest up to $2 billion over the next five to seven years for the development and commercialization of cleaner generation plant technologies, including integrated gasification combined cycle, the next generation of more efficient ultra-supercritical coal and pulverized coal emissions technology to reduce carbon dioxide emissions. Luminant Power has already initiated a number of actions, including research and development investments and partnerships, to advance next-generation technologies.

Integrated Gasification Combined Cycle (“IGCC”) Demonstration Plants

In March 2007, Energy Future Holdings Corp. and the Sponsors announced their intention to explore the development of two IGCC commercial demonstration plants to be located in Texas and Energy Future Holdings Corp. expects to issue a request for proposal from companies offering coal gasification technologies with carbon dioxide capture.

Long-term Hedging Program

In October 2005, Energy Future Holdings Corp. initiated a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, subsidiaries of TCEH have entered into market transactions involving natural gas-related financial instruments. As of October 10, 2007, these subsidiaries have effectively sold forward approximately 2.6 billion MMBtu of natural gas (equivalent to the natural gas exposure of over 300,000 GWh at an assumed 8.5 MMBtu/MWh market heat rate) over the period from 2008 to 2013 at average annual prices ranging from $7.25 per MMBtu to $8.15 per MMBtu.

Prior to March 2007, a significant portion of the instruments under the long-term hedging program had been designated as cash flow hedges. In March 2007, these instruments were dedesignated as allowed under SFAS 133. Changes in fair value of these hedges that were deferred in accumulated other comprehensive income totaled $117 million in pretax gains at the time of the dedesignation, and this amount is expected to be reclassified to net income as the related forecasted transactions settle. Subsequent changes in the fair value of

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these instruments are being marked-to-market in net income, which has and could continue to result in significantly increased volatility in reported earnings. Based on the size of the long-term hedging program as of October 10, 2007, a $1.00/MMBtu change in natural gas prices would result in the recognition by Energy Future Holdings Corp. of approximately $2.6 billion in pretax unrealized mark-to-market gains or losses.

In the first half of 2007, subsidiaries of Energy Future Holdings Corp. entered into several large hedging transactions involving natural gas-related financial instruments that resulted in “day one” losses totaling $160 million. The “day one” loss essentially represents the discount to transact this position given its size and long dating.

Approximately 90% of TCEH’s natural gas hedging transactions are secured by a first lien security interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility) thereby reducing the collateral requirements of the hedging program.

New Leases

In September 2007, TCEH entered into a $52 million capital lease with High Ridge Leasing to refinance an operating lease of rail cars. An obligation of $52 million will be reported as long-term debt.

In September 2007, TCEH entered into a $93 million operating lease with AIG Rail Services, Inc. to refinance an existing operating lease of rail cars.

Retail Pricing

In May 2007, Energy Future Holdings Corp. and the Sponsors announced that residential price cuts provided by TXU Energy subsequent to the announcement of the Merger would total 15% (5% of which will be implemented in late October 2007), which represented a five percentage point increase over the previously announced price discount program.

Suspension and Expected Termination of New Utility Services Joint Venture

Energy Future Holdings Corp. and InfrastruX Group suspended activities related to the InfrastruX Energy Services (“IES”) joint venture and Oncor Electric Delivery and IES suspended activities related to the utility services agreement. As a result of the Merger, Energy Future Holdings Corp. and Oncor Electric Delivery expect to terminate the joint venture and the utility services agreement.

In the second quarter of 2007, Energy Future Holdings Corp. wrote-off approximately $11 million ($7 million after-tax) in previously deferred costs primarily representing professional fees incurred in the development of the joint venture agreements.

Termination of Reference Plant Permitting

On October 15, 2007, we formally acted to terminate air permit applications for eight coal-fueled power units. The action delivers on our commitment to terminate the permit process upon close of the Merger. We suspended efforts to obtain the permits after the announcement of the Merger.

Technology Initiatives

In 2006, Oncor Electric Delivery finalized an agreement with CURRENT Communications Group, LLC (“CURRENT”), to utilize Oncor Electric Delivery’s power distribution network as a broadband-enabled “Smart Grid.” CURRENT plans to design, build and operate the “broadband over power line” (“BPL”) network covering the majority of the Oncor Electric Delivery service area. Build-out of the BPL network began in 2006 with the installation of fiber optic cable and additional investment in advanced data management systems. Under the

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terms of the agreement with CURRENT, Oncor Electric Delivery expects to incur service fees totaling approximately $150 million over a 10 year period commencing in 2007 to utilize the Smart Grid capabilities of CURRENT’s BPL network.

Overlaid on the existing electric distribution network, the CURRENT BPL network solution will incorporate advanced digital communication and computing capabilities that, for the first time, provide real-time monitoring through the electric distribution network, enabling Oncor Electric Delivery to:

• increase network reliability and power quality;

• prevent, detect and restore customer outages more effectively; and

• implement advanced meter monitoring more efficiently.

Additionally, CURRENT will use the same BPL network to provide homes and businesses with high-performance broadband and wireless services, including voice, video and high-speed Internet access, provided over existing electrical lines by having customers simply plug into any electrical outlet.

Energy Future Holdings Corp. has made a small investment to acquire a noncontrolling interest in CURRENT. Other CURRENT investors include energy, financial services and technology companies.

To take full advantage of the BPL network, Oncor Electric Delivery has initiated replacement of existing meters with advanced digital metering technology. Installation of these advanced meters is expected to speed connects/disconnects of electric service where applicable and ultimately facilitate the creation of new products and service offerings by REPs, including time-of-use options and various new billing methods. Oncor Electric Delivery has installed approximately 285,000 advanced meters in its service territory as of December 31, 2006 and plans to install up to 600,000 additional advanced meters in 2007. Oncor Electric Delivery expects to replace all of its three million meters with advanced meters under this technology initiative by 2012, for a total investment of approximately $450 million. Texas legislation provides for the recovery of and return on a utility’s investment related to advanced metering technology to incent electricity delivery utilities to invest in this new technology.

Rate Case and Proposed PUCT Settlement

In April 2007, the PUCT issued an order requiring Oncor Electric Delivery to file a rate case based on a test year ending December 31, 2006. On August 28, 2007, Oncor Electric Delivery made the required filing, and the filing supports a rate increase of approximately $85 million over current rates subject to the original jurisdiction of the PUCT. However, Oncor Electric Delivery requested that the PUCT enter an order abating the proceeding, except that the PUCT convene a technical conference to consider a final order in this Docket No. 34040 that would include the following provisions: (i) the PUCT will take “no action” on Oncor Electric Delivery’s proposed rate filing package and will enter an order confirming that Oncor Electric Delivery’s current rates will remain in effect until otherwise changed by a final order of the PUCT or other appropriate jurisdictional authority; (ii) Oncor Electric Delivery will be required to file a system-wide rate case with the PUCT no later than July 1, 2008, based on a test year ended December 31, 2007, consistent with the Settlement Agreement between Oncor Electric Delivery and certain cities in its service territory; (iii) Oncor Electric Delivery will be required to file an EMR with the PUCT no later than March 15, 2008, for calendar year 2007, and no later than March 15, 2009, for calendar year 2008, notwithstanding the pendency at the PUCT of this or any other Oncor Electric Delivery rate case; and (iv) the PUCT will enter an accounting order, or similar directive, providing that if Oncor Electric Delivery’s 2008 or 2009 EMR filings demonstrate that Oncor Electric Delivery earned more than a 10.75% return on equity (“ROE”) during the relevant period covered by the EMR filing, on a weather normalized basis, Oncor Electric Delivery will record a credit to the underrecovery balance in its insurance reserve, such that the additional expense would result in Oncor Electric Delivery’s ROE for the relevant period being no higher than 10.75%. Many of the parties to this proceeding, including Oncor Electric Delivery and the PUCT staff, have agreed on the terms of a settlement of this proceeding; however, a hearing on

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the merits has been scheduled for December 12-13, 2007. We cannot predict which, if any, of the above proposals will be adopted by the PUCT in the final order.

Because the PUCT has original jurisdiction over only transmission rates and the distribution rates charged in unincorporated areas and within cities that have ceded original jurisdiction to the PUCT, Oncor Electric Delivery estimates that approximately one-third of its operating revenues may be subject to change in this rate proceeding. While we believe the rates are just and reasonable, we cannot predict the results of any rate case.

On October 5, 2007, Oncor Electric Delivery and Texas Holdings reached an agreement in principle with major interested parties to resolve all outstanding issues with the PUCT. For additional details, see Note 17 to the June 30, 2007 Financial Statements and Note 26 to the 2006 year-and Financial Statements.

Other Oncor Electric Delivery Matters

Texas Holdings has announced that it expects to sell up to an approximately 20% stake in Oncor Electric Delivery. The sale of a minority stake in Oncor Electric Delivery is intended to enhance Oncor Electric Delivery’s independence and separation from Texas Holdings and its other subsidiaries. The purchaser of the minority stake will not be affiliated with Texas Holdings or any of its subsidiaries or other affiliates.

In addition, Oncor Electric Delivery is expected to secure all of its currently existing long-term debt that was not repaid in the Transactions.

Key Risks and Challenges

Following is a discussion of the key risks and challenges facing management and the initiatives currently underway to manage such challenges. This section should be read in conjunction with “Risk Factors.”

Natural Gas Price and Market Heat-Rate Exposure

Wholesale electricity prices in the Texas market generally correlate with the price of natural gas because marginal demand for electricity supply is generally met with natural gas-fueled generation plants. Natural gas prices have increased significantly in recent years, but historically the price has fluctuated due to the effects of weather, changes in industrial demand and supply availability, and other economic and market factors. Wholesale electricity prices also move with market heat rates. Heat rate is the measure of the efficiency of the marginal supplier (generally natural gas-fueled plants) in generating electricity. The wholesale market price of power divided by the market price of natural gas represents the market heat rate.

In contrast to Energy Future Holdings Corp.’s natural gas-fueled generation units, changes in natural gas prices have no significant effect on the cost of generating electricity from Energy Future Holdings Corp.’s nuclear and lignite/coal-fueled plants. All other factors being equal, these baseload generation assets, which provided 70% of Energy Future Holdings Corp.’s supply volumes in 2006, increase or decrease in value as natural gas prices rise or fall, respectively, because of the effect of natural gas prices on wholesale power prices.

With the exposure to variability of natural gas prices, retail sales price management and hedging activities are critical to the profitability of the business. With the expiration of the price-to-beat rate mechanism on January 1, 2007, Energy Future Holdings Corp. has price flexibility in all of its retail markets.

Considering forecasted electricity supply and sales load and wholesale market positions, Energy Future Holdings Corp.’s portfolio position for 2007 is largely balanced with respect to changes in natural gas prices. The supply and load forecast take into account projections of baseload unit availability and customer churn and currently assumes no further changes in retail rates for customers not already on a fixed price contract.

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Energy Future Holdings Corp.’s approach to managing commodity price risk focuses on the following:

• improving customer service to attract and retain high-value customers;

• continuing to follow a retail pricing strategy that appropriately reflects the magnitude and costs of commodity price risk;

• continuing reduction of fixed costs to better withstand gross margin volatility; and

• employing disciplined hedging and risk management strategies through physical and financial energy-related (electricity and natural gas) contracts to partially hedge gross margins.

As discussed above under “—Significant Developments—Long-term Hedging Program,” Energy Future Holdings Corp. has implemented a long-term hedging program that it believes mitigates the risk of future declines in wholesale electricity prices due to declines in natural gas prices.

The following scenarios are presented to quantify the potential impact of movements in natural gas prices and market heat rates. Illustratively, if our sales prices immediately and fully adjusted to reflect changes in wholesale electricity prices due to changes in natural gas prices, and taking into account the hedges in place at year-end 2006 under the long-term hedging program expected to settle in 2007, Energy Future Holdings Corp. could experience an approximate $300 million reduction in annual pretax earnings for every $1.00 per MMBtu reduction in natural gas prices (approximate 14% change in current price) sustained over the full year. In the same scenario of full and immediate pass-through of wholesale electricity price changes to sales prices, where natural gas prices and other nonprice conditions remained unchanged but ERCOT wholesale electricity prices declined by $5/MWh (approximate 9% change in current price) for a full year because of a decline in market heat rates, Energy Future Holdings Corp. could experience an approximate $300 million reduction in annual pretax earnings.

The long-term hedging program does not mitigate exposure to changes in market heat rates. Energy Future Holdings Corp.’s market heat rate exposure derives from its generation portfolio and may increase over time with expected generation capacity increases. Energy Future Holdings Corp. expects that increases in market heat rates would increase the value of its generation assets because higher market heat rates generally result in higher wholesale electricity prices, and vice versa.

On an ongoing basis, Energy Future Holdings Corp. will continue monitoring its overall commodity risks and seek to balance its portfolio based on its desired level of exposure to natural gas prices and market heat rates and potential changes to its operational forecasts of overall generation and consumption in its native and growth business. Portfolio balancing may include the execution of incremental transactions or the unwinding of existing transactions. As a result, commodity price exposures and their effect on earnings could change from time to time.

See “—Financial Condition—Historical/Pre-Merger—Liquidity and Capital Resources” below for a discussion of the liquidity effects of the long-term hedging program. Also see additional discussion of risk measures below under “—Quantitative and Qualitative Disclosure About Market Risk.”

Competitive Markets and Customer Retention

Competitive retail activity in Texas continued to result in declines in customer counts and sales volumes in the historical service territory. Total retail sales volumes declined 11%, 17% and 12% in 2006, 2005 and 2004, respectively, as retail sales volume declines in the historical service territory were partially offset by growth in other territories. As of year-end 2006, the area representing TCEH’s historical service territory prior to deregulation, largely in north Texas, consisted of approximately three million electricity consumers (measured by meter counts), of which approximately 1.9 million were retail customers of TCEH. As of year-end 2006, TCEH had acquired approximately 256,000 retail customers in other competitive areas in Texas. In responding to the

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competitive landscape and the transition to full competition in the Texas marketplace on January 1, 2007, TCEH is focusing on the following key initiatives:

• Customer retention strategy remains focused on delivering world-class customer service and improving the overall customer experience. In line with this strategy, TCEH continues to implement initiatives to improve call center response time and effectiveness as well as Internet interaction with customers;

• TCEH intends to establish itself as the most innovative retailer in the Texas market as it is critical in the fully competitive environment and continues to develop tailored product offerings to meet customer needs;

• A comprehensive customer initiative to provide residential customers with greater savings and price certainty has been introduced. See discussion under “—Retail Pricing”; and

• Initiatives in the business market are focused largely on programs targeted to retain the existing highest-value customers and to recapture customers who have switched REPs. Initiatives include a more disciplined contracting and pricing approach and improved economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy the direct-sales force. Tactical programs put into place include improved customer service, new product price/service offerings and a multichannel approach for the small business market.

Energy Prices and Regulatory Risk

Natural gas prices rose to unprecedented levels in the latter part of 2005, reflecting a world-wide increase in energy prices compounded by hurricane-related infrastructure damage. The related rise in retail electricity prices elevated public awareness of energy costs and dampened customer demand in 2006. Natural gas prices have since declined but remain subject to events that create price volatility. Sustained high energy prices and/or ongoing price volatility also creates a risk for regulatory and/or legislative intervention with the mechanisms that govern the competitive wholesale and retail markets in Texas. Energy Future Holdings Corp. believes that competitive markets result in a broad range of innovative pricing and service alternatives to consumers and ultimately the most efficient use of resources, and that regulatory bodies should continue to take actions that encourage competition in the industry.

New and Changing Environmental Regulations

Energy Future Holdings Corp. is subject to various environmental laws and regulations related to sulfur dioxide, nitrogen oxides and mercury emissions as well as other environmental contaminants that impact air and water quality. Energy Future Holdings Corp. believes it is in material compliance with all currently applicable requirements under such laws and regulations, but additional requirements under current air regulations, including the Clean Air Interstate Rule and the Clean Air Mercury Rule, will need to be satisfied in the future. See “Business—Environmental Regulations and Related Considerations—Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions.” Regulatory authorities continue to evaluate existing requirements and consider proposals for changes.

Energy Future Holdings Corp. continues to closely monitor any potential legislative changes pertaining to climate change and carbon dioxide emissions. The increasing attention to potential environmental effects of greenhouse gas emissions creates risk as to the completion of Energy Future Holdings Corp.’s plan to develop new lignite coal-fueled generation facilities in Texas. New legislation could result in higher costs due to new taxes, the need to acquire emissions credits or capital spending to reduce carbon dioxide emissions.

As discussed above, Energy Future Holdings Corp. has announced actions to address carbon dioxide emissions concerns, including:

• Establishing a plan to invest up to $2 billion for the development and commercialization of cleaner generation plant technologies;

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• Initiating the process to file an application to the NRC for licenses to construct and operate a new nuclear generation facility in Texas;

• Doubling the renewable energy (wind generation) portfolio to 1,500 MW;

• Investing up to $400 million in programs designed to encourage customer electricity demand efficiencies; and

• Increasing production efficiency of its existing generation facilities by up to two percent.

Cost Exposure Related to Nuclear Asset Outages

Energy Future Holdings Corp.’s nuclear assets are comprised of two generating units at Comanche Peak, each with a capacity of 1,150 MW. The Comanche Peak plant represents approximately 13% of Energy Future Holdings Corp.’s total generation capacity. The nuclear generation facilities represent Energy Future Holdings Corp.’s lowest marginal cost source of electricity. Assuming both nuclear generating units experienced an outage, the unfavorable impact to pretax earnings is estimated to be approximately $3.5 million per day before consideration of any insurance proceeds. Maintaining safe, reliable and efficient operations at the Comanche Peak plant is one of Energy Future Holdings Corp.’s top priorities. Also see discussion of nuclear facilities insurance in Note 16 to the 2006 year-end Financial Statements.

Texas Generation Development Program

The undertaking of the development of three lignite coal-fueled generation units in Texas as described above under “—Significant Developments” involves a number of risks. Aggregate capital expenditures to develop these three units are expected to total approximately $3.25 billion, including all construction, site preparation and mining development costs (not including the purchase of the Three Oaks mine assets). While Energy Future Holdings Corp. believes the investment economics of the program are strong, estimates of future natural gas prices, market heat rates and effects of any carbon dioxide emissions regulation may prove to be inaccurate, and returns on the investment could be significantly less than anticipated. The program is exposed to construction delays, failure of the units to meet performance specifications, nonperformance by equipment suppliers, increases in construction labor costs (which are contractually limited in part) and other project execution risks. Further, project capital spending for the three units continues despite increasing public discussion of the advantages and disadvantages of coal-fueled generation.

See Note 10 to the June 30, 2007 Financial Statements regarding commitments to the development activities.

Application of Critical Accounting Policies

Energy Future Holdings Corp.’s significant accounting policies are discussed in Note 1 to the 2006 year-end Financial Statements. Energy Future Holdings Corp. follows accounting principles generally accepted in the United States. Application of these accounting policies in the preparation of Energy Future Holdings Corp.’s consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenue and expense during the periods covered. The following is a summary of certain critical accounting policies of Energy Future Holdings Corp. that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

Derivative Instruments and Mark-to-Market Accounting—Energy Future Holdings Corp. enters into contracts for the purchase and sale of energy-related commodities, and also enters into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under SFAS 133, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.

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Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing the mark-to-market valuations, each market segment is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using market modeling techniques that take into account available market information; Energy Future Holdings Corp. generally recognizes losses but not gains due to the modeling risks associated with illiquid periods.

SFAS 133 allows for “normal” purchase or sale elections and hedge accounting designations, which generally eliminates or defers the requirement for mark-to-market recognition in net income and thus reduces the volatility of net income that can result from fluctuations in fair values. These elections and designations are intended to better match the accounting recognition of financial performance with the economic and risk decision-making profile. “Normal” purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business. Derivative contracts held for trading purposes are marked-to-market in net income.

In accounting for cash flow hedges, changes in fair value are recorded in other comprehensive income to the extent the change in value is effective; that is, it mirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectiveness of the hedge are recognized in net income immediately, and the effective portion of changes in fair value are initially recorded in other comprehensive income and are recognized in net income when the hedged transactions are recognized. Because Energy Future Holdings Corp.’s generation position is not marked-to-market, management has striven to make elections under SFAS 133 with respect to economic hedges of that position that allow accounting results to be more reflective of the economic position. Energy Future Holdings Corp. continually assesses these elections and under SFAS 133 could dedesignate positions currently accounted for as cash flow hedges, the effect of which could be more volatility of reported earnings as all changes in the fair value of the positions would be included in net income. Also see discussions of the long-term hedging program discussed above under “—Significant Developments.”

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The following tables provide the effects on both net income and other comprehensive income of accounting for those derivative instruments that Energy Future Holdings Corp. has determined to be subject to fair value measurement under SFAS 133:

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Amounts recognized in net income (after-tax):
Unrealized ineffectiveness net gains (losses) on unsettled positions accounted for as cash flow hedges	$	141		$	(24	)	$	(14	)
Reversals of previously recognized unrealized net losses related to cash flow hedge positions settled in the period		14			7			1
Unrealized net gains (losses) on unsettled positions marked-to-market in net income		15			21			(19	)
Reversals of previously recognized unrealized net losses (gains) related to marked-to-market positions settled in the period		7			(15	)		(40	)
Total	$	177		$	(11	)	$	(72	)
Amounts recognized in other comprehensive income (after-tax):
Net gains (losses) in fair value of unsettled positions accounted for as cash flow hedges	$	568		$	(47	)	$	(75	)
Net losses (gains) on cash flow hedge positions recognized in net income to offset hedged transactions		(15	)		77			44
Total	$	553		$	30		$	(31	)

The effect of mark-to-market and hedge accounting on the balance sheet is as follows:

	December 31,
	2006			2005
	(millions of dollars)
Net derivative asset (liability) related to cash flow hedges	$	910		$	(164	)
Net derivative liability related to interest rate fair value hedges		(85	)		(71	)
Other derivative assets		9			9
Total net cash flow hedge and other derivative asset (liability)	$	834		$	(226	)
Net commodity contract asset(a)	$	69		$	36
Long-term debt fair value adjustments—decrease in carrying value(b)	$	(63	)	$	(44	)
Net accumulated other comprehensive gain (loss) included in shareholders’ equity (after-tax amounts)	$	411		$	(142	)

(a) Excludes amounts not arising from mark-to-market valuations such as payments and receipts of cash and other consideration associated with commodity hedging and trading activities.

(b) Includes unamortized net gains of $6 million in 2006 related to settled interest rate swaps designated as fair value hedges. The gain is being amortized to net income as the hedged transactions are recognized.

See discussion above under “—Significant Developments—Long-term Hedging Program” regarding the long-term hedging program. A significant portion of the positions entered into under this program, which are natural gas-related financial instruments, are accounted for as cash flow hedges of future electricity sales.

Revenue Recognition—Energy Future Holdings Corp.’s revenue includes an estimate for unbilled revenue that represents estimated daily kilowatt-hours (“kWh”) consumption after the meter read date to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using historical kWh

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usage information adjusted for weather and other measurable factors affecting consumption. Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because of seasonal changes in demand. Accrued unbilled revenues totaled $466 million, $494 million and $422 million at December 31, 2006, 2005 and 2004, respectively.

Accounting for Contingencies—The financial results of Energy Future Holdings Corp. may be affected by judgments and estimates related to loss contingencies. A significant contingency that Energy Future Holdings Corp. accounts for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debt expense is based on factors such as historical write-off experience, aging of accounts receivable balances, changes in operating practices, regulatory rulings, general economic conditions and customer behavior. Increased customer attrition due to competitive activity and seasonal variations in amounts billed adds to the complexity of the estimation process. Historical results alone are not always indicative of future results causing management to consider potential changes in customer behavior and make judgments about the collectibility of accounts receivable. Bad debt expense totaled $68 million, $56 million and $90 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Litigation contingencies also may require significant judgment in estimating amounts to accrue. During 2004, management assessed the progress and status of matters in litigation and recorded a net $84 million ($55 million after-tax) charge for the anticipated settlement of the shareholders’ litigation initially filed in October 2002 (estimated litigation liability of $150 million less $66 million in pledged reimbursements from insurance carriers). In January 2005, Energy Future Holdings Corp. reached a comprehensive settlement of the shareholders’ litigation, which included a one-time payment to the class members of $150 million. To recognize additional insurance reimbursements related to the settlement, Energy Future Holdings Corp. recorded credits to earnings in 2005 and 2006 of $35 million ($23 million after-tax) and $15 million ($10 million after-tax), respectively.

Accounting for Income Taxes—Energy Future Holdings Corp.’s income tax expense and related balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, Energy Future Holdings Corp.’s forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. Energy Future Holdings Corp.’s income tax returns are regularly subject to examination by applicable tax authorities. In management’s opinion, an adequate reserve has been made for any future taxes that may be owed as a result of any examination.

FIN 48 provides interpretive guidance for accounting for uncertain tax positions, and as discussed in Note 1 to the 2006 year-end Financial Statements, Energy Future Holdings Corp. adopted this new standard January 1, 2007, as required. Also, see Notes 11 and 16 to the 2006 year-end Financial Statements for discussion of income tax matters.

Impairment of Long-Lived Assets—Energy Future Holdings Corp. evaluates long-lived assets for impairment whenever indications of impairment exist, in accordance with SFAS 144. One of those indications is a current expectation that “more likely than not” a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. For Energy Future Holdings Corp.’s baseload generation assets, another possible indication would be an expected long-term decline in natural gas prices. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets. Further, the unique nature of Energy Future Holdings Corp.’s property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual plants that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing.

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In the second quarter of 2006, we recorded an impairment charge of $198 million ($129 million after-tax) related to its natural gas-fueled generation plants. See Note 6 to the 2006 year-end Financial Statements for a discussion of the impairment. The estimated impairment was based on numerous assumptions including forecasted production, forward prices of natural gas and electricity, overall generation availability in ERCOT, ERCOT grid congestion and forward heat rates. Because of the highly judgmental nature of key assumptions and potential volatility of market conditions, the adjusted carrying value of these plants does not necessarily represent the amount of proceeds from any transaction to sell the assets, and future additional impairment is possible.

Energy Future Holdings Corp.’s most significant long-lived asset in terms of carrying value is its Comanche Peak nuclear generation facility. The net book value of the facility was $7.4 billion at December 31, 2006. Energy Future Holdings Corp. believes that the net book value of the facility significantly exceeds the estimated current market value. However, in applying the provision of SFAS 144, Energy Future Holdings Corp. estimates that future undiscounted cash flows from the facility significantly exceed net book value. Significant assumptions used in this analysis are forward price curves for natural gas and electricity, market heat rates and production estimates.Energy Future Holdings Corp. has conservatively estimated that a sustained structural decline in natural gas prices of at least 60% from current levels would need to occur before any risk of impairment of the facility would arise, assuming market heat rates remain unchanged.

Depreciation—The depreciable lives of property, plant and equipment are based on management’s estimates/determinations of the assets’ economical useful lives. To the extent that the actual lives differ from these estimates, the amount of period depreciation charges to earnings would be impacted. Consolidated depreciation expense as a percent of average depreciable property carrying value approximated 2.3% for 2006, 2005 and 2004.

Effective January 1, 2005, the estimated depreciable lives of lignite/coal-fueled generation facilities were extended from 50 years to 60 years to better reflect their useful lives.

Effective January 1, 2004, the estimated depreciable lives of lignite/coal-fueled generation facilities were extended an average of nine years to better reflect the useful lives of the assets, and depreciation rates for the Comanche Peak nuclear generating facility were decreased as a result of an increase in the estimated lives of boiler and turbine generator components of the facility by an average of five years.

Regulatory Assets—The financial statements at December 31, 2006 and 2005, reflect total regulatory assets of $2.2 billion and $1.9 billion, respectively. These amounts include $1.3 billion and $1.5 billion, respectively, of generation-related regulatory assets recoverable by securitization (transition) bonds as discussed immediately below. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. (See disclosures in Note 25 to the 2006 year-end Financial Statements under “Regulatory Assets and Liabilities.”)

Regulatory asset stranded costs arising prior to the 1999 Restructuring Legislation became subject to recovery through issuance of $1.3 billion principal amount of transition bonds by Oncor Electric Delivery in accordance with a regulatory financing order (see Note 4 to the 2006 year-end Financial Statements). As adjusted, the carrying value of the regulatory asset upon final issuance of the bonds in 2004 represented the projected future cash flows to be recovered from REPs by Oncor Electric Delivery through revenues as a transition charge to service the principal and fixed rate interest on the bonds. The regulatory asset is being amortized to expense in an amount equal to the transition charge revenues being recognized.

Other regulatory assets that Energy Future Holdings Corp. believes are recoverable, but are subject to review and possible disallowance in a future regulatory rate case, totaled $655 million at December 31, 2006. These amounts consist primarily of employee retirement costs (see Note 21 to the 2006 year-end Financial Statements) and storm-related service recovery costs. In October 2007, many of the parties to the ongoing proceeding under Section 14.101(b) of PURA, including Oncor Electric Delivery and the PUCT staff, agreed to the terms of a proposed settlement that is subject to approval by the PUCT. The terms of the settlement include an agreement by Oncor Electric Delivery to not seek recovery of approximately $56 million of expenditures recorded as regulatory assets.

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Defined Benefit Pension Plans and Other Postretirement Employee Benefit Plans—Energy Future Holdings Corp. offers pension benefits through either a defined benefit pension plan or a cash balance plan and also offers certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from Energy Future Holdings Corp. Reported costs of providing noncontributory defined pension benefits and other postretirement employee benefits (“OPEB”) are dependent upon numerous factors, assumptions and estimates.

Benefit costs are impacted by actual employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

In accordance with accounting rules, changes in benefit obligations associated with these factors may not be immediately recognized as costs in the income statement, but are recognized in future years over the remaining average service period of plan participants. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. Pension and OPEB costs as determined under applicable accounting rules are summarized in the following table:

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Pension costs under SFAS 87	$	66		$	46		$	58
OPEB costs under SFAS 106		81			71			80
Total benefit costs	$	147		$	117		$	138
Less amounts deferred principally as a regulatory asset or property		(84	)		(58	)		(27	)
Net amounts recognized as expense	$	63		$	59		$	111

Detailed information regarding Energy Future Holdings Corp.’s pension and OPEB costs is provided in Note 21 to the 2006 year-end Financial Statements. Additional information regarding pension and OPEB plans:

• Pension and OPEB costs increased $30 million to $147 million in 2006 primarily due to a lower discount rate (5.75% in 2006 versus 6.00% in 2005) used to measure pension and OPEB obligations.

• Pension and OPEB costs decreased $21 million to $117 million in 2005 due primarily to fewer active employees following the 2004 Capgemini outsourcing and TXU Gas disposition transactions and other 2004 restructuring actions. (See Note 8 to the 2006 year-end Financial Statements.)

• A curtailment charge of $5 million is included in pension and OPEB costs in 2004 due to the effects of the Capgemini outsourcing and TXU Gas disposition transactions.

In 2006, the assumed discount rate for both the pension and OPEB obligations was 5.75%. The expected rate of return on assets was 8.75% for the pension plan and 8.67% for the OPEB plan.

Sensitivity of these costs to changes in key assumptions is as follows:

	Increase/(Decrease) in 2006 Pension and OPEB Costs
	(millions of dollars)
Assumption:
Discount rate—1% increase	$	(42	)
Discount rate—1% decrease	$	37
Expected return on assets—1% increase	$	(19	)
Expected return on assets—1% decrease	$	19

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Regulatory Recovery of Pension and OPEB Costs—In June 2005, an amendment to PURA relating to pension and OPEB costs was enacted by the Texas Legislature. This amendment provides for the recovery by Oncor Electric Delivery of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to its own employees consists largely of active and retired personnel engaged in TCEH’s activities, related to service of those additional personnel prior to the deregulation and disaggregation of Energy Future Holdings Corp.’s business effective January 1, 2002. The amendment additionally authorizes Oncor Electric Delivery to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Accordingly, in the second quarter of 2005, Oncor Electric Delivery began deferring (principally as a regulatory asset or property) additional pension and OPEB costs for the effect of the amendment, which was retroactively effective January 1, 2005. Amounts deferred are ultimately subject to regulatory approval.

Stock-Based Incentive Compensation—Under its shareholder-approved long-term incentive plans, Energy Future Holdings Corp. has provided discretionary awards to qualified management employees in the form of restricted stock and performance units payable in common stock upon vesting. The awards generally vest over a three-year period and the number of shares ultimately earned is based on the performance of Energy Future Holdings Corp.’s stock over the vesting period as compared to the stock price performance of a peer group of companies (“index method”) or as compared to a combination of the index method and established thresholds of Energy Future Holdings Corp. stock performance. Stock-based compensation expense, which is reported in selling, general and administrative (“SG&A”) expenses, totaled $27 million, $32 million and $56 million in 2006, 2005 and 2004, respectively. The expense is determined based on the grant date fair value of the awards amortized over the vesting period in accordance with SFAS 123(R). See Note 22 to the 2006 year-end Financial Statements for additional information.

The determination of the fair value of stock-based compensation awards at grant date is based on a Monte Carlo simulation. The more significant assumptions used in this valuation process are as follows:

• Expected volatility of the stock price of Energy Future Holdings Corp. and peer group companies—expected volatility is determined based on historical stock price volatilities using daily stock price returns for the three years prior to the grant date.

• The dividend rate for Energy Future Holdings Corp. and peer group companies based on the observed dividend payments over the 12 months prior to grant date.

• Risk-free rate during the three year vesting period—the rate used for the April 1, 2006 awards was the interest rate at that date for three-year U.S. Treasury securities, which was 4.83%.

• Discount for liquidation restrictions—this factor estimates the discount for lack of marketability of vested awards due to the anticipated time for the approval and issuance of the awards, the black-out period immediately after the grant and additional holding requirements imposed on senior executives. This discount is determined based on an estimation of the cost of a protective put at the award date and is calculated using the Black-Scholes option pricing model using expected volatility assumptions based on historical and implied volatility as discussed above and a risk-free rate of return over the option period.

The sensitivity effects of reasonable changes in key assumptions were not significant to the fair value of the 2006 awards.

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Results of Operations—Interim Results

Energy Future Holdings Corp. Consolidated

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.

Energy Future Holdings Corp.’s operating revenues decreased $645 million, or 24%, to $2.0 billion in 2007. The net decrease reflected the following:

• Operating revenues in the Competitive Electric segment decreased $683 million, or 29%, to $1.7 billion. The decrease was driven by a $396 million decrease in retail electricity revenues and $370 million in increased losses from risk management and trading activities. The decrease in retail electricity revenues reflected lower volumes driven by cooler, below normal weather and a net loss of customers due to competitive activity. The retail revenue decrease also reflected residential price discount actions. The losses from risk management and trading activities reflected unrealized mark-to-market losses on positions in the long-term hedging program due to higher forward market prices of natural gas, with higher prices for all hedged future periods beyond 2008. Also, see discussion above under “—Significant Developments—Long-term Hedging Program.”

• Operating revenues in the Regulated Delivery segment decreased $15 million, or 2%, to $589 million. The revenue decrease reflected lower delivered volumes primarily reflecting the effects of cooler, below normal weather, partially offset by higher transmission and delivery tariffs and installation revenues in 2007 for equipment installation services to support the broadband-over-powerlines initiative.

• A decline in the net intercompany sales elimination of $53 million primarily reflected lower sales by Oncor Electric Delivery to REP subsidiaries of TCEH, while its sales to nonaffiliated REPs increased.

Gross Margin

	Three Months Ended June 30,
	2007		% of Revenue		2006		% of Revenue
	(millions of dollars)
Operating revenues	$	2,022	100	%	$	2,667	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		739	36			658	25
Operating costs		368	18			341	13
Depreciation and amortization		196	10			202	7
Gross margin	$	719	36	%	$	1,466	55	%

Gross margin is considered a key operating metric as its changes measure the effect of movements in sales volumes and pricing versus the variable and fixed costs to generate, purchase and deliver electricity.

Gross margin decreased $747 million, or 51%, to $719 million in 2007.

• The Competitive Electric segment’s gross margin decreased $719 million, or 61%, to $452 million. The gross margin decrease reflected the declines in revenues and the combined effect of lower nuclear generation volumes (due to a planned outage) and increased higher-cost purchased power volumes.

• The Regulated Delivery segment’s gross margin decreased $26 million, or 9%, to $268 million driven by the decline in revenues and higher third-party transmission fees.

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Operating costs increased $27 million, or 8%, to $368 million in 2007.

• The Competitive Electric segment’s operating costs increased $11 million, or 7%, reflecting higher generation maintenance costs, insurance costs and property taxes, partially offset by lower costs resulting from the outsourcing of certain generation technical support services.

• The Regulated Delivery segment’s operating costs increased $13 million, or 7%, reflecting equipment installation costs to support the broadband-over-powerlines initiative and higher third-party transmission fees.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants and the delivery system shown in the gross margin table above) decreased $7 million, or 3%, to $200 million in 2007. The decreased expense reflects lower amortization of the regulatory assets associated with the securitization bonds (offset in revenues) and lower depreciation due to the impairment of natural gas-fueled generation plants in the second quarter of 2006.

SG&A expenses increased $46 million, or 25%, to $227 million in 2007. The increase reflected:

• $12 million in increased retail marketing expenses;

• $11 million in higher professional services costs, due primarily to consulting fees for marketing/strategic projects and retail billing and customer care systems enhancements;

• $8 million increase in salary and benefit costs driven largely by an increase in staffing in retail operations;

• $5 million in higher incentive compensation;

• $3 million in higher outsourced service provider costs due to contract adjustments;

• $3 million for expenses related to rebranding of the Oncor Electric Delivery Company name; and

• $2 million in increased contributions primarily for the Energy Aid (low-income customer assistance) program,

partially offset by $3 million in lower bad debt expense reflecting a decrease in delinquencies and lower accounts receivable balances.

Other income totaled $16 million in 2007 and $42 million in 2006. Other deductions totaled $122 million in 2007 and a $221 million in 2006. See Note 6 to the June 30, 2007 Financial Statements for detail of other income and deductions. The 2007 other deductions amount includes an additional charge of $82 million related to the suspension of the development of eight coal-fueled generation units. (See Note 2 to the June 30, 2007 Financial Statements.) The 2006 other deductions amount includes a $198 million impairment charge related to the natural gas-fueled generation plants.

Interest expense and related charges increased $3 million, or 1%, to $221 million in 2007 reflecting $21 million due to higher average borrowings, partially offset by $14 million in increased capitalized interest and $4 million from lower average interest rates.

Income tax benefit on income from continuing operations totaled $21 million in 2007 compared to income tax expense of $310 million on income from continuing operations in 2006. Excluding the $51 million deferred tax benefit in 2007 and the $41 million deferred tax charge in 2006 related to the Texas margin tax as described in Note 4 to the June 30, 2007 Financial Statements, the effective income tax rate was 33.7% in 2007 (on a small income base) compared to 33.3% in 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion.) The increased effective rate reflects higher interest accrued related to uncertain tax positions partially offset by the effects on the rate of the significant unrealized mark-to-market net losses associated with the long-term hedging program.

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Income from continuing operations (an after-tax measure) decreased $387 million to $110 million in 2007.

• Earnings in the Competitive Electric segment decreased $332 million to $129 million driven by the decline in gross margin and higher SG&A expenses, partially offset by lower other deductions and the Texas margin tax benefit.

• Earnings in the Regulated Delivery segment decreased $32 million, or 37%, to $54 million primarily driven by lower operating revenue, higher SG&A expenses and third-party transmission fees and costs associated with the cities rate settlement.

• Corporate and Other net expenses totaled $73 million in 2007 and $50 million in 2006. The amounts in 2007 and 2006 consist principally of recurring interest expense on outstanding debt and affiliate borrowings at the Energy Future Holdings Corp. level, as well as corporate general and administrative expenses. The increase of $23 million primarily reflects:

• a $17 million after-tax favorable settlement in 2006 of a telecommunications contract dispute;

• $8 million after-tax in higher accrued interest related to uncertain tax positions;

• $7 million after-tax in increased SG&A expenses driven by higher compensation and consulting expenses;

• a $5 million after-tax write-off in 2007 of deferred costs associated with the suspended Infrastrux joint venture; and

• $4 million after-tax in financial advisory, legal and other professional fees in 2007 directly related to the Merger,

partially offset by the $21 million deferred tax benefit in 2007 related to the Texas margin tax as described in Note 4 to the June 30, 2007 Financial Statements.

Net pension and postretirement benefit costs reduced income from continuing operations by $8 million in 2007 and $10 million in 2006.

Energy Future Holdings Corp. Consolidated

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Energy Future Holdings Corp.’s operating revenues decreased $1.3 billion, or 26%, to $3.7 billion in 2007. The net decrease reflected the following:

• Operating revenues in the Competitive Electric segment decreased $1.4 billion, or 32%, to $3.0 billion. The decrease was driven by $1.0 billion in increased losses from risk management and trading activities and a $354 million decrease in retail electricity revenues. The losses from risk management and trading activities reflected unrealized mark-to-market losses on positions in the long-term hedging program due to higher forward market prices of natural gas, with higher prices for all hedged future periods beyond 2008. Also, see discussion above under “—Significant Developments—Long-term Hedging Program.” The decrease in retail electricity revenues reflected lower volumes driven by the effects of a net loss of customers due to competitive activity and cooler, below normal weather. The retail revenue decrease also reflected residential price discount actions.

• Operating revenues in the Regulated Delivery segment increased $41 million, or 4%, to $1.2 billion. The revenue increase reflected higher distribution and transmission tariffs, revenues in 2007 for equipment installation services to support the broadband-over-powerlines initiative and growth in points of delivery.

• A decline in the net intercompany sales elimination of $55 million reflected lower sales by Oncor Electric Delivery to REP subsidiaries of TCEH, while its sales to nonaffiliated REPs increased.

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Gross Margin

	Six Months Ended June 30,
	2007		% of Revenue		2006		% of Revenue
	(millions of dollars)
Operating revenues	$	3,691	100	%	$	4,971	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,404	38			1,179	24
Operating costs		714	19			684	14
Depreciation and amortization		395	11			404	8
Gross margin	$	1,178	32	%	$	2,704	54	%

Gross margin decreased $1.5 billion, or 56%, to $1.2 billion in 2007.

• The Competitive Electric segment’s gross margin decreased $1.5 billion, or 72%, to $609 million. The gross margin decrease reflected the declines in revenues and higher average cost of electricity sold due primarily to a decrease in baseload generation volumes (largely reflecting planned outages) and increased purchased power volumes.

• The Regulated Delivery segment’s gross margin increased $21 million, or 4%, to $572 million driven by higher revenues, partially offset by higher third-party transmission fees.

Operating costs increased $30 million, or 4%, to $714 million in 2007.

• The Competitive Electric segment’s operating costs increased $8 million, or 3%, reflecting $20 million in higher generation maintenance costs largely due to the scheduled outage of one of the nuclear generation units, partially offset by $11 million in lower costs associated with generation technical support outsourcing service agreements.

• The Regulated Delivery segment’s operating costs increased $17 million, or 4%, reflecting equipment installation costs in 2007 to support the broadband-over-powerlines initiative and higher third-party transmission fees.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants and the delivery system shown in the Gross Margin table above) decreased $10 million, or 2%, to $403 million in 2007. The decreased expense reflects lower depreciation due to the impairment of natural gas-fueled generation plants in the second quarter of 2006, lower expense associated with mining reclamation obligations and lower amortization of the regulatory assets associated with the securitization bonds (offset in revenues), partially offset by normal additions of property, plant and equipment and additional mining development amortization.

SG&A expenses increased $77 million, or 21%, to $447 million in 2007. The increase reflected:

• $20 million in costs associated with the generation development program that was initiated in the second quarter of 2006, principally salaries and consulting expenses;

• $18 million in increased retail marketing expenses;

• $15 million in higher professional services costs, due primarily to consulting fees for retail billing and customer care systems enhancements and marketing/strategic projects;

• $10 million in higher outsourced service provider costs due to contract adjustments;

• $7 million increase in salary and benefit costs driven largely by an increase in staffing in retail operations;

• $4 million in higher incentive compensation;

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• $3 million for expenses related to rebranding of the Oncor Electric Delivery Company name; and

• $3 million in increased contributions primarily for the Energy Aid (low-income customer assistance) program,

partially offset by the effect of $12 million in executive severance expense in 2006.

Other income totaled $45 million in 2007 and $55 million in 2006. Other deductions totaled $891 million in 2007 and $221 million in 2006. The 2007 other deductions amount includes charges of $795 million related to the suspension of the development of eight coal-fueled generation units (see Note 2 to the June 30, 2007 Financial Statements). The 2006 other deductions amount includes a $198 million impairment charge related to natural gas-fired generation plants. See Note 6 to the June 30, 2007 Financial Statements for detail of other income and deductions.

Interest expense and related charges decreased $13 million, or 3%, to $418 million in 2007 reflecting $31 million in increased capitalized interest and $8 million from lower average interest rates, partially offset by $26 million due to higher average borrowings.

Income tax benefit on loss from continuing operations totaled $294 million in 2007 compared to income tax expense on income from continuing operations of $561 million in 2006. Excluding the $51 million deferred tax benefit in 2007 and the $41 million deferred tax charge in 2006 related to the Texas margin tax as described in Note 4 to the June 30, 2007 Financial Statements, the effective income tax rate was 35.6% on a loss in 2007 compared to 33.0% on income in 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion.) The increased effective rate reflects the impact of the significant unrealized mark-to-market net losses associated with the long-term hedging program as well as the charge related to the suspended generation development activities. These effects were partially offset by higher interest accrued related to uncertain tax positions and higher income-based taxes arising from enactment of the Texas margin tax.

Results from continuing operations (an after-tax measure) decreased $1.4 billion to a loss of $388 million in 2007.

• Results in the Competitive Electric segment decreased $1.3 billion to a loss of $342 million driven by the decline in gross margin and the charges related to the suspension of the development of eight coal-fueled generation units.

• Earnings in the Regulated Delivery segment decreased $11 million, or 7%, to $140 million primarily driven by costs associated with the cities rate settlement, higher interest expense and higher third-party transmission fees, partially offset by higher operating revenues.

• Corporate and Other net expenses totaled $186 million in 2007 and $119 million in 2006. The amounts in 2007 and 2006 consist principally of recurring interest expense on outstanding debt and affiliate borrowings at Energy Future Holdings Corp., as well as corporate general and administrative expenses. The increase of $67 million primarily reflects:

• $20 million after-tax in financial advisory, legal and other professional fees in 2007 directly related to the Merger;

• a 2007 write-off of $19 million after-tax in previously deferred costs related to anticipated strategic transactions (including expected financings) that are no longer expected to be completed as a result of the Merger;

• a $17 million after-tax favorable settlement in 2006 of a telecommunications contract dispute;

• $16 million after-tax in higher accrued interest related to uncertain tax positions; and

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• $9 million after-tax in higher SG&A expenses driven by higher compensation and consulting expenses,

partially offset by the $21 million deferred tax benefit in 2007 related to the Texas margin tax as described in Note 4 to the June 30, 2007 Financial Statements.

Net pension and postretirement benefit costs reduced results from continuing operations by $19 million in 2007 and $21 million in 2006.

Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the six months ended June 30, 2007. The net changes in these assets and liabilities, excluding “other activity” as described below, represent the net effect of mark-to-market accounting for positions in the commodity contract portfolio, which excludes positions that are subject to cash flow hedge accounting. For the six months ended June 30, 2007, this effect totaled $1.3 billion in unrealized net losses, which represented $1.3 billion in net losses on unsettled positions, principally those positions entered into as part of the long-term hedging positions that were dedesignated as cash flow hedges for accounting purposes, and $7 million in reversals of net losses recognized in prior periods on positions settled in the current period. These positions represent both economic hedging and trading activities.

	Six Months Ended June 30, 2007
	(millions of dollars)
Net commodity contract liability at beginning of period	$	23
Settlements of positions included in the opening balance(1)		(7	)
Unrealized mark-to-market valuations of positions held at end of period(2)		1,283
Other activity(3)		(143	)
Net commodity contract liability at end of period	$	1,156

(1) Represents reversals of unrealized mark-to-market valuations of these positions recognized in net income prior to the beginning of the period, to offset gains and losses realized upon settlement of the positions in the current period.

(2) Includes mark-to-market effects of positions dedesignated as cash flow hedges (see discussion above under “—Significant Developments—Long-term Hedging Program”). Also includes $164 million in losses and a $30 million gain recorded at contract inception dates (see Note 12 to the June 30, 2007 Financial Statements).

(3) These amounts have not been recognized in prior and current year mark-to-market earnings. Includes initial values of positions involving the receipt or payment of cash or other consideration such as option premiums paid and received. Activity in 2007 included payments of $39 million related to natural gas physical swap transactions and a $102 million premium paid in 2007 related to a structured economic hedge transaction in the long-term hedging program.

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In addition to the net effect of recording unrealized mark-to-market gains and losses that are reflected in the table above, similar effects arise in the recording of unrealized ineffectiveness gains and losses associated with commodity-related cash flow hedges. These effects, which include reversals of previously recorded unrealized ineffectiveness gains and losses to offset realized gains and losses upon settlement, are reflected as changes in cash flow hedge and other derivative assets and liabilities (see Note 12 to the June 30, 2007 Financial Statements). The total net effect of recording unrealized gains and losses related to commodity contracts under SFAS 133 is summarized as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(millions of dollars)
Unrealized losses related to contracts marked-to-market	$	(413	)	$	(121	)	$	(1,276	)	$	(115	)
Ineffectiveness gains (losses) related to cash flow hedges(a)		(5	)		145			94			144
Total unrealized gains (losses) related to commodity contracts	$	(418	)	$	24		$	(1,182	)	$	29

(a) See Note 12 to the June 30, 2007 Financial Statements.

These amounts are reported in the “risk management and trading activities” component of revenues.

Maturity Table—Of the net commodity contract liability balance above at June 30, 2007, the amount representing unrealized mark-to-market net losses that have been recognized in current and prior years’ earnings totals $1.2 billion. Partially offsetting this net liability is a net asset of $51 million included in the June 30, 2007 balance sheet that is comprised principally of amounts representing current and prior years’ net payments of cash or other consideration, including $101 million of net option payments and $47 million in net receipts of natural gas related to physical swap transactions. The following table presents the unrealized net commodity contract liability arising from mark-to-market accounting as of June 30, 2007, scheduled by contractual settlement dates of the underlying positions.

	Maturity Dates of Unrealized Net Commodity Contract Liabilities at June 30, 2007
	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
	(millions of dollars)
Source of fair value
Prices actively quoted	$	16		$	(200	)	$	(248	)	$	(23	)	$	(455	)
Prices provided by other external sources(a)		6			(253	)		(353	)		(89	)		(689	)
Prices based on models(b)		(45	)		(18	)		—			—			(63	)
Total	$	(23	)	$	(471	)	$	(601	)	$	(112	)	$	(1,207	)
Percentage of total fair value		2	%		39	%		50	%		9	%		100	%

(a) Includes “day one” losses of $138 million associated with hedge transactions and a “day one” gain of $30 million associated with a long-term power purchase agreement.

(b) Includes “day one” loss of $26 million associated with a hedge transaction.

The “prices actively quoted” category reflects only exchange traded contracts with active quotes available. The “prices provided by other external sources” category represents forward commodity positions at locations for which over-the-counter broker quotes are available. Over-the-counter quotes for power in ERCOT generally extend through 2011 and over-the-counter quotes for natural gas generally extend through 2015, depending upon delivery point. The “prices based on models” category contains the value of all nonexchange traded options, valued using option pricing models. In addition, this category contains other contractual arrangements which may

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have both forward and option components. In many instances, these contracts can be broken down into their component parts and each component valued separately. Components valued as forward commodity positions are included in the “prices provided by other external sources” category. Components valued as options are included in the “prices based on models” category.

Competitive Electric Segment

Financial Results

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(millions of dollars)
Operating revenues	$	1,666		$	2,349		$	2,983		$	4,359
Costs and expenses:
Fuel, purchased power costs and delivery fees		971			943			1,902			1,733
Operating costs		163			152			314			306
Depreciation and amortization		82			84			161			169
Selling, general and administrative expenses		155			128			312			249
Franchise and revenue-based taxes		27			27			53			54
Other income		—			(1	)		(9	)		(1	)
Other deductions		93			205			808			195
Interest income		(85	)		(45	)		(162	)		(76	)
Interest expense and related charges		123			102			212			203
Total costs and expenses		1,529			1,595			3,591			2,832
Income (loss) before income taxes		137			754			(608	)		1,527
Income tax expense (benefit)		8			293			(266	)		546
Net income (loss) from continuing operations	$	129		$	461		$	(342	)	$	981

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Sales Volume Data

	Three Months Ended June 30,						Six Months Ended June 30,
	2007		2006		Change %		2007		2006		Change %
Sales volumes:
Retail electricity sales volumes (GWh):
Historical service territory:
Residential	5,072		6,825		(25.7	)	10,719		12,057		(11.1	)
Small business(a)	1,537		2,068		(25.7	)	3,180		3,795		(16.2	)
Total historical service territory	6,609		8,893		(25.7	)	13,899		15,852		(12.3	)
Other territories:
Residential	1,010		1,018		(0.8	)	1,748		1,629		7.3
Small business(a)	204		169		20.7		368		301		22.3
Total other territories	1,214		1,187		2.3		2,116		1,930		9.6
Large business and other customers	3,653		3,552		2.8		7,043		6,785		3.8
Total retail electricity	11,476		13,632		(15.8	)	23,058		24,567		(6.1	)
Wholesale electricity sales volumes	9,290		7,852		18.3		17,977		15,705		14.5
Net sales (purchases) of balancing electricity to/from ERCOT	302		(267	)	—		626		1,165		(46.3	)
Total sales volumes	21,068		21,217		(0.7	)	41,661		41,437		0.5
Average volume (kWh) per retail customer(b):
Residential	3,299		4,012		(17.8	)	6,731		6,975		(3.5	)
Small business	6,676		7,990		(16.4	)	13,476		14,460		(6.8	)
Large business and other customers	100,336		70,256		42.8		175,727		130,966		34.2
Weather (service territory average)—percent of normal(c):
Percent of normal:
Cooling degree days	85.3	%	131.0	%			88.8	%	135.9	%

(a) Customers with demand of less than 1 MW.

(b) Calculated using average number of customers for period.

(c) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the U.S. Department of Commerce).

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Customer Count Data

	June 30,
	2007	2006	Change %
Customer counts:
Retail electricity customers (end of period and in thousands)(a):
Historical service territory:
Residential	1,560	1,716	(9.1	)%
Small business(b)	248	271	(8.5	)
Total historical service territory	1,808	1,987	(9.0	)
Other territories:
Residential	273	227	20.3
Small business(b)	11	7	57.1
Total other territories	284	234	21.4
All territories:
Residential	1,833	1,943	(5.7	)
Small business(b)	259	278	(6.8	)
Total all territories	2,092	2,221	(5.8	)
Large business and other customers	36	49	(26.5	)
Total retail electricity customers	2,128	2,270	(6.3	)%

(a) Based on number of meters.

(b) Customers with demand of less than 1MW.

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Revenue and Market Share Data

	Three Months Ended June 30,								Six Months Ended June 30,
	2007			2006			Change %		2007			2006			Change %
	(millions of dollars)
Operating revenues:
Retail electricity revenues:
Historical service territory:
Residential	$	700		$	1,008		(30.6	)%	$	1,484		$	1,753		(15.3	)%
Small business(a)		230			309		(25.6	)		468			566		(17.3	)
Total historical service territory		930			1,317		(29.4	)		1,952			2,319		(15.8	)
Other territories:
Residential		141			160		(11.9	)		249			248		0.4
Small business(a)		26			20		30.0			46			36		27.8
Total other territories		167			180		(7.2	)		295			284		3.9
Large business and other customers		343			339		1.2			657			655		0.3
Total retail electricity revenues		1,440			1,836		(21.6	)		2,904			3,258		(10.9	)
Wholesale electricity revenues		535			479		11.7			982			956		2.7
Net sales (purchases) of balancing electricity to/from ERCOT		—			(32	)	—			9			26		(65.4	)
Net losses from risk management and trading activities		(383	)		(13	)	—			(1,069	)		(57	)	—
Other operating revenues		74			79		(6.3	)		157			176		(10.8	)
Total operating revenues	$	1,666		$	2,349		(29.1	)%	$	2,983		$	4,359		(31.6	)%
Risk management and trading activities:
Realized net gains (losses) on settled positions(b)	$	35		$	(38	)			$	113		$	(86	)
Reversal of prior periods’ unrealized net (gains) losses on positions settled in current period		(21	)		2					(13	)		38
Other unrealized net gains (losses), including cash flow hedge ineffectiveness		(397	)		23					(1,169	)		(9	)
Total net losses	$	(383	)	$	(13	)			$	(1,069	)	$	(57	)
Average revenues per MWh:
Residential	$	138.36		$	148.85		(7.0	)%	$	139.01		$	146.23		(4.9	)%
Estimated share of ERCOT retail markets(c):
Historical service territory:
Residential										62	%		69	%
Small business										61	%		68	%
Total ERCOT:
Residential										35	%		38	%
Small business										25	%		28	%
Large business and other customers										11	%		17	%

(a) Customers with demand of less than 1 MW.

(b) Includes physical commodity trading activity not subject to mark-to-market accounting of $5 million in net losses in the second quarter of both 2007 and 2006, and $6 million and $15 million in net losses in the six months ended June 30, 2007 and 2006, respectively.

(c) Based on number of meters. Estimated market share is based on the number of customers that have choice.

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Production, Purchased Power and Delivery Cost Data

	Three Months Ended June 30,								Six Months Ended June 30,
	2007			2006			Change %		2007			2006			Change %
	(millions of dollars, except percentages and average costs per month)
Fuel, purchased power costs and delivery fees:
Nuclear fuel	$	21		$	22		(4.5	)	$	39		$	43		(9.3	)%
Lignite/coal		152			113		34.5			290			229		26.6
Total baseload fuel		173			135		28.1			329			272		21.0
Natural gas fuel and purchased power		435			421		3.3			818			689		18.7
Other costs		72			50		44.0			146			122		19.7
Fuel and purchased power costs		680			606		12.2			1,293			1,083		19.4
Delivery fees(a)		291			337		(13.6	)		609			650		(6.3	)
Total	$	971		$	943		3.0	%	$	1,902		$	1,733		9.8	%
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	4.64		$	4.25		9.2	%	$	4.55		$	4.24		7.3	%
Lignite/coal(b)	$	16.14		$	12.67		27.4	%	$	15.62		$	12.33		26.7	%
Natural gas fuel and purchased power	$	62.86		$	63.40		(0.9	)%	$	61.37		$	61.76		(0.6	)%
Delivery fees per MWh	$	24.90		$	24.51		1.6	%	$	25.94		$	26.18		(0.9	)%
Production and purchased power volumes (GWh):
Nuclear		4,492			5,098		(11.9	)%		8,555			10,178		(15.9	)%
Lignite/coal		10,211			10,044		1.7			20,197			20,918		(3.4	)
Total baseload generation		14,703			15,142		(2.9	)		28,752			31,096		(7.5	)
Natural gas-fueled generation		633			1,350		(53.1	)		1,382			1,539		(10.2	)
Purchased power		6,287			5,291		18.8			11,957			9,616		24.3
Total energy supply		21,623			21,783		(0.7	)		42,091			42,251		(0.4	)
Less line loss and power imbalances		555			566		(1.9	)		430			814		(47.2	)
Net energy supply volumes		21,068			21,217		(0.7	)%		41,661			41,437		0.5	%
Baseload capacity factors (%):
Nuclear		89.6	%		102.0	%	(12.2	)%		85.8	%		102.3	%	(16.1	)%
Lignite/coal		85.9	%		82.4	%	4.2	%		86.6	%		86.4	%	0.2	%
Total baseload		87.0	%		88.0	%	(1.1	)%		86.3	%		90.9	%	(5.1	)%

(a) Includes delivery fee charges from Oncor Electric Delivery that are eliminated in consolidation.

(b) Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs.

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See Note 2 to the June 30, 2007 Financial Statements for discussion of potential charges in future periods in connection with the suspended development of eight coal-fueled generation facilities.

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

Operating revenues decreased $683 million, or 29%, as follows:

	Three Months Ended June 30,						Increase (Decrease)
	2007			2006
	(millions of dollars)
Retail electricity revenues	$	1,440		$	1,836		$	(396	)
Wholesale electricity revenues		535			479			56
Wholesale balancing activities		—			(32	)		32
Net losses from risk management and trading activities		(383	)		(13	)		(370	)
Other operating revenues		74			79			(5	)
Total operating revenues	$	1,666		$	2,349		$	(683	)

The $396 million, or 22%, decrease in retail electricity revenues reflected the following:

• Lower retail volumes contributed $290 million to the revenue decrease. Residential and small business volumes in the historical service territory decreased 26% reflecting cooler, below normal weather that drove an 18% decrease in average consumption per customer and the effects of a net loss of customers due to competitive activity.

• Lower average pricing (including customer mix effects) contributed $106 million to the revenue decrease. Lower average retail pricing reflected new competitive product offerings, the effect of a six percent price discount, effective with meter reads on March 27, 2007, and an additional four percent price discount, effective with meter reads on June 8, 2007, to those residential customers in the historical service territory with month-to-month service plans and a rate equivalent to the former price-to-beat rate. Average prices in the large business market decreased 2% primarily reflecting a change in customer mix.

• Total retail electricity customer counts at June 30, 2007 declined 6% from June 30, 2006. Total residential and small business customer counts in the historical service territory declined 9% and in all combined territories declined 6%.

Wholesale electricity revenues increased $56 million, or 12%. Volume growth of 18% contributed $88 million to the increase, which was partially offset by a $32 million pricing impact as average wholesale prices declined 6% reflecting lower natural gas prices. The volume growth was due in part to the decline in retail volumes associated with competitive activity.

Wholesale balancing activity comparisons are not meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, that are highly variable.

Results from risk management and trading activities include realized and unrealized gains and losses associated with financial instruments used for economic hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading purposes. Because most of the hedging and risk management activities are intended to mitigate the risk of future commodity price movements on revenues and fuel and purchased power costs, the changes in such results should not be viewed in isolation, but rather

72

taken together with the effects of pricing and cost changes on gross margin. Following is an analysis of activities in the second quarter of 2007:

Results associated with the long-term hedging program

• $400 million in unrealized mark-to-market net losses, which includes $386 million in net losses on unsettled positions and $14 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period;

• $63 million in unrealized “day one” losses on a related series of commodity price hedges entered into at below-market prices;

• $3 million in unrealized cash flow hedge ineffectiveness net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period; and

• $34 million in realized net gains that offset hedged electricity revenues recognized in the current period.

Results associated with other risk management and trading activities

• $33 million in unrealized net gains on economic hedge positions, which includes $40 million in net gains on unsettled positions and $7 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period;

• $30 million “day one” gain on a long-term power purchase agreement; and

• $14 million in other net losses, including unrealized losses on commodity trading positions.

Gross Margin

	Three Months Ended June 30,
	2007		% of Revenue		2006		% of Revenue
	(millions of dollars)
Operating revenues	$	1,666	100	%	$	2,349	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		971	58			943	40
Generation plant operating costs		163	10			152	6
Depreciation and amortization		80	5			83	4
Gross margin	$	452	27	%	$	1,171	50	%

Gross margin decreased $719 million, or 61%, to $452 million in 2007. The decrease reflected $370 million unfavorable change in results from risk management and trading activities, a 26% decrease in residential and small business volumes in the historical service territory and lower retail electricity average pricing driven by residential price discounts. Lower gross margin also reflected higher average cost of electricity sold due to a 12% decrease in nuclear generation volumes and increased purchased power volumes. In addition, average fuel cost per MWh generated increased 5% as the impact of inefficiencies in lignite mining operations due to significantly above normal rainfall was partially offset by the favorable effect of lower utilization of natural gas-fueled plants.

The decline in nuclear generation volumes was due to a planned refueling and major maintenance outage for one of the two Comanche Peak units. Maintenance work during the 55-day outage, which ended in late April 2007, included the replacement of the unit’s steam generators and reactor vessel head.

Gross margin as a percent of revenues decreased 23 percentage points to 27%. The decline reflected:

• the effect of results from risk management and trading activities, including unrealized mark-to-market losses on positions in the long-term hedging program (12 percentage point margin decrease);

73

• the effect of a decrease in residential and small business sales volumes and an increase in wholesale sales volumes (six percentage point margin decrease);

• the effect of lower average retail electricity pricing (two percentage point margin decrease); and

• the effect of lower generation volumes and higher purchased power volumes (one percentage point margin decrease).

Operating costs increased $11 million, or 7%, to $163 million in 2007. The increase reflected:

• $6 million in higher generation maintenance costs largely due to the scheduled outage of one of the nuclear generation units;

• $6 million in higher insurance costs, principally property-related; and

• $5 million in higher property taxes reflecting higher valuations for 2007,

partially offset by $7 million in lower costs associated with the outsourcing of certain generation technical support services.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) decreased $2 million, or 2%, to $82 million primarily reflecting lower depreciation due to the impairment of natural gas-fueled generation plants in the second quarter of 2006.

SG&A expenses increased $27 million, or 21%, to $155 million in 2007. The increase reflected:

• $12 million in increased retail marketing expenses;

• $8 million in higher salary and benefit costs primarily driven by an increase in staffing in retail operations;

• $6 million in higher professional fees primarily for marketing/strategic projects and retail billing and customer care systems enhancements;

• $2 million in higher incentive compensation expense; and

• $2 million in increased contributions primarily for the Energy Aid (low-income customer assistance) program,

partially offset by $3 million in lower bad debt expense driven by a decrease in delinquencies and lower accounts receivable balances due to the milder winter weather.

Other deductions totaled $93 million in 2007 and $205 million in 2006. The 2007 amount includes a charge of $82 million in connection with the suspension of the development of eight coal-fueled generation units (see Note 2 to the June 30, 2007 Financial Statements) and $5 million in connection with the settlement of the PUCT’s investigation regarding TXU Energy’s renewal process for certain small and medium business customers on term service plans. The 2006 amount includes a charge of $198 million to write down the natural gas-fueled generation plants to fair value.

Interest income increased $40 million to $85 million in 2007 reflecting $21 million due to higher average advances to affiliates and $19 million due to higher average rates on the advances.

Interest expense and related charges increased by $21 million, or 21%, to $123 million in 2007. The increase reflected $18 million due to higher average borrowings and $16 million due to higher average interest rates, partially offset by $13 million in increased capitalized interest.

Income tax expense totaled $8 million in 2007 compared to $293 million in 2006. Excluding the $30 million deferred tax benefit in 2007 and the $42 million deferred tax charge in 2006 related to the Texas margin tax as

74

described in Note 4 to the June 30, 2007 Financial Statements, the effective income tax rate was 27.7% in 2007 on a small income base compared to 33.2% in 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion.) The lower effective rate reflected the impact of the significant unrealized mark-to-market net losses associated with the long-term hedging program, partially offset by higher interest accrued related to uncertain tax positions.

Income from continuing operations decreased $332 million to $129 million in 2007 driven by the decline in gross margin and higher SG&A expenses, partially offset by lower other deductions and the Texas margin tax benefit.

Competitive Electric Segment

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Operating revenues decreased $1.4 billion, or 32%, as follows:

	Six Months Ended June 30,						Increase (Decrease)
	2007			2006
	(millions of dollars)
Retail electricity revenues	$	2,904		$	3,258		$	(354	)
Wholesale electricity revenues		982			956			26
Wholesale balancing activities		9			26			(17	)
Net losses from risk management and trading activities		(1,069	)		(57	)		(1,012	)
Other operating revenues		157			176			(19	)
Total operating revenues	$	2,983		$	4,359		$	(1,376	)

The $354 million, or 11%, decrease in retail electricity revenues reflected the following:

• Lower retail volumes contributed $200 million to the revenue decrease. Residential and small business volumes in the historical service territory decreased 12% reflecting the effects of a net loss of customers due to competitive activity and lower average consumption per customer of 4% reflecting the cooler, below normal weather in the second quarter of 2007. Large business market volumes increased 4% reflecting a change in customer mix.

• Lower average pricing (including customer mix effects) contributed $154 million to the revenue decrease. Lower average retail pricing reflected new competitive product offerings, the effect of a six percent price discount, effective with meter reads on March 27, 2007, and an additional four percent price discount, effective with meter reads on June 8, 2007, to those residential customers in the historical service territory with month-to-month service plans and a rate equivalent to the former price-to-beat rate. Average prices in the large business market decreased 3% primarily reflecting a change in customer mix.

• Total retail electricity customer counts at June 30, 2007 declined 6% from June 30, 2006. Total residential and small business customer counts in the historical service territory declined 9% and in all combined territories declined 6%.

Wholesale electricity revenues increased $26 million, or 3%. Volume growth of 14% contributed $138 million to the increase, which was partially offset by a $112 million pricing impact as average wholesale prices declined 10% reflecting lower natural gas prices. The volume growth was due in part to the decline in retail volumes associated with competitive activity.

Wholesale balancing activity comparisons are not meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, that are highly variable.

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Results from risk management and trading activities include realized and unrealized gains and losses associated with financial instruments used for economic hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading purposes. Because most of the hedging and risk management activities are intended to mitigate the risk of future commodity price movements on revenues and fuel and purchased power costs, the changes in such results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on gross margin. Following is an analysis of activities for the six months ended June 30, 2007:

Results associated with the long-term hedging program

• $1.099 billion in unrealized mark-to-market net losses, which includes $1.130 billion in net losses on unsettled positions and $31 million in net gains that represent reversals of previously recorded unrealized net losses on positions settled in the current period;

• $96 million in unrealized cash flow hedge ineffectiveness net gains, which includes $114 million in net gains on unsettled positions and $18 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period;

• $160 million in unrealized “day one” losses on large positions entered into at below-market prices; and

• $93 million in realized net gains that offset hedged electricity revenues recognized in the current period.

Results associated with other risk management and trading activities

• $50 million in unrealized net losses on commodity trading positions, which includes $22 million in net losses on unsettled positions and $28 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period;

• $30 million “day one” gain on a long-term power purchase agreement; and

• $18 million in other gains, driven by realized net gains on settlement of trading positions.

Gross Margin

	Six Months Ended June 30,
	2007		% of Revenue		2006		% of Revenue
	(millions of dollars)
Operating revenues	$	2,983	100	%	$	4,359	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,902	64			1,733	40
Generation plant operating costs		314	11			306	7
Depreciation and amortization		158	5			166	4
Gross margin	$	609	20	%	$	2,154	49	%

Gross margin decreased $1.5 billion, or 72%, to $609 million in 2007. The decrease reflected $1.0 billion unfavorable change in results from risk management and trading activities, a 12% decrease in residential and small business volumes in the historical service territory and lower average retail electricity pricing driven by residential price discounts. Lower gross margin also reflected higher average cost of electricity sold due to an 8% decrease in baseload generation volumes and increased purchased power volumes. In addition, average fuel cost per MWh generated increased 23% due primarily to inefficiencies in lignite mining operations caused by significantly above normal rainfall.

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The decline in baseload generation volumes was primarily due to a planned refueling and major maintenance outage for one of the two Comanche Peak nuclear units, which resulted in a 16% decline in nuclear generation volumes. Maintenance work during the 55-day outage, which ended in late April 2007, included the replacement of the unit’s steam generators and reactor vessel head.

Gross margin as a percent of revenues decreased 29 percentage points to 20%. The decline reflected:

• the effect of results from risk management and trading activities, including net unrealized mark-to-market losses on positions in the long-term hedging program (19 percentage point margin decrease);

• the effect of a decrease in residential and small business sales volumes and an increase in wholesale sales volumes (three percentage point margin decrease);

• the effect of lower average retail electricity pricing (two percentage point margin decrease);

• the effect of lower generation volumes and higher purchased power volumes (two percentage point margin decrease); and

• the effect of higher average fuel costs (one percentage point margin decrease).

Operating costs increased $8 million, or 3%, to $314 million in 2007. The increase reflected $20 million in higher generation maintenance costs largely due to the scheduled outage of one of the nuclear generation units, partially offset by $11 million in lower costs in 2007 associated with generation technical support outsourcing service agreements.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the Gross Margin table above) decreased $8 million, or 5%, to $161 million driven by lower depreciation due to the impairment of natural gas-fueled generation plants in the second quarter of 2006 and lower expense associated with mining reclamation obligations.

SG&A expenses increased $63 million, or 25%, to $312 million in 2007. The increase reflected:

• $20 million in costs associated with the generation development program, principally salaries and consulting expenses;

• $18 million in increased retail marketing expenses;

• $12 million in higher professional fees primarily for retail billing and customer care systems enhancements and marketing/strategic projects;

• $10 million in higher salary and benefit costs primarily driven by an increase in staffing in retail operations;

• $7 million in higher costs due to reallocation of Capgemini outsourcing fees; and

• $3 million in increased contributions primarily for the Energy Aid (low-income customer assistance) program,

partially offset by $6 million in executive severance expense in 2006 (including amounts allocated from parent).

Other income totaled $9 million in 2007 and $1 million in 2006. Other income in 2007 includes $5 million of royalty income and $3 million in penalties received due to nonperformance under a coal transportation agreement.

Other deductions totaled $808 million in 2007 and $195 million in 2006. The 2007 amount includes charges of $795 million in connection with the suspension of the development of eight coal-fueled generation units (see Note 2 to June 30, 2007 Financial Statements).

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The 2006 amount includes:

• a $198 million charge related to the write-down of the natural gas-fueled generation plants to fair value;

• $5 million in equity losses (representing amortization expense) related to the ownership interest in the Energy Future Holdings Corp. subsidiary holding the capitalized software licensed to Capgemini; and

• $2 million in accretion expense related to the combustion turbine lease liability,

partially offset by a $12 million credit related to the favorable settlement of a counterparty default under a coal contract (as noted below, the original charge related to the default was recorded in this line item).

Interest income increased $86 million to $162 million in 2007 reflecting $49 million due to higher average advances to affiliates and $37 million due to higher average rates on the advances.

Interest expense and related charges increased by $9 million, or 4%, to $212 million in 2007. The increase reflected $24 million due to higher average borrowings and $15 million due to higher average interest rates, partially offset by $30 million in increased capitalized interest.

Income tax benefit totaled $266 million in 2007 compared to income tax expense of $546 million in 2006. Excluding the $30 million deferred tax benefit in 2007 and the $42 million deferred tax charge in 2006 related to the Texas margin tax as described in Note 4 to the June 30, 2007 Financial Statements, the effective income tax rate was a 38.8% on a loss in 2007 compared to 33.0% on income in 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion.) The increased effective rate reflects the impact of the significant unrealized mark-to-market net losses associated with the long-term hedging program as well as the charge related to the suspended generation development activities. These effects were partially offset by higher interest accrued related to uncertain tax positions and the higher income-based taxes arising from enactment of the Texas margin tax.

Income (loss) from continuing operations decreased $1.3 billion to a loss of $342 million in 2007 driven by the decline in gross margin and the charges related to the suspension of the development of eight lignite/coal-fueled generation units.

Regulated Delivery Segment

Financial Results

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(millions of dollars)
Operating revenues	$	589		$	604		$	1,207		$	1,166
Costs and expenses:
Operating costs		207			194			402			385
Depreciation and amortization		114			117			234			231
Selling, general and administrative expenses		51			43			93			93
Franchise and revenue-based taxes		60			59			121			119
Other income		(1	)		—			(3	)		(1	)
Other deductions		10			1			19			2
Interest income		(14	)		(14	)		(29	)		(29	)
Interest expense and related charges		78			72			154			140
Total costs and expenses		505			472			991			940
Income before income taxes		84			132			216			226
Income tax expense		30			46			76			75
Income from continuing operations	$	54		$	86		$	140		$	151

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Operating Data

	Three Months Ended June 30,						Six Months Ended June 30,
	2007		2006		Change %		2007		2006		Change %
Operating statistics—volumes:
Electric energy delivered (GWh)		24,972		27,244	(8.3	)		49,966		50,376	(0.8	)
Reliability statistics(a):
System Average Interruption Duration Index (SAIDI) (nonstorm)								77.92		73.54	6.0
System Average Interruption Frequency Index (SAIFI) (nonstorm)								1.15		1.11	3.6
Customer Average Interruption Duration Index (CAIDI) (nonstorm)								67.78		66.11	2.5
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters)(b)								3,077		3,038	1.3
Operating revenues:		(millions of dollars)
Electricity distribution revenues(c):
Affiliated (TCEH)	$	230	$	283	(18.7	)%	$	494	$	550	(10.2	)%
Nonaffiliated		278		254	9.4			558		485	15.1
Total distribution revenues		508		537	(5.4	)		1,052		1,035	1.6
Third-party transmission revenues		65		59	10.2			126		116	8.6
Other miscellaneous revenues		16		8	100.0			29		15	93.3
Total operating revenues	$	589	$	604	(2.5	)%	$	1,207	$	1,166	3.5	%

(a) SAIDI is the average number of electric service interruption minutes per consumer in a year. SAIFI is the average number of electric service interruptions per consumer in a year. CAIDI is the average duration in minutes per electric service interruption in a year. The statistics presented are based on the preceding 12 months’ data.

(b) Includes lighting sites, primarily guard lights, for which TXU Energy is the REP but are not included in TXU Energy’s customer count. Such sites totaled 79,856 and 84,362 at June 30, 2007 and 2006, respectively.

(c) Includes transition charge revenue associated with the issuance of transition bonds totaling $33 million and $37 million for the three months ended June 30, 2007 and 2006, respectively, and $70 million and $73 million for the six months ended June 30, 2007 and 2006, respectively. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.

Regulated Delivery’s future results are expected to be impacted by the effects of the 2006 cities rate settlement. Incremental expenses of approximately $70 million are being recognized almost entirely over the period from May 2006 through June 2008, of which $8 million and $16 million has been recognized in the three and six month periods ended June 30, 2007, respectively.

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

Operating revenues decreased $15 million, or 2%, to $589 million in 2007. The revenue decrease reflected:

• an estimated $33 million in lower revenues due to decreased delivered volumes primarily reflecting the effects of cooler, below normal weather; and

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• $4 million in lower charges to REPs related to securitization bonds (offset by lower amortization of the related regulatory asset),

partially offset by,

• $7 million for installation services related to equipment to support the broadband-over-powerlines initiative;

• $6 million in higher transmission revenues primarily due to rate increases approved in 2006 and 2007 to recover ongoing investment in the transmission system;

• $4 million from increased distribution tariffs to recover higher transmission costs; and

• $3 million due to increased growth in points of delivery.

Gross Margin

	Three Months Ended June 30,
	2007		% of Revenue		2006		% of Revenue
	(millions of dollars)
Operating revenues	$	589	100	%	$	604	100	%
Costs and expenses:
Operating costs		207	35			194	32
Depreciation and amortization		114	19			116	19
Gross margin	$	268	46	%	$	294	49	%

Operating costs increased $13 million, or 7%, to $207 million in 2007. The increase reflected $7 million in equipment installation costs related to the broadband-over-powerlines initiative, $6 million in higher fees to other transmission entities, $5 million in increased labor costs primarily for restoration of service as a result of weather events and individually insignificant cost increases in several categories, partially offset by lower vegetation management expenses of $11 million due primarily to timing of these activities.

Depreciation and amortization decreased $3 million, or 3%, to $114 million in 2007. The decrease reflected $4 million in lower amortization of the regulatory assets associated with the securitization bonds (offset in revenues), partially offset by $1 million in higher depreciation due to normal additions and replacements of property, plant and equipment.

SG&A expenses increased $8 million, or 19%, to $51 million in 2007. The increase reflected $3 million for expenses related to the rebranding of the Oncor Electric Delivery Company name, $2 million in higher legal and consulting fees, $2 million in higher outsourced service provider costs and $1 million in higher sale of receivables program fees driven by higher interest rates.

Franchise and revenue-based taxes increased $1 million, or 2%, to $60 million in 2007. The increase was driven primarily by higher franchise fees under the 2006 cities rate settlement.

Other deductions totaled $10 million in 2007 and $1 million in 2006. The 2007 amount includes $7 million in costs as a result of the 2006 cities rate settlement and $3 million in costs related to the InfrastruX Energy Services joint venture.

Interest expense increased $6 million, or 8%, to $78 million in 2007. The increase reflects $4 million due to higher average borrowings and $2 million due to higher average interest rates.

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Income tax expense totaled $30 million in 2007 compared to $46 million in 2006. The effective income tax rate increased to 35.7% in 2007 from 34.8% in 2006. The increase reflects higher interest accrued related to uncertain tax positions and the effect of full amortization prior to 2007 of a regulatory liability associated with statutory tax rate changes.

Income from continuing operations decreased $32 million, or 37%, to $54 million. This decrease was primarily driven by lower operating revenue, higher SG&A expenses and fees to other transmission entities and costs associated with the cities rate settlement.

Regulated Delivery Segment

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Operating revenues increased $41 million, or 4%, to $1.2 billion in 2007. The revenue increase reflected:

• $13 million for installation services related to equipment to support the broadband-over-powerlines initiative;

• $10 million from increased distribution tariffs to recover higher transmission costs;

• $9 million in higher transmission revenues primarily due to rate increases approved in 2006 and 2007 to recover ongoing investment in the transmission system; and

• $8 million due to growth in points of delivery,

partially offset by $3 million in lower charges to REPs related to securitization bonds (offset by lower amortization of the related regulatory asset).

Gross Margin

	Six Months Ended June 30,
	2007		% of Revenue		2006		% of Revenue
	(millions of dollars)
Operating revenues	$	1,207	100	%	$	1,166	100	%
Costs and expenses:
Operating costs		402	33			385	33
Depreciation and amortization		233	20			230	20
Gross margin	$	572	47	%	$	551	47	%

Operating costs increased $17 million, or 4%, to $402 million in 2007. The increase reflected $12 million in higher fees to other transmission entities, $12 million in equipment installation costs related to the broadband-over-powerlines initiative and $5 million in increased labor costs primarily due to restore service as a result of weather events, partially offset by lower vegetation management expenses of $14 million, due primarily to timing of these activities.

Depreciation and amortization increased $3 million, or 1%, to $234 million in 2007. The increase reflected $5 million in higher depreciation due to normal additions and replacements of property, plant and equipment, partially offset by $2 million in lower amortization of the regulatory assets associated with the securitization bonds (offset in revenues).

Franchise and revenue-based taxes increased $2 million, or 2%, to $121 million in 2007. The increase was driven primarily by higher franchise fees under the cities rate settlement.

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Other deductions totaled $19 million in 2007 and $2 million in 2006. The 2007 amount includes $13 million in costs as a result of the 2006 cities rate settlement and $4 million in costs related to the InfrastruX Energy Services joint venture.

Interest expense increased $14 million, or 10%, to $154 million in 2007. The increase reflects $11 million due to higher average borrowings and $3 million due to higher average interest rates.

Income tax expense totaled $76 million in 2007 compared to $75 million in 2006. The effective income tax rate increased to 35.2% in 2007 from 33.2% in 2006. The increase reflects higher taxes as a result of the enactment of the Texas margin tax, higher interest accrued related to uncertain tax positions and the effect of full amortization prior to 2007 of a regulatory liability associated with statutory tax rate changes.

Income from continuing operations decreased $11 million, or 7%, to $140 million. This decrease was driven by costs associated with the cities rate settlement, higher interest expense due primarily to higher average borrowings and higher fees to other transmission entities, partially offset by higher operating revenue.

COMPREHENSIVE INCOME—Continuing Operations

Cash flow hedge activity reported in other comprehensive income from continuing operations included (all amounts after-tax):

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2007			2006			2007			2006
	(millions of dollars)
Net increase (decrease) in fair value of cash flow hedges (all commodity-related) held at end of period	$	35		$	(83	)	$	(281	)	$	30
Derivative value net losses (gains) reported in net income that relate to hedged transactions recognized in the period:
Commodities		(19	)		10			(95	)		7
Financing—interest rate swaps(a)		2			2			4			4
		(17	)		12			(91	)		11
Total income (loss) effect of cash flow hedges reported in other comprehensive income from continuing operations	$	18		$	(71	)	$	(372	)	$	41

(a) Represents recognition of net losses on settled swaps.

Energy Future Holdings Corp. has historically used, and expects to continue to use, derivative instruments that are effective in offsetting future cash flow variability in interest rates and energy commodity prices. The amounts included in accumulated other comprehensive income are expected to offset the impact of rate or price changes on forecasted transactions. Amounts in accumulated other comprehensive income include (i) the value of open cash flow hedges (for the effective portion), based on current market conditions, and (ii) the value of dedesignated and terminated cash flow hedges at the time of such dedesignation, less amounts reclassified to earnings as the original hedged transactions are recognized, unless the hedged transactions become probable of not occurring. The effects of the hedge will be recorded in the statement of income as the hedged transactions are actually settled and affect earnings. Also see Note 12 to the June 30, 2007 Financial Statements.

Results of Operations—Annual Results

Results of operations and the related management’s discussion of those results for all periods presented reflect the discontinuance of certain operations (see Note 3 to the 2006 year-end Financial Statements regarding discontinued operations).

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Energy Future Holdings Corp. Consolidated

2006 compared to 2005

Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.

Energy Future Holdings Corp.’s operating revenues increased $194 million, or 2%, to $10.9 billion in 2006 as shown in the table below:

	Year Ended December 31,
	2006			2005			Increase (Decrease)
	(millions of dollars)
Competitive Electric segment:
Retail electricity revenues	$	6,953		$	6,330		$	623
Accrued customer appreciation bonus		(162	)		—			(162	)
Wholesale electricity revenues		2,278			2,807			(529	)
Wholesale balancing activities		(31	)		225			(256	)
Results of risk management and trading activities		153			(164	)		317
Other operating revenues		358			354			4
Total Competitive Electric segment		9,549			9,552			(3	)
Regulated Delivery segment		2,449			2,394			55
Net intercompany eliminations		(1,142	)		(1,284	)		142
Total consolidated revenues	$	10,856		$	10,662		$	194

The following discusses the changes in revenue within the Competitive Electric segment:

• A 10% increase in retail electricity revenues was driven by higher pricing, partially offset by the effect of an 11% decline in retail sales volumes. Higher retail prices reflected increases in natural gas prices that resulted in the regulatory-approved price-to-beat rate increases implemented in May 2005, October 2005 and January 2006. The decline in retail sales volumes reflected a net loss of customers due to competitive activity and lower average consumption per residential and small business customer.

• A $162 million ($105 million after-tax) charge was recorded in the fourth quarter of 2006 for a special residential customer appreciation bonus. See discussion in Note 7 to the 2006 year-end Financial Statements for details.

• The decline in wholesale electricity revenues reflected the reporting of wholesale electricity trading activity on a net basis in 2006 as described in Note 1 to the 2006 year-end Financial Statements.

• Wholesale balancing net revenues/purchases are subject to high variability as the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes as measured in 15-minute intervals. See Note 1 to the 2006 year-end Financial Statements for a discussion regarding reporting of ERCOT balancing activities.

• The gains arising from risk management and trading activities in 2006 primarily reflect the unrealized effects of changes in natural gas prices and market heat rates on positions in the long-term hedging program implemented in the fourth quarter of 2005, while the losses in 2005 primarily represent realized losses on prior years’ hedging activities.

The 2% revenue increase in the Regulated Delivery segment reflected higher transmission and distribution tariffs as well as growth in points of delivery.

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The decline in net intercompany sales elimination reflected lower sales by Oncor Electric Delivery to REP subsidiaries of TCEH, while its sales to nonaffiliated REPs increased.

Gross Margin

	Year Ended December 31,
	2006		% of Revenue		2005		% of Revenue
	(millions of dollars)
Operating revenues	$	10,856	100	%	$	10,662	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		2,784	26			4,261	40
Operating costs		1,373	13			1,425	13
Depreciation and amortization		813	7			764	7
Gross margin	$	5,886	54	%	$	4,212	40	%

Gross margin is considered a key operating metric as its changes measure the effect of movements in sales volumes and pricing versus the variable and fixed costs to generate, purchase and deliver electricity.

Gross margin increased $1.7 billion, or 40%, to $5.9 billion in 2006.

• The Competitive Electric segment’s gross margin increased $1.7 billion, or 55%, to $4.7 billion. The gross margin increase reflected the regulatory-approved price-to-beat increases and unrealized net gains from cash flow hedge ineffectiveness and mark-to-market valuations of positions in the long-term hedging program.

• The Regulated Delivery segment’s gross margin increased $15 million, or 1%, to $1.2 billion in 2006, driven by higher revenues.

Fuel, purchased power costs and delivery fees declined $1.5 billion, or 35%, to $2.8 billion primarily due to the reporting of wholesale trading activity on a net basis in 2006 as discussed in Note 1 to the 2006 year-end Financial Statements.

Operating costs decreased $52 million, or 4%, to $1.4 billion in 2006.

• Competitive Electric’s operating costs decreased $64 million, or 10%, primarily reflecting lower maintenance costs due to both nuclear generation units having scheduled refueling outages in 2005 compared to one in 2006, as well as lower incentive compensation expense in 2006 and the absence of combustion turbine lease expense in 2006 resulting from the purchase of a lease trust interest in early 2006 (see Note 4 to the 2006 year-end Financial Statements).

• Regulated Delivery’s operating costs increased $12 million, or 2%, driven by fees paid to third-party transmission entities.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants and the delivery system shown in the gross margin table above) increased $54 million, or 7%, to $830 million in 2006. The increased expense reflects depreciation related to normal additions and replacements of property and higher expense associated with mining land reclamation activities.

SG&A expenses increased $38 million, or 5%, to $819 million in 2006. The increase reflected:

• $39 million in costs associated with the new generation development programs, principally salaries and consulting expenses;

• $17 million in higher fees related to the sale of accounts receivable program due to higher interest rates;

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• $12 million in executive severance costs; and

• $12 million in higher bad debt expense primarily reflecting higher retail accounts receivable balances due to higher prices,

partially offset by:

• $20 million in lower stock-based incentive compensation expense due primarily to fewer share awards and lower expense related to a deferred compensation plan;

• $9 million in lower consulting fees related to various strategic initiatives, including fees in 2005 relating to the Luminant Operating System; and

• $7 million in lower compensation expense resulting from cost reduction initiatives.

Franchise and revenue-based taxes increased $26 million, or 7%, to $390 million reflecting higher state gross receipts taxes due to higher revenues and higher city franchise tax assessments under the 2006 cities rate settlement. See Note 9 to the 2006 year-end Financial Statements.

Other income totaled $121 million in 2006 and $151 million in 2005. Other deductions totaled $269 million in 2006, which included a $198 million impairment charge related to natural gas-fueled generation plants, and $45 million in 2005. See Note 12 to the 2006 year-end Financial Statements for detail of other income and deductions.

Interest expense and related charges increased $28 million, or 3%, to $830 million in 2006. The increase reflected $69 million from higher average interest rates (including the effect of interest rate swap transactions), partially offset by $30 million in increased capitalized interest and $11 million due to lower average borrowings.

Income tax expense from continuing operations totaled $1.3 billion in 2006 compared to $632 million in 2005. The effective tax rate was 33.9% in 2006 compared to 26.3% in 2005. The 2006 amount included a charge of $44 million (1.2 percentage point effective tax rate impact) representing an adjustment to net deferred tax liabilities arising from the enactment of the Texas margin tax as described in Note 10 to the 2006 year-end Financial Statements. The 2005 amount included $138 million in additional tax benefit (5.7 percentage point effective tax rate impact) related to the TXU Europe write-off as described in Note 11 to the 2006 year-end Financial Statements and $29 million benefit (1.2 percentage point effective tax rate impact) related to the release of a tax reserve.

Income from continuing operations (an after-tax measure) increased $690 million, or 39%, to $2.5 billion in 2006.

• Earnings in the Competitive Electric segment increased $934 million, or 65%, to $2.4 billion driven primarily by improved gross margin partially offset by a charge for the write-down of the natural gas-fueled generation plants.

• Earnings in the Regulated Delivery segment decreased $7 million, or 2%, to $344 million driven by expenses in 2006 related to the cities rate settlement and the InfrastruX Energy Services joint venture.

• Corporate and Other net expenses totaled $242 million in 2006 and $5 million in 2005. The increase reflected (all amounts after-tax):

• a $138 million tax benefit in 2005 related to TXU Europe (see Note 11 to the 2006 year-end Financial Statements);

• an $85 million increase (to $241 million) in net interest expense related to advances from subsidiaries reflecting higher balances and interest rates;

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• a $17 million gain in 2006 related to a settlement of a telecommunications contract dispute; and

• $10 million and $23 million of insurance recoveries in 2006 and 2005, respectively, related to the 2005 shareholders’ litigation settlement.

Net pension and other postretirement employee benefit costs reduced income from continuing operations by $41 million in 2006 and $38 million in 2005. See Note 21 to the 2006 year-end Financial Statements.

Income from discontinued operations (an after-tax measure) totaled $87 million in 2006 and $5 million in 2005. See Note 3 to the 2006 year-end Financial Statements for details.

Diluted earnings per share of common stock totaled $5.46 in 2006 and $2.50 in 2005.

• Diluted earnings per share in 2006 reflected a favorable $0.16 per share impact from the repurchase of approximately 18.5 million shares since December 31, 2005. Basic average common shares outstanding decreased 3% to 460 million shares reflecting these share repurchases. Diluted average common shares decreased 4% to 467 million shares. (See Note 2 to the year-end Financial Statements.)

• Diluted earnings per share in 2005 reflect an unfavorable impact associated with the November 2004 accelerated share repurchase program. See Notes 2 and 17 to the 2006 year-end Financial Statements.

Energy Future Holdings Corp. Consolidated

2005 compared to 2004

Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.

Energy Future Holdings Corp.’s operating revenues increased $1.4 billion, or 16%, to $10.7 billion in 2005.

• Operating revenues in the Competitive Electric segment increased $1.2 billion, or 14%, to $9.6 billion driven by higher retail and wholesale pricing, which was primarily the result of higher natural gas prices. The effect of higher pricing was partially offset by the effect of lower retail sales volumes. Retail sales volumes declined 17% primarily reflecting a net loss of customers to competitive activity, particularly in the large business market, partially offset by the effect of warmer weather.

• Operating revenues in the Regulated Delivery segment increased $168 million, or 8%, to $2.4 billion in 2005. The revenue increase was driven by a 5% increase in delivered volumes, due largely to warmer weather and an increase in delivery points. The balance of the growth reflected $46 million in higher transition charges associated with securitization bonds issued in 2004 (offset in total by higher amortization of the related regulatory asset as discussed below). Additionally, higher transmission and distribution tariffs driven by Oncor Electric Delivery’s ongoing transmission investment program and market growth contributed to increased revenues.

• Consolidated revenue growth reflected a $128 million reduction in the intercompany sales elimination, primarily reflecting lower sales by Oncor Electric Delivery to TCEH, while its sales to nonaffiliated REPs increased.

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Gross Margin

	Year Ended December 31,
	2005		% of Revenue		2004		% of Revenue
	(millions of dollars)
Operating revenues	$	10,662	100	%	$	9,216	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		4,261	40	%		3,755	41	%
Operating costs		1,425	13	%		1,429	15	%
Depreciation and amortization		764	7	%		709	8	%
Gross margin	$	4,212	40	%	$	3,323	36	%

Gross margin increased $889 million, or 27%, to $4.2 billion in 2005.

• The Competitive Electric segment’s gross margin increased $831 million, or 38%, to $3.0 billion, driven by higher pricing partially offset by higher per MWh cost of purchased power and gas-fueled generation as well as the effect of lower sales volumes.

• The Regulated Delivery segment’s gross margin increased $80 million, or 7%, to $1.2 billion in 2005, driven by higher operating revenues.

Operating costs were $1.4 billion in both 2005 and 2004.

• Competitive Electric’s operating costs declined $35 million, or 5%. As discussed below in the business segment analysis, this decline was due to a number of factors, including the absence of $43 million of costs related to activities no longer performed.

• Regulated Delivery’s operating costs rose $28 million, or 4%, driven by increased spending for reliability initiatives and higher property taxes due to increased investments in property.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants and the delivery system shown in the gross margin table above) increased $16 million, or 2%, to $776 million in 2005. The increase included higher amortization of the regulatory asset associated with securitization bonds (offset in revenues) and higher depreciation due to normal additions of property, largely offset by a change in the carrying value of software assets in connection with the Capgemini outsourcing transaction and the effect of reduced 2005 depreciation rates for lignite/coal-fueled plants due to extending the estimated useful lives.

SG&A expense decreased $310 million, or 28%, to $781 million in 2005. The decline reflected:

• $93 million resulting from cost reduction initiatives including the Capgemini outsourcing agreement;

• $52 million in nonrecurring executive compensation costs in 2004;

• $50 million in reduced incentive compensation expense including $15 million due to a one-time incentive compensation program in wholesale operations in 2004;

• $42 million in consulting and professional fees in 2004 related to the formulation and execution of strategic initiatives;

• $34 million in lower bad debt expense as a result of stricter disconnect policies and more focused collection activities; and

• $15 million in reduced pension and other postretirement benefits primarily due to the effect of Texas legislation enacted in the second quarter of 2005. (See Note 21 to the 2006 year-end Financial Statements.)

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Other income totaled $151 million in 2005 and $148 million in 2004. Other deductions totaled $45 million in 2005 and $1.2 billion in 2004. The other deductions in 2004 primarily represented charges related to the restructuring actions discussed in Note 8 to the 2006 year-end Financial Statements. Also see Note 12 to the 2006 year-end Financial Statements for detail of other income and deductions.

Interest income increased $20 million to $48 million in 2005 primarily reflecting losses on interest rate swaps in 2004 (related to a note receivable) and higher interest earned on short-term investments in 2005.

Interest expense and related charges increased $107 million, or 15%, to $802 million in 2005 reflecting $66 million due to higher average borrowings and $41 million due to higher average interest rates.

Income tax expense on income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles included:

• $138 million in additional tax benefit recorded in the first quarter of 2005 related to the TXU Europe write-off. This benefit reflects identification of tax planning strategies Energy Future Holdings Corp. would implement to ensure utilization of capital losses associated with the write-off of the investment in TXU Europe; and

• $75 million tax benefit recorded in the second quarter of 2004 arising from the sale of TXU Fuel Company (“TXU Fuel”).

The effective income tax rate excluding the effect of these benefits was 32.0% in 2005 and 95.1% in 2004. The 2005 effective income tax rate reflects a $29 million benefit for the reversal of previously established tax reserves due to current period events. The 2004 effective rate reflected the limited deductibility of expenses recorded in connection with the repurchase of convertible and equity-linked debt securities on a small income base.

Income from continuing operations before extraordinary items and the cumulative effect of changes in accounting principle (an after-tax measure) increased to $1.8 billion in 2005 from $81 million in 2004.

• Earnings in the Competitive Electric segment increased $1.0 billion to $1.4 billion driven by improved gross margin, the effect of restructuring-related charges in 2004 and lower SG&A expenses.

• Earnings in the Regulated Delivery segment increased $96 million, or 38%, to $351 million driven by higher operating revenues and the impact of 2004 restructuring-related charges and a rate case settlement charge (see Note 8 to the 2006 year-end Financial Statements).

• Corporate and other activities resulted in net expenses of $5 million in 2005 compared to $582 million in 2004. The improvement of $577 million reflected (all amounts after-tax):

• $382 million of debt extinguishment losses due primarily to restructuring-related actions in 2004;

• $138 million income tax benefit recorded in 2005 related to TXU Europe;

• $56 million for a litigation accrual in 2004;

• $52 million pre and after-tax in nonrecurring executive compensation in 2004;

• $27 million in restructuring-related consulting and professional fees in 2004; and

• $23 million insurance recovery in 2005 related to the 2005 shareholders litigation settlement,

partially offset by the recognition in 2004 of a $75 million income tax benefit arising from the sale of TXU Fuel.

Net pension and postretirement benefit costs reduced income from continuing operations by $38 million in 2005 and $64 million in 2004. See Note 21 to the 2006 year-end Financial Statements.

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Income from discontinued operations (an after-tax measure) totaled $5 million in 2005 and $378 million in 2004. See Note 3 to the 2006 year-end Financial Statements for details.

Diluted results per share of common stock were net income of $2.50 in 2005 compared to a net loss of $0.64 in 2004.

• The 2005 diluted per share results reflect an unfavorable impact associated with the November 2004 accelerated share repurchase program. See Note 17 to the 2006 year-end Financial Statements.

• Diluted earnings per share in 2005 reflected the favorable impact of 114 million fewer average shares outstanding in 2005. Basic average common shares outstanding decreased 21% to 476 million shares reflecting the repurchase of 105 million shares in November 2004 under the accelerated share repurchase program and the repurchase of 12 million shares in 2005. (See Notes 2 and 17 to the 2006 year-end Financial Statements.) Diluted average common shares decreased 19% to 486 million shares.

• Per share results in 2004 were unfavorably impacted by Energy Future Holdings Corp.’s repurchase of TCEH’s exchangeable preferred membership interests in April 2004 (see Notes 2 and 17 to the 2006 year-end Financial Statements). For 2004, results per diluted share of common stock equaled results per basic share because of antidilution accounting rules.

Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2006, 2005 and 2004. The net changes in these assets and liabilities, excluding “other activity” as described below, represent the net effect of mark-to-market accounting for positions in the commodity contract portfolio, which excludes positions that are subject to cash flow hedge accounting. For the 2006 period, this effect totaled $33 million in unrealized net gains, which represented $22 million in net gains on unsettled positions and $11 million in reversals of net losses recognized in prior periods on positions settled in the current period. These positions represent both economic hedging and trading activities.

	December 31,
	2006			2005			2004
	(millions of dollars)
Commodity contract net asset (liability) at beginning of period	$	(56	)	$	23		$	108
Settlements of positions included in the opening balance(1)		11			(23	)		(61	)
Unrealized mark-to-market valuations of positions held at end of period(2)		22			32			(29	)
Other activity(3)		—			(88	)		5
Commodity contract net asset (liability) at end of period	$	(23	)	$	(56	)	$	23

(1) Represents reversals of unrealized mark-to-market valuations of these positions recognized in net income prior to the beginning of the period, to offset gains and losses realized upon settlement of the positions in the current period.

(2) Includes gains and losses recorded at contract inception dates. In June 2006, a subsidiary of Energy Future Holdings Corp. entered into a related series of commodity hedge transactions at below-market prices resulting in a $109 million loss at inception date. See Note 18 to the 2006 year-end Financial Statements.

(3) These amounts have not been recognized in prior and current year mark-to-market earnings. Includes initial values of positions involving the receipt or payment of cash or other consideration such as option premiums paid and received. Activity in 2005 included $75 million of natural gas received related to physical swap transactions and a $12 million charge related to nonperformance by a coal contract counterparty.

In addition to the net effect of recording unrealized mark-to-market gains and losses that are reflected in the table above, similar effects arise in the recording of unrealized ineffectiveness gains and losses associated with

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commodity-related cash flow hedges. These effects, which include reversals of previously recorded unrealized ineffectiveness gains and losses to offset realized gains and losses upon settlement, are reflected in the balance sheet as changes in cash flow hedge and other derivative assets and liabilities. The total net effect of recording unrealized gains and losses related to commodity contracts under SFAS 133 is summarized as follows:

	December 31,
	2006		2005			2004
	(millions of dollars)
Unrealized gains/(losses) related to contracts marked-to-market	$	33	$	9		$	(90	)
Ineffectiveness gains/(losses) related to cash flow hedges(a)		239		(27	)		(19	)
Total unrealized gains (losses) related to commodity contracts	$	272	$	(18	)	$	(109	)

(a) See Note 19 to the 2006 year-end Financial Statements.

These amounts are reported in the “risk management and trading activities” component of revenues.

Maturity Table—Included in the net commodity contract liability above at December 31, 2006, is a net asset of $69 million representing cumulative unrealized mark-to-market net gains that have been recognized in current and prior years’ earnings. More than offsetting this net asset is a net liability of $92 million included in the December 31, 2006 balance sheet that is comprised principally of amounts representing current and prior years’ net receipts of cash or other consideration, including $86 million related to natural gas physical swap transactions. The following table presents the unrealized net commodity contract asset arising from mark-to-market accounting as of December 31, 2006, scheduled by contractual settlement dates of the underlying positions.

	Maturity Dates of Unrealized Commodity Contract Net Assets (Liabilities) at December 31, 2006
	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
	(millions of dollars)
Source of fair value
Prices actively quoted	$	(24	)	$	6		$	33		$	4		$	19
Prices provided by other external sources(a)		57			8			(64	)		59			60
Prices based on models		(7	)		(3	)		—			—			(10	)
Total	$	26		$	11		$	(31	)	$	63		$	69
Percentage of total fair value		38	%		16	%		(45	)%		91	%		100	%

(a) Includes a “day one” loss of $109 million associated with a related series of commodity hedge transactions. See Note 18 to the 2006 year-end Financial Statements.

The “prices actively quoted” category reflects only exchange traded contracts with active quotes available. The “prices provided by other external sources” category represents forward commodity positions at locations for which over-the-counter broker quotes are available. Over-the-counter quotes for power in ERCOT generally extend through 2010 and over-the-counter quotes for natural gas generally extend through 2015, depending upon delivery point. The “prices based on models” category contains the value of all nonexchange traded options, valued using option pricing models. In addition, this category contains other contractual arrangements which may have both forward and option components. In many instances, these contracts can be broken down into their component parts and each component valued separately. Components valued as forward commodity positions are included in the “prices provided by other external sources” category. Components valued as options are included in the “prices based on models” category.

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Competitive Electric Segment

Financial Results

	Year Ended December 31,
	2006			2005		��	2004
	(millions of dollars)
Operating revenues	$	9,549		$	9,552		$	8,402
Costs and expenses:
Fuel, purchased power costs and delivery fees		3,928			5,545			5,173
Operating costs		604			668			703
Depreciation and amortization		334			313			350
Selling, general and administrative expenses		571			522			666
Franchise and revenue-based taxes		126			114			117
Other income		(17	)		(64	)		(110	)
Other deductions		215			15			611
Interest income		(202	)		(70	)		(31	)
Interest expense and related charges		388			393			353
Total costs and expenses		5,947			7,436			7,832
Income from continuing operations before income taxes and cumulative effect of changes in accounting principles		3,602			2,116			570
Income tax expense		1,239			687			162
Income from continuing operations before cumulative effect of changes in accounting principles
	$	2,363		$	1,429		$	408

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Competitive Electric Segment

Sales Volume Data

	Year Ended December 31,						Change % 2006/2005		Change % 2005/2004
	2006		2005		2004
Sales volumes:
Retail electricity sales volumes—gigawatt hours (GWh):
Historical service territory:
Residential	25,932		29,239		30,897		(11.3	)	(5.4	)
Small business(a)	7,753		9,004		10,476		(13.9	)	(14.1	)
Total historical service territory	33,685		38,243		41,373		(11.9	)	(7.6	)
Other territories:
Residential	3,663		3,416		3,089		7.2		10.6
Small business(a)	671		674		363		(0.4	)	85.7
Total other territories	4,334		4,090		3,452		6.0		18.5
Large business and other customers	14,031		15,843		25,466		(11.4	)	(37.8	)
Total retail electricity	52,050		58,176		70,291		(10.5	)	(17.2	)
Wholesale electricity sales volumes	36,931		52,001		48,309		(29.0	)	7.6
Net sales (purchases) of balancing electricity to/from ERCOT(b)	874		4,787		(1,613	)	(81.7	)	—
Total sales volumes	89,855		114,964		116,987		(21.8	)	(1.7	)
Average volume (kWh) per retail customer(c):
Residential	15,359		15,825		15,619		(2.9	)	1.3
Small business	30,360		32,078		34,095		(5.4	)	(5.9	)
Large business and other customers	285,277		243,538		351,542		17.1		(30.7	)
Weather (service territory average)—percent of normal(d):
Percent of normal:
Cooling degree days	117.6	%	107.0	%	90.0	%
Heating degree days	79.2	%	90.0	%	90.1	%

(a) Customers with demand of less than 1 MW annually.

(b) See Note 1 to the 2006 year-end Financial Statements for discussion of trading and ERCOT balancing activity in 2006.

(c) Calculated using average number of customers for period.

(d) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the U.S. Department of Commerce).

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Competitive Electric Segment

Customer Count Data

	Year Ended December 31,			Change % 2006/2005		Change % 2005/2004
	2006	2005	2004
Customer counts:
Retail electricity customers (end of period and in thousands)(a):
Historical service territory:
Residential	1,624	1,769	1,951	(8.2	)	(9.3	)
Small business(b)	258	281	309	(8.2	)	(9.1	)
Total historical service territory	1,882	2,050	2,260	(8.2	)	(9.3	)
Other territories:
Residential	247	213	194	16.0		9.8
Small business(b)	9	7	6	28.6		16.7
Total other territories	256	220	200	16.4		10.0
Large business and other customers	44	55	76	(20.0	)	(27.6	)
Total retail electricity customers	2,182	2,325	2,536	(6.2	)	(8.3	)

(a) Based on number of meters.

(b) Customers with demand of less than 1 MW annually.

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Competitive Electric Segment

Revenue and Market Share Data

	Year Ended December 31,									Change % 2006/2005		Change % 2005/2004
	2006			2005			2004
	(millions of dollars, except percentages and average revenues per MWh)
Operating revenues:
Retail electricity revenues:
Historical service territory:
Residential	$	3,804		$	3,444		$	3,164		10.5		8.8
Small business(a)		1,153			1,086			1,103		6.2		(1.5	)
Total historical service territory		4,957			4,530			4,267		9.4		6.2
Other territories:
Residential		559			405			298		38.0		35.9
Small business(a)		80			65			34		23.1		91.2
Total other territories		639			470			332		36.0		41.6
Large business and other customers		1,357			1,330			1,771		2.0		(24.9	)
Total retail electricity revenues		6,953			6,330			6,370		9.8		(0.6	)
Wholesale electricity revenues(b)		2,278			2,807			1,886		(18.8	)	48.8
Net sales (purchases) of balancing electricity to/from ERCOT(b)		(31	)		225			(92	)	—		—
Net gains (losses) from risk management and trading activities		153			(164	)		(103	)	—		(59.2	)
Other operating revenues(c)		196			354			341		(44.6	)	3.8
Total operating revenues	$	9,549		$	9,552		$	8,402		—		13.7
Risk management and trading activities:
Realized net gains (losses) on settled positions(d)	$	(119	)	$	(146	)	$	6
Reversal of prior periods’ unrealized net (gains) losses on positions settled in current period		32			(12	)		(59	)
Other unrealized net gains (losses), including cash flow hedge ineffectiveness		240			(6	)		(50	)
Total net gains (losses)	$	153		$	(164	)	$	(103	)
Average revenues per MWh:
Residential	$	147.43		$	117.86		$	101.88		25.1		15.7
Small business	$	146.39		$	118.90		$	104.87		23.1		13.4
Large business and other customers	$	96.67		$	83.96		$	69.54		15.1		20.7
Estimated share of ERCOT retail markets(e)(f):
Historical service territory:
Residential		65	%		72	%		81	%
Small business		64	%		71	%		78	%
Total ERCOT:
Residential		37	%		39	%		44	%
Small business		26	%		29	%		31	%
Large business and other customers		14	%		20	%		33	%

(a) Customers with demand of less than 1 MW annually.

(b) See Note 1 to the 2006 year-end Financial Statements for discussion of reporting of trading and ERCOT balancing activity in 2006.

(c) Includes a $162 million charge for a special customer appreciation bonus. This charge does not affect the computation of residential average revenues per MWh. See Note 7 to the 2006 year-end Financial Statements.

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(d) Includes physical commodity trading activity not subject to mark-to-market accounting of $34 million in net losses, $61 million in net gains and $13 million in net gains in 2006, 2005 and 2004, respectively.

(e) Based on number of meters.

(f) Estimated market share is based on the number of customers that have choice.

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Year Ended December 31,									Change % 2006/2005		Change % 2005/2004
	2006			2005			2004
	(millions of dollars)
Fuel, purchased power costs and delivery fees:
Nuclear fuel	$	85		$	78		$	82		9.0		(4.9	)
Lignite/coal		475			475			506		—		(6.1	)
Total baseload fuel		560			553			588		1.3		(6.0	)
Natural gas fuel and purchased power		1,787			3,285			2,820		(45.6	)	16.5
Other costs		228			281			221		(18.9	)	27.1
Fuel and purchased power costs(a)		2,575			4,119			3,629		(37.5	)	13.5
Delivery fees(b)		1,353			1,426			1,544		(5.1	)	(7.6	)
Total	$	3,928		$	5,545		$	5,173		(29.2	)	7.2
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	4.29		$	4.23		$	4.31		1.4		(1.9	)
Lignite/coal(c)	$	12.20		$	11.68		$	12.96		4.5		(9.9	)
Natural gas fuel and purchased power	$	62.99		$	60.37		$	47.88		4.3		26.1
Delivery fee per MWh	$	25.71		$	24.20		$	21.75		6.2		11.3
Production and purchased power volumes (GWh):
Nuclear		19,795			18,371			18,979		7.8		(3.2	)
Lignite/coal		43,837			44,005			42,339		(0.4	)	3.9
Total baseload generation		63,632			62,376			61,318		2.0		1.7
Natural gas-fueled generation		3,989			3,504			4,726		13.8		(25.9	)
Purchased power(a)		24,380			50,920			54,394		(52.1	)	(6.4	)
Total energy supply		92,001			116,800			120,438		(21.2	)	(3.0	)
Less line loss and power imbalances		2,146			1,836			3,451		16.9		(46.8	)
Net energy supply volumes		89,855			114,964			116,987		(21.8	)	(1.7	)
Baseload capacity factors (%):
Nuclear		98.8	%		91.5	%		94.3	%	8.0		(3.0	)
Lignite/coal		89.1	%		89.8	%		86.0	%	(0.8	)	4.4
Total baseload		91.8	%		90.3	%		88.4	%	1.7		2.1

(a) See Note 1 to the 2006 year-end Financial Statements for discussion of reporting of trading and ERCOT balancing activity in 2006.

(b) Includes delivery fee charges from Oncor Electric Delivery that are eliminated in consolidation ($1.144 billion, $1.285 billion and $1.417 billion in 2006, 2005 and 2004, respectively).

(c) Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs.

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Competitive Electric Segment

2006 Compared to 2005

Operating revenues decreased $3 million to $9.5 billion in 2006.

	Year Ended December 31,						Increase (Decrease)
	2006			2005
	(millions of dollars)
Retail electricity revenues	$	6,953		$	6,330		$	623
Accrued customer appreciation bonus		(162	)		—			(162	)
Wholesale electricity revenues		2,278			2,807			(529	)
Wholesale balancing activities		(31	)		225			(256	)
Results of risk management and trading activities		153			(164	)		317
Other operating revenues		358			354			4
Total operating revenues	$	9,549		$	9,552		$	(3	)

The 10% increase in retail electricity revenues reflected the following:

• Higher average pricing contributed $1.3 billion to the revenue increase. Higher retail prices reflected increases in natural gas prices that resulted in the regulatory-approved price-to-beat rate increases implemented in May 2005, October 2005 and January 2006.

• The effect of higher retail pricing was partially offset by $667 million in lower retail volumes. Total retail sales volumes declined 11%. Residential and small business volumes fell 10% on a net loss of customers due to competitive activity and lower average consumption per customer. The lower consumption reflected customer efficiency measures in response to prices and warmer weather. Large business market sales volumes declined 11% as the effect of fewer customers was partially offset by higher average consumption per customer. A change in large business customer mix reflected a continuing strategy to improve margins.

• Retail electricity customer counts at December 31, 2006 declined 6% from December 31, 2005. Total residential and small business customer counts in the historical service territory declined 8% and in all combined territories declined 6%.

A $162 million ($105 million after-tax) charge was recorded in the fourth quarter of 2006 for a special residential customer appreciation bonus. See discussion in Note 7 to the 2006 year-end Financial Statements.

The decline in wholesale electricity revenues reflected the reporting of wholesale electricity trading activity on a net basis in 2006 as described in Note 1 to the 2006 year-end Financial Statements. This effect was partially offset by higher wholesale sales prices.

Wholesale balancing net revenues/purchases are subject to high variability as the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes as measured in 15-minute intervals. See Note 1 for a discussion regarding the change in reporting of ERCOT balancing activities.

Results from risk management and trading activities include realized and unrealized gains and losses associated with financial instruments used for economic hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading purposes (principally natural gas). Because most of the hedging and risk management activities are intended to mitigate the risk of commodity price

96

movements on revenues and fuel and purchased power costs, the changes in such results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on gross margin. Following is an analysis of activities in 2006:

Results associated with the long-term hedging program

• $205 million in unrealized cash flow hedge ineffectiveness net gains, which includes $209 million in net gains on unsettled positions and $4 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period;

• $135 million in unrealized mark-to-market net gains on unsettled economic hedge positions that are not being accounted for as cash flow hedges;

• $109 million in an unrealized “day one” loss on a related series of commodity price hedges entered into in June 2006 at below-market prices; and

• $112 million in realized net gains on positions accounted for as cash flow hedges, including the reclassification of $34 million in net gains accumulated in other comprehensive income at December 31, 2005, to offset hedged electricity revenues recognized in the current period.

Results associated with other risk management and trading activities

• $52 million in realized net losses on positions accounted for as cash flow hedges and primarily entered into in prior years (largely 2003), including the reclassification of $36 million in net losses accumulated in other comprehensive income at December 31, 2005, to offset hedged electricity revenues recognized in the current period;

• $34 million in unrealized cash flow hedge ineffectiveness net gains, which includes $9 million in net gains on unsettled positions and $25 million in net gains that represent reversals of previously recorded unrealized net losses on positions settled in the current period;

• $125 million in realized net losses on settlement of economic hedge positions that offset hedged electricity revenues recognized in the current period; and

• $54 million in realized net losses on settlement of trading positions.

Gross Margin

	Year Ended December 31,
	2006		% of Revenue		2005		% of Revenue
	(millions of dollars)
Operating revenues	$	9,549	100	%	$	9,552	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		3,928	41			5,545	58
Generation plant operating costs		604	6			668	7
Depreciation and amortization		328	4			309	3
Gross margin	$	4,689	49	%	$	3,030	32	%

Gross margin increased $1.7 billion, or 55%, to $4.7 billion in 2006. This growth primarily reflected the relatively low fuel costs of TCEH’s nuclear and lignite/coal-fueled baseload plants, as well as the continued improved productivity of the baseload plants, in an environment of increasing wholesale power prices. The increased wholesale power prices were driven by rising natural gas prices. Retail prices, including price-to-beat retail prices, were increased in response to higher wholesale prices. In addition to higher retail prices, the gross margin increase reflected $231 million in unrealized net gains from cash flow hedge ineffectiveness and

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mark-to-market valuations of positions in the long-term hedging program. An 8% increase in production volumes at the nuclear generation plant also contributed to higher gross margin as this generation represents the lowest marginal cost of electricity to supply retail and wholesale customers. The gross margin performance was tempered by the effects of lower retail sales volumes and the effect of the customer appreciation bonus accrual.

Gross margin as a percent of revenues increased 17 percentage points to 49%. The improvement reflected the following estimated effects:

• higher pricing, as the average retail sales price per MWh rose 23% and the average wholesale sales price per MWh rose 17% (10 percentage point margin increase);

• the effect of reporting wholesale electricity trading activity on a net basis (6 percentage point margin increase);

• the effect of unrealized cash flow hedge ineffectiveness and mark-to-market net gains related to the long-term hedge program (1 percentage point margin increase);

• the combined effect of increased nuclear generation production volumes and less need for purchased electricity volumes (2 percentage point margin increase),

partially offset by:

• lower retail sales volumes (2 percentage point margin decrease); and

• customer appreciation bonus (1 percentage point margin decrease).

Fuel, purchased power costs and delivery fees declined $1.6 billion, or 29%, to $3.9 billion reflecting the reporting of wholesale trading activity on a net basis in 2006 as discussed in Note 1 to the 2006 year-end Financial Statements and the favorable impact of higher nuclear generation volumes to meet sales demand, partially offset by the effect of higher average prices of purchased electricity.

Operating costs decreased $64 million, or 10%, to $604 million in 2006. The decrease reflected:

• $49 million in lower maintenance costs due to both nuclear generation units having scheduled refueling outages in 2005 compared to one in 2006, and reduced other maintenance activity;

• $9 million in lower incentive compensation expense; and

• the absence of $10 million in combustion turbine lease expense in 2006 resulting from the purchase of a lease trust interest in early 2006 (see Note 4 to the 2006 year-end Financial Statements), partially offset by $8 million in net severance and early retirement costs associated with generation outsourcing services agreements entered into in early 2006.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) increased $21 million, or 7%, to $334 million reflecting higher costs associated with mining land reclamation activities and increased amortization of intangible software assets, partially offset by $7 million in lower depreciation due to the impairment of natural gas-fueled generation plants in the second quarter of 2006.

SG&A expenses increased by $49 million, or 9%, to $571 million in 2006. The increase reflected:

• $39 million in costs associated with the new generation development programs, principally salaries and consulting expenses;

• $14 million in higher bad debt expense reflecting higher retail accounts receivable balances due to higher prices and the effect of a temporary regulatory-mandated deferred payment arrangement and disconnect moratorium applicable to certain retail customers;

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• $14 million in higher fees related to the sale of accounts receivable program due to higher interest rates; and

• $6 million in executive severance expense (including amounts allocated from Energy Future Holdings Corp.),

partially offset by:

• $8 million in lower consulting fees primarily reflecting expenses in 2005 for the development and implementation of the Luminant Operating System to improve productivity;

• $7 million in lower stock-based incentive compensation and deferred compensation expenses; and

• $7 million in lower salaries resulting from cost reduction initiatives in late 2005.

Franchise and revenue-based taxes increased $12 million, or 11%, to $126 million reflecting higher state gross receipts taxes due to higher revenues.

Other income totaled $17 million in 2006 and $64 million in 2005. The 2006 amount includes $11 million in gains on the sale of undeveloped land and a $2 million insurance recovery related to a generation plant outage in 2001.

The 2005 amount included:

• $33 million in gains on the sale of undeveloped land and mining land;

• an $8 million insurance recovery related to a generation plant fire in 2002;

• a $7 million gain on the sale of an investment in an out-of-state electricity transmission project;

• a $4 million gain in connection with a customer’s termination of an electricity services contract; and

• a $2 million gain on the sale of surplus equipment.

Other deductions totaled $215 million in 2006 and $15 million in 2005. The 2006 amount includes:

• a $198 million charge related to the write-down of the natural gas-fueled generation plants to fair value (see Note 6 to the 2006 year-end Financial Statements);

• $10 million in equity losses (representing amortization expense) related to the ownership interest in the Energy Future Holdings Corp. subsidiary holding the capitalized software licensed to Capgemini;

• $6 million of litigation-related charges; and

• a $5 million charge for the termination of an equipment purchase agreement,

partially offset by a $12 million credit related to the favorable settlement of a counterparty default under a coal contract (as noted below, the original charge related to the default was recorded in this line item).

The 2005 amount includes:

• a $12 million charge related to a counterparty default under a coal contract;

• $12 million in transition costs associated with the Capgemini outsourcing agreement;

• $7 million in equity losses (representing amortization expense) related to the ownership interest in the Energy Future Holdings Corp. subsidiary holding the capitalized software licensed to Capgemini;

• $6 million in accretion expense related to a lease liability for combustion turbines no longer operated for TCEH’s benefit;

99

• a $16 million net credit from a reduction in the combustion turbine lease liability due to a change in estimated sublease proceeds. As the original charge associated with this liability was reported in this line item, the related credit was similarly reported; and

• the release of a previously recorded $6 million reserve for restoration of a site that is now expected to be used in generation plant development.

Interest income increased by $132 million to $202 million in 2006 reflecting $91 million due to higher average advances to affiliates and $41 million due to higher average rates.

Interest expense and related charges decreased by $5 million, or 1%, to $388 million in 2006. The decrease reflects $29 million of higher capitalized interest, partially offset by higher average interest rates of $24 million.

Income tax expense on income from continuing operations totaled $1.2 billion in 2006 compared to $687 million in 2005. The effective tax rate was 34.4% in 2006 compared to 32.5% in 2005. The 2006 amount included a charge of $44 million (a 1.2 percentage point effective tax rate impact) representing an adjustment to deferred tax liabilities arising from the enactment of the Texas margin tax as described in Note 10 to the 2006 year-end Financial Statements. The 2005 amount reflected a benefit of $29 million representing a tax reserve adjustment (1.4 percentage point effective tax rate impact) and a charge of $10 million (a 0.5 percentage point effective tax rate impact) related to the settlement of the IRS audit for the 1994 to 1996 years.

Income from continuing operations increased $934 million, or 65%, to $2.4 billion in 2006 driven by improved gross margin and higher interest income, partially offset by the charge for the write-down of the natural gas-fueled generation plants and expenses related to the new generation development program.

Competitive Electric Segment

2005 Compared to 2004

Operating revenues increased $1.2 billion, or 14%, to $9.6 billion in 2005. Retail electricity revenues decreased $40 million, or 1%, to $6.3 billion.

• The retail revenue decline reflected a $1.1 billion decrease attributable to a 17% drop in sales volumes, primarily reflecting a net loss of customers due to competitive activity, particularly in the large business market, partially offset by the effect of warmer weather. A total volume decline of 38% in the large business market also reflected a strategy to improve margins. Total residential and small business volumes fell 6%, driven by competitive activity and stricter disconnect policies and more focused collection activities, partially offset by the effect of increased consumption by residential customers due to warmer weather.

• The effect of lower retail volumes was partially offset by $886 million in higher pricing due to increased price-to-beat rates, reflecting regulatory-approved fuel factor increases in 2005, and higher pricing in the competitive business market, both resulting from the effects of higher natural gas prices. A favorable $171 million mix shift in the composition of retail sales from large business to residential and small business also offset the effect of lower volumes.

• Retail electricity customer counts at December 31, 2005 declined 8% from December 31, 2004. Total residential and small business customer counts in the historical service territory declined 9% and in all combined territories declined 8%.

Wholesale electricity revenues grew $921 million, or 49%, to $2.8 billion reflecting $777 million in higher prices due to the effect of increased natural gas prices on wholesale electricity prices and $144 million due to an 8% increase in sales volumes. The wholesale sales volume increase was driven by a shift in the composition of the customer base from retail to wholesale and weather-related increases in wholesale demand.

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ERCOT balancing activities resulted in net sales of $225 million in 2005 and net purchases of $92 million in 2004. See Note 1 for a discussion regarding the change in reporting of ERCOT balancing activities.

The increase in other revenues of $12 million primarily reflected higher retail (business customers) natural gas revenues due to increased prices, partially offset by the effect of no longer providing customer care support to TXU Gas after the first half of 2004 and the sale of TXU Fuel in June 2004.

Net losses from hedging and risk management activities, which are reported in revenues and include both realized and unrealized (mark-to-market) gains and losses, totaled $164 million in 2005 and $103 million in 2004. Because most of the hedging and risk management activities are intended to mitigate the risk of commodity price movements on revenues and fuel and purchased power costs, the changes in such results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on gross margin. Results in 2005 included:

• $133 million in net realized losses associated with hedges entered into in prior years (largely 2003), the offsetting effects of which are reported in revenues and fuel and purchased power costs. This amount includes $88 million in losses related to cash flow hedges, which had been recognized in other comprehensive income;

• $84 million reversal of net unrealized gains previously recognized on power positions settled in the current period, the offsetting effects of which are reported in revenues and fuel and purchased power costs;

• $79 million in net realized gains on settlement of commodity trading positions largely entered into in 2005 and relating primarily to natural gas; and

• $31 million of unrealized ineffectiveness losses relating to cash flow hedges principally related to the long-term hedging program.

Gross Margin

	Year Ended December 31,
	2005		% of Revenue		2004		% of Revenue
	(millions of dollars)
Operating revenues	$	9,552	100	%	$	8,402	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		5,545	58			5,173	62
Generation plant operating costs		668	7			703	8
Depreciation and amortization		309	3			327	4
Gross margin	$	3,030	32	%	$	2,199	26	%

Gross margin increased $831 million, or 38%, to $3.0 billion in 2005. This growth primarily reflected the relatively low fuel costs of TCEH’s nuclear and lignite/coal-fueled baseload plants, as well as the continued improved productivity of the baseload plants, in an environment of increasing wholesale power prices. The increased wholesale power prices were driven by rising natural gas prices. Retail prices, including price-to-beat retail prices, were increased in response to higher wholesale prices. The gross margin performance was mitigated by the effect of lower retail sales volumes.

Gross margin as a percent of revenues increased 6 percentage points to 32%. The improvement reflected:

• higher pricing, as the average retail sales price per MWh rose 20%, and the average wholesale sales price per MWh rose 38% (15 percentage point margin increase),

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partially offset by:

• higher purchased power costs driven by a 26% increase in average purchased power prices (5 percentage point margin decrease); and

• a 17% decrease in retail sales volumes (4 percentage point margin decrease).

Operating costs decreased $35 million, or 5%, to $668 million in 2005. The decline reflected:

• $30 million in lower benefits expense including $13 million in lower pension and other postretirement benefit costs (see discussion in SG&A expenses below regarding these costs);

• the absence of $18 million of costs associated with 9 combustion turbine units no longer operated for TCEH’s benefit;

• a $17 million effect of no longer providing customer care support to TXU Gas (largely offset by lower related revenues), the operations of which were sold in October 2004; and

• the absence of $8 million of costs associated with the TXU Fuel business sold in June 2004,

partially offset by:

• $25 million in higher maintenance costs associated with planned nuclear unit outages in 2005, reflecting two outages in 2005 and one outage in 2004; and

• $15 million in supplier credits recorded in 2004.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) decreased $37 million, or 11%, to $313 million. The decline included $19 million due to the effect of the transfer of information technology assets, principally capitalized software, to a Energy Future Holdings Corp. affiliate in connection with the Capgemini outsourcing transaction. The decrease also reflected a $13 million effect of reduced 2005 depreciation rates for lignite/coal-fueled plants due to extending the estimated useful lives.

SG&A expenses decreased by $144 million, or 22%, to $522 million in 2005. The decline reflected:

• a net $64 million decline due to cost reduction initiatives, including the effect of the Capgemini outsourcing agreement;

• $41 million in reduced incentive compensation expense including a $15 million one-time incentive compensation program in wholesale operations in 2004;

• $38 million in lower bad debt expense as a result of refining and consistently applying credit and collection policies; and

• an $11 million net decrease in employee retirement-related expenses primarily due to the assumption by Oncor Electric Delivery of pension and other postretirement benefit costs related to service of TCEH’s employees prior to the unbundling of Energy Future Holdings Corp.’s electric utility business and the deregulation of the Texas electricity industry effective January 1, 2002 (see Note 21 to the 2006 year-end Financial Statements),

partially offset by $14 million in higher consulting expense primarily related to development and implementation of the Luminant Operating System to improve efficiency of generation plant and mining operations.

Other income totaled $64 million in 2005 and $110 million in 2004. Other income in 2005 included:

• $33 million in gains on the sale of undeveloped land and mining land;

• an $8 million insurance reimbursement related to a generation plant fire in 2002;

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• a $7 million gain on the sale of an investment in an out-of-state electricity transmission project;

• $4 million in connection with the termination of a power services contract; and

• $2 million gain on the sale of surplus equipment.

Other income in 2004 included:

• $88 million in amortization of the gain on the 2002 sale of two generation plants including $58 million of the remaining unamortized gain recognized as a result of the termination of a related power purchase and tolling agreement; and

• a $19 million gain on sale of undeveloped land.

Other deductions totaled $15 million in 2005 and $611 million in 2004. The 2005 amount includes:

• a $12 million charge related to nonperformance of a counterparty in connection with a trading coal contract;

• $12 million in transition costs associated with the Capgemini outsourcing agreement;

• $7 million in equity losses (representing depreciation expense) in the Energy Future Holdings Corp. entity holding the capitalized software licensed to Capgemini;

• $6 million in accretion expense related to the 2004 impairment of a lease for gas-fueled combustion turbines no longer operated for TCEH’s benefit;

• a $16 million net credit adjusting the impairment loss on the leased gas-fueled combustion turbines to reflect actual sub-lease proceeds under the terms of a third-party contract entered into in 2005; and

• the release of a previously recorded $6 million reserve for restoration of property that is now expected to be used in generation plant development.

The 2004 amount includes:

• $180 million in lease-related charges primarily related to generation and mining assets taken out of service;

• $107 million in software write-offs;

• $107 million for employee severance;

• $101 million in termination costs for an existing power purchase and tolling agreement; and

• $79 million for spare parts inventory writedowns.

Interest income increased by $39 million to $70 million in 2005 reflecting higher interest on short-term investments and higher average advances to affiliates.

Interest expense and related charges increased by $40 million, or 11%, to $393 million in 2005. The increase reflected $26 million due to higher average interest rates and $14 million due to higher average debt levels.

The effective income tax rate was 32.5% in 2005 and 28.4% in 2004. The increase reflects the effect of ongoing relatively fixed tax benefits of lignite depletion allowances and amortization of investment tax credits on a significantly higher 2005 income base. The 2005 effective income tax rate also reflects a $29 million credit for the reversal of previously established tax reserves due to current period events, partially offset by $10 million in additional tax expense related to settlement of the IRS audit for the 1994 to 1996 tax years.

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Income from continuing operations increased $1.0 billion to $1.4 billion in 2005 driven by improved gross margin, the effect of restructuring-related charges in 2004 and lower SG&A expenses.

Regulated Delivery Segment

Financial Results

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Operating revenues	$	2,449		$	2,394		$	2,226
Costs and expenses:
Operating costs		770			758			730
Depreciation and amortization		476			446			389
Selling, general and administrative expenses		177			201			219
Franchise and revenue-based taxes		262			247			248
Other income		(2	)		(4	)		(7	)
Other deductions		24			11			52
Interest income		(58	)		(59	)		(56	)
Interest expense and related charges		286			269			280
Total costs and expenses		1,935			1,869			1,855
Income before income taxes, extraordinary gain and cumulative effect of change in accounting principle		514			525			371
Income tax expense		170			174			116
Income before extraordinary gain and cumulative effect of change in accounting principle	$	344		$	351		$	255

Regulated Delivery Segment

Operating Data

	Year Ended December 31,						% Change 2006/2005		% Change 2005/2004
	2006		2005		2004
Operating statistics—volumes:
Electric energy delivered (GWh)		107,098		106,780		101,928	0.3		4.8
Reliability statistics(a):
System Average Interruption Duration Index (SAIDI) (nonstorm)		79.09		76.79		75.51	3.0		1.7
System Average Interruption Frequency Index (SAIFI) (nonstorm)		1.17		1.17		1.10	—		6.4
Customer Average Interruption Duration Index (CAIDI) (nonstorm)		67.54		65.60		68.75	3.0		(4.6	)
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters)(b)		3,056		3,013		2,971	1.4		1.4
Operating Revenues:
Electricity distribution revenues(c):
Affiliated (TCEH)	$	1,137	$	1,276	$	1,418	(10.9	)	(10.0	)
Nonaffiliated		1,046		879		590	19.0		49.0
Total distribution revenues		2,183		2,155		2,008	1.3		7.3
Third-party transmission revenues		236		213		192	10.8		10.9
Other miscellaneous revenues		30		26		26	15.4		—
Total operating revenues	$	2,449	$	2,394	$	2,226	2.3		7.5

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(a) SAIDI is the average number of electric service interruption minutes per consumer in a year. SAIFI is the average number of electric service interruptions per consumer in a year. CAIDI is the average duration in minutes per electric service interruption in a year. The statistics presented are based on the preceding twelve months’ data.

(b) Includes lighting sites, primarily guard lights, for which TCEH is the REP but are not included in TCEH’s customer count. Such sites totaled 82,337, 86,495 and 95,252 at December 31, 2006, 2005 and 2004, respectively.

(c) Includes transition charges associated with the issuance of securitization bonds totaling $151 million, $152 million and $106 million for the years ended December 31, 2006, 2005 and 2004, respectively. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.

Regulated Delivery Segment

Regulated Delivery’s future results are expected to be impacted by the effects of the cities rate settlement described in Note 9 to the 2006 year-end Financial Statements. Incremental expenses of approximately $70 million are being recognized almost entirely over the period from May 2006 through June 2008, of which $18 million has been recognized in the 2006 period.

2006 compared to 2005

Operating revenues increased $55 million, or 2%, to $2.4 billion in 2006. Delivered volumes rose less than 1%. The revenue increase reflected:

• $24 million in higher transmission revenues primarily due to rate increases approved in 2005 and 2006 to recover ongoing investment in the transmission system;

• an estimated $16 million due to growth in points of delivery; and

• $9 million from increased distribution tariffs to recover higher transmission costs.

The effect of warmer weather on electricity consumption was largely offset by end-user efficiency measures in response to higher prices and warmer weather.

Gross Margin

	Year Ended December 31,
	2006		% of Revenue		2005		% of Revenue
	(millions of dollars)
Operating revenues	$	2,449	100	%	$	2,394	100	%
Costs and expenses:
Transmission and distribution system operating costs		770	31	%		758	32	%
Depreciation and amortization		474	20	%		446	18	%
Gross margin	$	1,205	49	%	$	1,190	50	%

Operating costs rose $12 million, or 2%, to $770 million in 2006. The increase reflected $19 million in increased fees paid to third party transmission entities, partially offset by $6 million due to increased labor capitalization rates and timing of expenses related to advanced meter installations.

Depreciation and amortization (essentially all of which related to the delivery system as shown in the gross margin table above) increased $30 million, or 7%, to $476 million in 2006. The increase reflected $23 million in depreciation related to normal additions and replacements of property, plant and equipment and a $4 million adjustment related to capitalized software costs.

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SG&A expenses decreased $24 million, or 12%, to $177 million in 2006. The decrease reflected:

• $8 million in lower incentive compensation expense;

• $4 million in decreased employee benefits expense;

• $3 million in lower bad debt expense;

• $3 million in lower legal and consulting fees; and

• $3 million in lower research and development costs.

partially offset by, $3 million in higher sale of receivables program fees driven by higher interest rates.

Franchise and revenue-based taxes increased $15 million, or 6%, to $262 million in 2006. The increase was driven by higher delivered volumes in the period to which the tax applies and also includes $5 million in higher franchise fees under the cities rate settlement. See Note 9 to the 2006 year-end Financial Statements.

Other deductions totaled $24 million in 2006 and $11 million in 2005. The 2006 amount includes:

• $13 million in costs as a result of the 2006 cities rate settlement (See Note 9 to the 2006 year-end Financial Statements);

• $7 million in transition costs related to the InfrastruX Energy Services joint venture; and

• $4 million in equity losses (representing amortization expense) related to the ownership interest in the Energy Future Holdings Corp. subsidiary holding the capitalized software licensed to Capgemini.

The 2005 amount included:

• $3 million in costs associated with transitioning the outsourced activities to Capgemini;

• $3 million in equity losses (representing amortization expense) related to the ownership interest in the Energy Future Holdings Corp. subsidiary holding the capitalized software licensed to Capgemini; and

• $2 million of severance-related charges related to the 2004 restructuring actions.

Interest expense increased $17 million, or 6%, to $286 million in 2006 due to higher average balances of commercial paper outstanding.

Income tax expense totaled $170 million in 2006 compared to $174 million in 2005. The effective tax rate was comparable at 33.1% for both 2006 and 2005.

Income from continuing operations decreased $7 million, or 2%, to $344 million driven by costs associated with the cities rate settlement and expenses related to the InfrastruX Energy Services agreement.

Regulated Delivery Segment

2005 compared to 2004

Operating revenues increased $168 million, or 8%, to $2.4 billion in 2005. This change reflected:

• $46 million in higher transition charges associated with the issuance of securitization bonds in June 2004 (offset in total by higher amortization of the related regulatory asset as discussed below);

• approximately $30 million related to warmer summer weather;

• $22 million from continued implementation of power factor billing (power factor billing is a tariff adjustment applied to nonresidential end-use consumers that utilize inefficient equipment);

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• $21 million in base growth reflecting an increase in points of delivery;

• $21 million from increased distribution tariffs to recover higher transmission costs; and

• $21 million in increased transmission revenues due to rate increases approved in 2005 and 2004 and higher volumes.

Gross Margin

	Year Ended December 31,
	2005		% of Revenue		2004		% of Revenue
	(millions of dollars)
Operating revenues	$	2,394	100	%	$	2,226	100	%
Costs and expenses:
Transmission and distribution system operating costs		758	32	%		730	33	%
Depreciation and amortization		446	18	%		386	17	%
Gross margin	$	1,190	50	%	$	1,110	50	%

Gross margin increased $80 million, or 7%, to $1.2 billion in 2005. The increase was driven by higher operating revenues.

Operating costs rose $28 million, or 4%, to $758 million. This increase reflected:

• $13 million in increased spending for system reliability initiatives;

• $7 million in higher property taxes primarily due to increased investments in property;

• $4 million in increased metering expenses due to increased labor costs to accommodate increased consumer requested activities;

• $3 million in increased third-party transmission costs due to increased rates; and

• $3 million in higher transportation expense due to an increase in fuel and lease costs,

partially offset by:

• $4 million in decreased employee benefits costs, reflecting lower health care costs due to plan changes; and

• $4 million in reduced pension and OPEB costs. This reduction reflects an amendment to PURA as discussed in Note 21 to the 2006 year-end Financial Statements.

Depreciation and amortization (consisting almost entirely of amounts shown in the gross margin table above) increased $57 million, or 15%, to $446 million in 2005. The increase reflected $46 million in higher amortization of regulatory assets associated with the issuance of transition bonds (offsetting the same amount of revenue increase) and $14 million in higher depreciation due to normal additions and replacements of property, plant, and equipment, partially offset by a $3 million decline reflecting the July 2004 transfer of information technology assets, principally capitalized software, to a Energy Future Holdings Corp. affiliate in connection with the Capgemini outsourcing transaction.

SG&A expense decreased $18 million, or 8%, to $201 million in 2005. The decline included:

• $16 million from cost reduction initiatives including the effects of the Capgemini agreement;

• $5 million in decreased employee benefits, reflecting lower health care costs due to plan changes; and

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• $2 million in reduced pension and OPEB costs, as a result of the amendment to PURA,

partially offset by $3 million higher bad debt expense largely resulting from the establishment of an allowance for uncollectible accounts based on a credit-scoring methodology applied to outstanding REP accounts receivable.

Other deductions totaled $11 million in 2005 and $52 million in 2004. The 2005 amount included:

• $3 million in costs associated with transitioning the outsourced activities to Capgemini;

• $3 million in equity losses (representing amortization expense) related to the ownership interest in the Energy Future Holdings Corp. subsidiary holding the capitalized software licensed to Capgemini; and

• $2 million of severance-related charges resulting from the 2004 restructuring actions.

The 2004 amount included:

• a $21 million charge for estimated settlement payments arising from the 2004 cities rate settlement;

• $20 million of severance-related charges in connection with the Capgemini outsourcing transaction and other Energy Future Holdings Corp. restructuring actions; and

• $8 million related to transitioning the outsourced activities to Capgemini, including asset write-downs and other unusual charges.

Interest expense decreased $11 million, or 4%, to $269 million in 2005. The decrease includes $9 million from the impact of lower average interest rates and $2 million due to an increase in allowance for funds used during construction (capitalized interest) on higher construction expenditures.

The effective income tax rate increased to 33.1% in 2005 from 31.3% in 2004. The increase is due primarily to the effect of ongoing relatively fixed amortization of tax benefits (statutory tax rate changes and investment tax credits) on a higher 2005 income base, partially offset by $4 million credit in 2005 arising from the settlement of the IRS audit for the 1994 through 1996 tax years.

Income before extraordinary gain and cumulative effect of a change in accounting principle (an after-tax measure) increased $96 million, or 38%, to $351 million. This increase was driven by higher operating revenues and the impact of unusual charges in 2004 reported in other deductions.

COMPREHENSIVE INCOME—Continuing Operations

Cash flow hedge activity reported in other comprehensive income from continuing operations included (all amounts after-tax):

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Net increase (decrease) in fair value of cash flow hedges (all commodity) held at end of period	$	568		$	(47	)	$	(75	)
Derivative value net losses (gains) reported in net income that relate to hedged transactions recognized in the period:
Commodities		(23	)		64			21
Financing—interest rate swaps(a)		8			13			23
		(15	)		77			44
Total income (loss) effect of cash flow hedges reported in other comprehensive from continuing operations	$	553		$	30		$	(31	)

(a) Represents recognition of net losses on settled swaps.

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Energy Future Holdings Corp. has historically used, and expects to continue to use, derivative instruments that are effective in offsetting future cash flow variability in interest rates and energy commodity prices. The amounts included in accumulated other comprehensive income are expected to offset the impact of rate or price changes on forecasted transactions. Amounts in accumulated other comprehensive income include (i) the value of open cash flow hedges (for the effective portion), based on current market conditions, and (ii) the value of dedesignated and terminated cash flow hedges at the time of such dedesignation, less amounts reclassified to earnings as the original hedged transactions are recognized, unless the hedged transactions become probable of not occurring. The effects of the hedge will be recorded in the statement of income as the hedged transactions are actually settled and affect earnings. Also see Note 19 to the 2006 year-end Financial Statements.

See discussion in Note 21 to the 2006 year-end Financial Statements regarding the minimum pension liability adjustments reported in other comprehensive income.

Financial Condition—Historical/Pre-Merger

Liquidity and Capital Resources

Cash Flows—Cash flows used in operating activities for the six months ended June 30, 2007 totaled $55 million compared to cash flows provided by operating activities of $1.9 billion for the six months ended June 30, 2006. The decrease of $2.0 billion reflected:

• lower operating earnings after taking into account noncash items such as deferred federal income taxes, unrealized mark-to-market valuations and charges related to suspended development of generation facilities;

• an unfavorable change of $959 million in net margin deposits due to the effect of higher forward natural gas prices on hedge positions;

• an unfavorable change in working capital (accounts receivable, accounts payable and inventories) balances of $252 million primarily due to the effects of lower natural gas prices, as cash flows in 2006 included the collection of higher wholesale natural gas and electricity receivables that resulted from higher prices in late 2005; and

• a $102 million premium paid in 2007 related to a structured natural gas-related option transaction entered into as part of the long-term hedging program.

Cash flows provided by financing activities totaled $1.9 billion for the six months ended June 30, 2007 compared to cash flows used by financing activities of $806 million for the six months ended June 30, 2006 as summarized below:

	Six Months Ended June 30,
	2007			2006
	(millions of dollars)
Net issuances, repayments and repurchases of borrowings	$	2,433		$	263
Net issuances and repurchases of common stock		(9	)		(629	)
Common stock dividends paid		(397	)		(384	)
Settlements of minimum withholding tax liabilities under stock-based incentive compensation plans		(93	)		(56	)
Total	$	1,934		$	(806	)

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Cash flows used in investing activities increased $444 million in the six months ended June 30, 2007 compared to the same period in 2006 as summarized below:

	Six Months Ended June 30,
	2007			2006
	(millions of dollars)
Capital expenditures, including nuclear fuel	$	(1,641	)	$	(855	)
Reduction of restricted cash related to the redemption of pollution control revenue bonds		143			—
Purchase of lease trust		—			(69	)
Proceeds from pollution control revenue bonds deposited with trustee		—			(99	)
Net investments in nuclear decommissioning trust fund securities		(7	)		(7	)
Investment in unconsolidated affiliate		—			(15	)
Costs to remove retired property		(16	)		(22	)
Other		15			5
Total	$	(1,506	)	$	(1,062	)

The $786 million, or 92%, increase in capital expenditures was driven by new generation facility development spending.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $30 million for the six months ended June 30, 2007. This difference represents amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice.

Cash flows provided by operating activities for the year ended December 31, 2006 increased $2.2 billion, or 77%, to $4.9 billion as compared to the year ended December 31, 2005. The improvement reflected:

• higher operating earnings after taking into account noncash items such as deferred federal income taxes, unrealized mark-to-market valuations and the generation plant impairment charge;

• a favorable change of $503 million in net margin deposits, primarily reflecting amounts received from counterparties related to natural gas positions in the long-term hedging program; and

• a favorable change of $293 million in working capital (accounts receivable, accounts payable and inventories) driven by higher wholesale natural gas and electricity receivables in 2005 due to higher prices in the fourth quarter of 2005.

Cash flows provided by operating activities for the year ended December 31, 2005 increased $1.0 billion, or 59%, to $2.8 billion as compared to the year ended December 31, 2004. The increase was driven by higher earnings.

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Cash flows used in financing activities were $2.3 billion in 2006, $1.6 billion in 2005 and $6.5 billion in 2004. The drivers of the $769 million increase in cash used in finance activities from 2005 to 2006 and the $5.0 billion decrease in cash used in financing activities from 2004 to 2005 are summarized in the table below:

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Cash used in financing activities:
Net issuances and (repayments) of borrowings, including premiums and discounts	$	(777	)	$	356		$	155
Net repurchases of common stock		(832	)		(1,054	)		(4,575	)
Repurchase of preference stock		—			(300	)		—
Repurchase of preferred securities of subsidiaries		—			(38	)		(75	)
Repurchase of exchangeable preferred membership interests		—			—			(1,852	)
Payment of common stock dividends		(764	)		(544	)		(150	)
Payment of preference stock dividends		—			(11	)		(22	)
Excess tax benefit on stock-based compensation		41			28			—
Total	$	(2,332	)	$	(1,563	)	$	(6,519	)

Investing activities used cash flows of $2.7 billion in 2006, $1.0 billion in 2005 and provided cash flows of $4.3 billion in 2004. The table below details the business activities impacting investing cash flows.

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Cash provided by (used in) investing activities:
Capital expenditures, including nuclear fuel	$	(2,297	)	$	(1,104	)	$	(999	)
Sale of TXU Australia		—			—			1,885
Disposition of TXU Gas		—			—			1,905
Sale of TXU Fuel		—			—			500
Sale of telecommunications business		—			—			524
Purchase of lease trust		(69	)		—			—
Deposit of proceeds from pollution control revenue bonds with trustee		(240	)		—			—
Proceeds from sale of assets		20			77			27
Return of investment in trust to support a credit facility		—			—			525
Investment in unconsolidated affiliate		(15	)		—			—
Net investments in nuclear decommissioning trust fund securities		(16	)		(15	)		(15	)
Costs to remove retired property		(40	)		(44	)		(40	)
Other		(7	)		48			(32	)
Total	$	(2,664	)	$	(1,038	)	$	4,280

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $63 million, $60 million and $66 million for 2006, 2005 and 2004, respectively. This difference represents amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice.

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Long-term Debt Activity—During the six months ended June 30, 2007, Energy Future Holdings Corp. issued, reacquired or made scheduled principal payments on long-term debt as follows (all amounts presented are principal):

	Issuances		Repayments and Repurchases
	(millions of dollars)
Energy Future Holdings Corp.:
Other long-term debt	$	—	$	(6	)
TCEH:
Floating rate senior notes		1,000		—
Pollution control revenue bonds		—		(143	)
Other long-term debt		—		(6	)
Oncor Electric Delivery:
Floating rate senior notes		800		—
Transition bonds		—		(48	)
Energy Future Competitive Holdings		—		(8	)
Total	$	1,800	$	(211	)

During the year ended December 31, 2006, Energy Future Holdings Corp. reacquired or made scheduled principal payments on long-term debt as follows (all amounts presented are principal):

	Repayments and Repurchases
	(millions of dollars)
Energy Future Holdings Corp.:
Senior notes	$	733
Equity-linked senior notes		179
Other long-term debt		10
TCEH:
Pollution control revenue bonds	$	259
Senior notes		400
Other long-term debt		5
Oncor Electric Delivery:
Transition bonds		93
Energy Future Competitive Holdings		12
Total	$	1,691

Issuances for the year ended December 31, 2006 totaled $243 million in pollution control revenue bonds at TCEH. Scheduled principal payments in 2007 total $485 million.

Interest rate swaps related to $300 million and $1.85 billion principal amount of debt were dedesignated as fair value hedges in December 2006 and January 2007, respectively. Offsetting swap positions were entered into, and both the original swaps and offsetting positions are subsequently being marked-to-market in net income.

See Note 9 to the June 30, 2007 Financial Statements and Note 15 to the 2006 year-end Financial Statements for further detail of long-term debt and other financing arrangements.

Credit Facilities/Commercial Paper—As of October 10, 2007, subsidiaries of Energy Future Holdings Corp. repaid and terminated their credit facilities. See Note 8 to the 2006 year-end Financial Statements for details of the arrangements. Availability under these facilities at June 30, 2007 declined $2.4 billion from year-end 2006 primarily due to incremental credit support requirements related largely to the long-term hedging program, capital expenditures and borrowings to repay all outstanding commercial paper as it matured due to the

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effects of rating agency actions on the commercial paper program. Commercial paper maturities totaled $1.3 billion in the first six months of 2007. These credit facilities will be repaid and replaced upon closing of the Merger.

Capitalization—The capitalization ratios of Energy Future Holdings Corp. at June 30, 2007, consisted of 91.9% long-term debt, less amounts due currently, and 8.1% common stock equity. The capitalization ratios of Energy Future Holdings Corp. at December 31, 2006, consisted of 83.2% long-term debt, less amounts due currently, and 16.8% common stock equity. Total debt to capitalization, including short-term debt, was 85.5% at December 31, 2006.

Pension Plan Funding—In August 2006, the Pension Protection Act of 2006 (the “Act”) was signed into law. The Act which will be phased in over the next few years is expected to increase pension plan funding and require additional plan disclosures in regulatory filings and to plan participants. Energy Future Holdings Corp. expects to make required contributions to its pension plan of $1 million in 2007 and $161 million in 2008. Contributions to the pension plan in 2006 totaled $4 million.

Income Tax Payments—Such payments totaled $214 million and $18 million in the first six months of 2007 and 2006, respectively. Energy Future Holdings Corp. cannot reasonably estimate the ultimate timing of tax payments associated with uncertain tax positions, but none are expected in the next 12 months. Excluding the effects of any potential transactions or audit settlements with the IRS, federal income tax payments in 2007 are estimated to total approximately $430 million. Federal income tax payments totaled $220 million in 2006.

Short-term Borrowings—On October 10, 2007, subsidiaries of Energy Future Holdings Corp. repaid all outstanding bank borrowings under their credit facilities.

Dividends—At its August 2007 meeting, the Board of Directors of Energy Future Holdings Corp. declared a quarterly dividend of 43.25 cents per share, which is payable on October 1, 2007 to shareholders of record on September 7, 2007. At its May 2007 meeting, the Board of Directors of Energy Future Holdings Corp. declared a quarterly dividend of 43.25 cents per share, which was paid on July 2, 2007 to shareholders of record on June 1, 2007. At its February 2007 meeting, the Board of Directors of Energy Future Holdings Corp. declared a quarterly dividend of 43.25 cents per share, which was paid on April 2, 2007 to shareholders of record on March 2, 2007.

On November 3, 2006, the Board of Directors of Energy Future Holdings Corp. declared a common stock dividend in the amount of 43.25 cents per share, an increase of 5% over the previous quarter, payable on January 2, 2007 to shareholders of record as of December 1, 2006. The increase sets the common stock dividend at an annual rate of $1.73 per share.

Sales of Accounts Receivable—Subsidiaries of Energy Future Holdings Corp. participate in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, subsidiaries of Energy Future Holdings Corp. (originators) sell trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of Energy Future Holdings Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions. All new trade receivables under the program generated by the originators are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $527 million and $627 million at June 30, 2007 and December 31, 2006, respectively. See Note 7 to June 30, 2007 Financial Statements and Note 13 to the 2006 year-end Financial Statements for a more complete description of the program including the impact on the financial statements for the periods presented and the contingencies that could result upon the termination of the program. This program was amended in connection with the Merger.

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Liquidity Effects of Risk Management and Trading Activities—Risk management and trading transactions typically require collateral to support potential future payment obligations. In particular, commodity transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument is out-of-the-money to such counterparty. Energy Future Holdings Corp. and its subsidiaries typically use cash and letters of credit to satisfy such collateral obligations. In addition, Energy Future Holdings Corp. and its subsidiaries continuously explore the use of other forms of collateral to maximize liquidity. For example, given the scale of Energy Future Holdings Corp.’s long-term hedging program, certain hedging transactions are currently supported with a first-lien security interest in the assets of Big Brown Power Company LLC (formerly TXU Big Brown Company LP) consisting of two existing lignite/coal-fueled generation units (“Big Brown Lien”) as well as a guarantee from TCEH. The Big Brown Lien supported hedging transactions for up to an aggregate of 1.2 billion MMBtu of natural gas. As of October 10, 2007, approximately half of the long-term hedging program position was supported with cash and letter of credit collateral while the other half was supported by the Big Brown Lien. Upon the closing of the Merger, the transactions that were secured by the Big Brown Lien will become pari passu with the TCEH Senior Secured Facilities and the TCEH guarantee will be terminated.

As of September 30, 2007, subsidiaries of Energy Future Holdings Corp. have received or posted cash and letters of credit for risk management and trading activities as follows:

• $31 million in cash has been posted as of September 30, 2007 related to daily margin settled transactions, principally associated with positions in the long-term hedging program, as compared to $672 million received as of December 31, 2006;

• $63 million in cash has been posted with over-the-counter and all other counterparties as collateral as of September 30, 2007, as compared to $2 million received as of December 31, 2006; and

• $603 million in letters of credit have been posted with all counterparties as collateral as of September 30, 2007, as compared to $455 million posted as of December 31, 2006.

With respect to exchange cleared transactions, these transactions typically require initial margin (i.e. the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variation margin (i.e. the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. With respect to cash collateral that is received, such cash collateral is used by Energy Future Holdings Corp. and its subsidiaries for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities. Such counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing Energy Future Holdings Corp.’s liquidity.

As a result of the long-term hedging program, any increase in natural gas prices results in increased cash and letter of credit margin requirements for Energy Future Holdings Corp. and its subsidiaries. Significant increases in cash and letter of credit margin requirements, whether resulting from initial margin or variation margin requirements or otherwise, could have a material adverse impact on Energy Future Holdings Corp.’s liquidity. As a representative example, as of September 30, 2007, for each $1.00 per MMBtu increase in natural gas prices, Energy Future Holdings Corp.’s liquidity could have been reduced by approximately $1.2 billion as a result of cash and letter of credit variation margin posting requirements associated with the long-term hedging program.

Financial Covenants The terms of certain financing arrangements of subsidiaries of Energy Future Holdings Corp. contain financial covenants that require maintenance of specified fixed charge coverage ratios and leverage ratios and/or contain minimum net worth covenants. As of June 30, 2007 and December 31, 2006, Energy Future Holdings Corp.’s subsidiaries were in compliance with all such applicable covenants.

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Historical Long-term Contractual Obligations and Commitments—The following table summarizes Energy Future Holdings Corp.’s contractual cash obligations as of December 31, 2006 (see Notes 15 and 16 to the 2006 year-end Financial Statements for additional disclosures regarding these long-term debt and noncancelable purchase obligations).

Contractual Cash Obligations	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years			Total
	(millions of dollars)
Long-term debt—principal	$	474	$	1,705	$	278	$	8,644	��	$	11,101
Long-term debt—interest(a)		696		1,262		1,134		5,946			9,038
Operating and capital leases(b)		69		126		111		332			638
Contracts related to generation development program(c)		1,301		896		—		—			2,197
Obligations under commodity purchase and services agreements(d)		2,075		2,432		851		1,237			6,595
Total contractual cash obligations(e)	$	4,615	$	6,421	$	2,374	$	16,159		$	29,569

(a) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect at December 31, 2006.

(b) Includes short-term noncancellable leases.

(c) Amounts represent scheduled payments under the contracts for the three proposed new generation units. See Note 16 to the 2006 year-end Financial Statements.

(d) Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments. Amounts presented for variable priced contracts assumed the year-end 2006 price remained in effect for all periods except where contractual price adjustment or index-based prices were specified.

(e) Table does not include estimated 2007 funding of the pension and other postretirement benefits plans totaling approximately $28 million.

The following contractual obligations were excluded from the table above:

• contracts between affiliated entities and intercompany debt;

• individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one counterparty that are more than $1 million on an aggregated basis have been included);

• contracts that are cancelable without payment of a substantial cancellation penalty;

• income tax payments associated with uncertain tax positions that cannot reasonably be estimated;

• Cities rate settlement agreement, which is discussed below; and

• employment contracts with management.

Off Balance Sheet Arrangements

Energy Future Holdings Corp. has established an accounts receivable securitization program. See discussion above under “—Sales of Accounts Receivables” and in Note 7 to the June 30, 2007 Financial Statements and Note 13 to the 2006 year-end Financial Statements.

Energy Future Holdings Corp. has an ownership interest in the Capgemini outsourcing business. See Note 20 to the 2006 year-end Financial Statements.

Also see Note 10 to the June 30, 2007 Financial Statements and Note 16 in the 2006 year-end Financial Statements regarding guarantees.

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Commitments and Contingencies

See Note 10 to the June 30, 2007 Financial Statements and Note 16 to the 2006 year-end Financial Statements for discussion of commitments and contingencies.

Changes in Accounting Standards

See Notes 1 and 3 to the June 30, 2007 Financial Statements and Notes 1 and 21 to the 2006 year-end Financial Statements for a discussion of changes in accounting standards.

Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk that Energy Future Holdings Corp. may experience a loss in value as a result of changes in market conditions affecting commodity prices and interest rates, which Energy Future Holdings Corp. is exposed to in the ordinary course of business. Energy Future Holdings Corp.’s exposure to market risk is affected by a number of factors, including the size, duration and composition of its energy and financial portfolio, as well as the volatility and liquidity of markets. Energy Future Holdings Corp. enters into instruments such as interest rate swaps to manage interest rate risks related to its indebtedness, as well as exchange traded, over-the-counter contracts and other contractual commitments to manage commodity price risk as part of its wholesale activities.

Risk Oversight

Energy Future Holdings Corp.’s wholesale operation manages the commodity price, counterparty credit and operational risk related to the unregulated energy business within limitations established by senior management and in accordance with Energy Future Holdings Corp.’s overall risk management policies. Interest rate risks are managed centrally by the corporate treasury function. Market risks are monitored daily by risk management groups that operate and report independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, Value at Risk (“VaR”) methodologies. Key risk control activities include, but are not limited to, credit review and approval, operational and market risk measurement, validation of transaction capture, portfolio valuation and daily portfolio reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

Energy Future Holdings Corp. has a corporate risk management organization that is headed by a Chief Risk Officer. The Chief Risk Officer, through his designees, enforces all applicable risk limits, including the respective policies and procedures to ensure compliance with such limits and evaluates the risks inherent in the various businesses of Energy Future Holdings Corp. and their associated transactions.

Commodity Price Risk

Energy Future Holdings Corp.’s businesses are subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products they market or purchase. Energy Future Holdings Corp.’s businesses actively manage their portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. These businesses, similar to other participants in the market, cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices and spark spreads (differences between the market price of electricity and its cost of production).

In managing energy price risk, subsidiaries of Energy Future Holdings Corp. enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange traded and over-the-counter financial contracts and bilateral contracts with customers. Activities in the wholesale operations include hedging, the structuring of long-term contractual arrangements and proprietary trading. The

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wholesale operation continuously monitors the valuation of identified risks and adjusts the portfolio based on current market conditions. Valuation adjustments or reserves are established in recognition that certain risks exist until full delivery and settlement of energy has occurred, counterparties have fulfilled their financial commitments and related contracts have either matured or are settled. Energy Future Holdings Corp. strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

Long-term Hedging Program—See discussion above under “—Significant Developments” for an update of the program, including potential effects on reported results.

VaR Methodology—A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio’s potential for loss given a specified confidence level and considers among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.

A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effective way to estimate changes in a portfolio’s value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e. the time necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlation data.

Energy Future Holdings Corp. regularly reviews its risk analysis metrics. In the course of a review in 2006, it was determined that the Cash Flow at Risk metric previously disclosed is not a meaningful measure of actionable commodity price risk. It was also determined that providing a Trading VaR would enhance disclosure. Trading VaR includes all natural gas and electricity-related contracts entered into for trading purposes. Energy Future Holdings Corp. may add or eliminate other metrics in the future in its disclosures of risks.

Trading VaR—This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts entered into for trading purposes based on a 95% confidence level and an assumed holding period of five to 60 days.

	Six Months Ended June 30, 2007		Year Ended December 31, 2006
Month-end average Trading VaR:	$	9	$	12
Month-end high Trading VaR:	$	11	$	30
Month-end low Trading VaR:	$	6	$	5

In a review performed in 2006 of the holding period for VaR calculations presented below, Energy Future Holdings Corp. determined that a holding period of five to 60 days, instead of the five-day holding period previously assumed, would be more reflective of the time it would take to liquidate the portfolio, considering the increase in longer-dated positions (principally related to the long-term hedging program) and the associated liquidity effects.

VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting—This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period as presented below.

	Six Months Ended June 30, 2007		Year Ended December 31, 2006
	Five to 60 day holding period		Five to 60 day holding period
Month-end average MtM VaR:	$	714	$	149
Month-end high MtM VaR:	$	1,013	$	391
Month-end low MtM VaR:	$	322	$	5

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	Year Ended December 31, 2006				Year Ended December 31, 2005
	Five to 60 day holding period		Five-day holding period		Five-day holding period
Month-end average MtM VaR:	$	149	$	48	$	19
Month-end high MtM VaR:	$	391	$	117	$	27
Month-end low MtM VaR:	$	5	$	5	$	12

Earnings at Risk (EaR)—This measurement estimates the potential reduction of fair value of expected pretax earnings for the years presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). For this purpose, cash flow hedges are also included with transactions that are not marked-to-market in net income. A 95% confidence level is assumed in determining EaR.

	Six Months Ended June 30, 2007		Year Ended December 31, 2006
	Five to 60 day holding period		Five to 60 day holding period
Month-end average EaR:	$	707	$	156
Month-end high EaR:	$	991	$	387
Month-end low EaR:	$	318	$	21

	Year Ended December 31, 2006				Year Ended December 31, 2005
	Five to 60 day holding period		Five-day holding period		Five-day holding period
Month-end average EaR:	$	99	$	41	$	23
Month-end high EaR:	$	241	$	72	$	41
Month-end low EaR:	$	21	$	21	$	3

The increases in the risk measures (MtM VaR and EaR) in 2007 are driven by the dedesignation of positions in the long-term hedging program as cash flow hedges for accounting purposes as well as the increase in number of positions in the program.

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Interest Rate Risk

The table below provides information concerning Energy Future Holdings Corp.’s financial instruments as of December 31, 2006 and 2005 that are sensitive to changes in interest rates, which include debt obligations and interest rate swaps. Energy Future Holdings Corp. has entered into interest rate swaps under which it has agreed to exchange the difference between fixed-rate and variable-rate interest amounts calculated with reference to specified notional principal amounts at dates that generally coincide with interest payments. The weighted average interest rate presented is based on the rate in effect at the reporting date. Capital leases and the effects of unamortized premiums and discounts and fair value hedges are excluded from the table. See Note 15 to the 2006 year-end Financial Statements for a discussion of changes in debt obligations.

	Expected Maturity Date																		2006			2006		2005			2005
	2007			2008			2009			2010			2011			There- After			Total Carrying Amount			Total Fair Value		Total Carrying Amount			Total Fair Value
	(millions of dollars)
Equity-linked debt:
Fixed rate debt amount		—			—			—			—			—			—			—			—	$	179		$	289
Average interest rate		—			—			—			—			—			—			—			—		5.80	%		—
All other long-term debt: (including current maturities):
Fixed rate debt	$	331		$	576		$	1,129		$	135		$	143		$	8,172		$	10,486		$	10,669	$	11,493		$	11,735
Average interest rate		4.90	%		5.90	%		4.81	%		5.46	%		5.57	%		6.46	%		6.18	%		—		6.14	%		—
Variable rate debt amount	$	143			—			—			—			—		$	472		$	615		$	639	$	872		$	867
Average interest rate		4.11	%		—			—			—			—			4.32	%		4.27	%		—		4.32	%		—
Total Debt	$	474		$	576		$	1,129		$	135		$	143		$	8,644		$	11,101		$	11,308	$	12,544		$	12,891
Debt swapped to variable:
Amount	$	200		$	450		$	450			—			—		$	1,700		$	2,800				$	3,400
Average pay rate		6.66	%		8.12	%		6.16	%		—			—			6.88	%		6.95	%				6.48	%
Average receive rate		5.00	%		6.24	%		4.80	%		—			—			6.18	%		5.89	%				5.97	%
Debt swapped to fixed:
Amount		—			—			—			—			—		$	300		$	300					—
Average pay rate		—			—			—			—			—			5.18	%		5.18	%				—
Average receive rate		—			—			—			—			—			5.37	%		5.37	%				—

(a) Reflects the maturity date and not the remarketing date for certain debt that is subject to mandatory tender for remarketing prior to maturity. See Note 15 to the 2006 year-end Financial Statements for details concerning long-term debt subject to mandatory tender for remarketing.

Interest rate swaps (fixed to variable) related to $300 million and $1.8 billion principal amount of debt were dedesignated as fair value hedges in December 2006 and January 2007, respectively. Offsetting swap positions were entered into, and both the original swaps and offsetting positions are subsequently being marked-to-market in net income.

As of August 31, 2007, the potential reduction of annual pretax earnings due to a one-point increase in interest rates totaled approximately $20 million.

Credit Risk

Credit Risk—Credit risk relates to the risk of loss associated with nonperformance by counterparties. Energy Future Holdings Corp. and its subsidiaries maintain credit risk policies with regard to their counterparties to minimize overall credit risk. These policies require an evaluation of a potential counterparty’s financial

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condition, credit rating and other quantitative and qualitative credit criteria and specify authorized risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. Energy Future Holdings Corp. has standardized documented processes for monitoring and managing credit exposure of its businesses including methodologies to analyze counterparties’ financial strength, measurement of current and potential future credit exposures and standardized contract language that provides rights for netting and set-off. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to preset limits and analyzed to assess potential credit exposure. This evaluation results in establishing credit limits or collateral requirements prior to entering into an agreement with a counterparty that creates credit exposure. Additionally, Energy Future Holdings Corp. has established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Any prospective material adverse change in the payment history or financial condition of a counterparty or downgrade of its credit quality will result in the reassessment of the credit limit with that counterparty. This process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.

Credit Exposure—Energy Future Holdings Corp.’s gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions arising from hedging and trading activities totaled $2.0 billion at both June 30, 2007 and December 31, 2006.

Gross assets subject to credit risk as of June 30, 2007 and December 31, 2006 include $532 million and $595 million, respectively, in accounts receivable from the retail sale of electricity to residential and small business customers. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience and market or operational conditions.

Most of the remaining credit exposure is with large business retail customers and wholesale counterparties. These counterparties include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of June 30, 2007, the exposure to credit risk from these customers and counterparties totaled $1.3 billion taking into account standardized master netting contracts and agreements described above and $23 million in credit collateral (cash, letters of credit and other security interests) held by Energy Future Holdings Corp. subsidiaries. As of December 31, 2006, the exposure to credit risk from these customers and counterparties totaled $1.2 billion taking into account standardized master netting contracts and agreements described above and $56 million in credit collateral (cash, letters of credit and other security interests) held by Energy Future Holdings Corp. subsidiaries.

Of the $1.3 billion net exposure at June 30, 2007, 77% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and Energy Future Holdings Corp.’s internal credit evaluation process. Of the $1.2 billion net exposure at December 31, 2006, 88% is with investment grade customers and counterparties. Those customers and counterparties without an S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate an S&P equivalent rating. Energy Future Holdings Corp. routinely monitors and manages its credit exposure to these customers and counterparties on this basis.

In addition, Oncor Electric Delivery has exposure to credit risk totaling $233 million at June 30, 2007 and $174 million at December 31, 2006 arising from potential nonperformance by nonaffiliated REPs. This exposure consists almost entirely of noninvestment grade trade accounts receivable.

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The following tables present the distribution of credit exposure as of June 30, 2007 and December 31, 2006, for retail trade accounts receivable from large business customers, wholesale trade accounts receivable as well as net asset positions arising from hedging and trading activities, by investment grade and noninvestment grade, credit quality and maturity.

	June 30, 2007
	Exposure before Credit Collateral			Credit Collateral			Net Exposure			Net Exposure by Maturity
										2 years or less		Between 2-5 years		Greater than 5 years		Total
	(millions of dollars)
Investment grade	$	1,004		$	16		$	988		$	596	$	140	$	252	$	988
Noninvestment grade		301			7			294			168		72		54		294
Totals	$	1,305		$	23		$	1,282		$	764	$	212	$	306	$	1,282
Investment grade		77	%		70	%		77	%
Noninvestment grade		23	%		30	%		23	%

	December 31, 2006
	Exposure before Credit Collateral			Credit Collateral			Net Exposure			Net Exposure by Maturity
										2 years or less		Between 2-5 years		Greater than 5 years		Total
	(millions of dollars)
Investment grade	$	1,094		$	41		$	1,053		$	614	$	220	$	219	$	1,053
Noninvestment grade		164			15			149			111		13		25		149
Totals	$	1,258		$	56		$	1,202		$	725	$	233	$	244	$	1,202
Investment grade		87	%		73	%		88	%
Noninvestment grade		13	%		27	%		12	%

Approximately 60% of the net $1.3 billion credit exposure at June 30, 2007 has a maturity date of two years or less. Energy Future Holdings Corp. does not anticipate any material adverse effect on its financial position or results of operations due to nonperformance by any customer or counterparty.

Energy Future Holdings Corp.’s subsidiaries had credit exposure to two counterparties each having an exposure greater than 10% of the net $1.3 billion credit exposure at June 30, 2007. These two counterparties represented 16% and 13%, respectively, of the net exposure. Energy Future Holdings Corp. views exposure to these two counterparties to be within an acceptable level of risk tolerance as they are rated investment grade.

Energy Future Holdings Corp.’s subsidiaries are exposed to credit risk related to its long-term hedging program. Of the transactions in the program at June 30, 2007, over 98% of the volumes are with counterparties with an A credit rating or better, and 99% are at least investment grade.

Additionally, under the long-term hedging program, Energy Future Holdings Corp. has potential credit risk exposure concentration related to a limited number of counterparties. The hedge transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of significant declines in natural gas prices and a material downgrade in the credit rating of the counterparties. Energy Future Holdings Corp. views the potential concentration of risk with these counterparties to be within an acceptable risk tolerance due to the strong financial profile of the counterparties and their respective A or above credit rating.

Energy Future Holdings Corp. is also exposed to credit risk related to the Capgemini put option with a carrying value of $177 million. Subject to certain terms and conditions, Cap Gemini North America, Inc. and its

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parent, Cap Gemini S.A., have guaranteed the performance and payment obligations of Capgemini under the services agreements with TCEH and Oncor Electric Delivery, as well as the payment in connection with a put option. S&P currently maintains a BB+ rating with a positive outlook for Cap Gemini S.A.

Financial Condition—Post-Merger

Liquidity and Capital Resources

Following the consummation of the Transactions, we are highly leveraged. As of June 30, 2007, on a pro forma basis (excluding expected discount of $1.1 billion related to the fair valuing of existing debt due to purchase accounting and $1.25 billion related to the TCEH Letter of Credit Facility) after giving effect to the Transactions, we would have had $40.2 billion in aggregate indebtedness outstanding, with an additional approximately $5.9 billion of borrowing capacity available under the TCEH Senior Secured Facilities (excluding amounts available under the TCEH Commodity Collateral Posting Facility and outstanding letters of credit). Our liquidity requirements will be significant, primarily due to debt service requirements and financing costs incurred in connection with the TCEH Senior Secured Facilities, the EFH Senior Interim Facility and the TCEH Senior Interim Facility. On a pro forma basis, after giving effect to the Transactions, our interest expense for the twelve months ended June 30, 2007 would have been $3,574 million.

None of Oncor Electric Delivery Holdings or any of its subsidiaries, including Oncor Electric Delivery, will be a guarantor of, and no such entity’s assets will be pledged to secure, any of the indebtedness for borrowed money owed by Energy Future Holdings Corp. or any of Energy Future Holdings Corp.’s other subsidiaries; and none of Oncor Electric Delivery’s indebtedness for borrowed money will be guaranteed by, or secured by the assets of, Energy Future Holdings Corp. or any of Energy Future Holdings Corp.’s other subsidiaries. See “The Transactions—Ring-Fencing.”

Management expects our cash flows from operations, combined with availability under our new credit facilities, to provide sufficient liquidity to fund our current obligations, projected working capital requirements, restructuring obligations and capital spending for a period that includes the next twelve months. We expect to make approximately $2.1 billion million in capital expenditures including capitalized interest over the twelve months ending December 31, 2008.

Capital Expenditures

We expect to incur the following capital expenditures and distributions in 2007:

• $760 million for increased investment in Oncor Electric Delivery’s transmission and distribution infrastructure;

• $2.2 billion for investments in generation activities, including $1.4 billion for construction of one generation unit at Sandow and two generation units at Oak Grove; and

• $430 million related to the suspended development of eight coal-fueled generation units.

Indebtedness Incurred in Connection with the Merger

Credit Facilities

In connection with the Merger, Energy Future Holdings Corp. entered into the EFH Senior Interim Facility and TCEH entered into the TCEH Senior Secured Facilities and the TCEH Senior Interim Facility. In addition, Oncor Electric Delivery entered into the Oncor Electric Delivery Revolving Facility.

The TCEH Commodity Collateral Posting Facility is a senior secured revolving credit facility, the aggregate principal amount of which is determined by the out-of-the-money mark-to-market exposure of TCEH (and/or its

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subsidiaries) on a portfolio of certain natural gas commodity swap transactions under which TCEH (and/or its subsidiaries) is the “floating price” payor as such portfolio may be amended from time to time (the “Deemed Transactions”). The Deemed Transactions generally correspond to hedging transactions of TCEH (and/or its subsidiaries). The TCEH Commodity Collateral Posting Facility is intended to fund the cash posting requirements due to trading counterparties for a significant portion of TCEH’s long-term hedging program that is not otherwise secured by means of a first lien under the security arrangements entered into in connection with the TCEH Senior Secured Facilities. On a pro forma basis as of June 30, 2007 (based on the forward natural gas curve as of such date), approximately $687 million was outstanding under the TCEH Commodity Collateral Posting Facility. The actual drawn amount on October 10, 2007 (based on the forward natural gas curve as of such date) was approximately $378 million.

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Existing Senior Notes and Debentures

After consummation of the Transactions, we had approximately $9,652 million of aggregate principal amount of existing senior notes and debentures outstanding.

Debt Repayment

In connection with the Merger, we redeemed and repaid or expect to repay an aggregate of approximately $5.5 billion of our consolidated indebtedness (including the Specified Notes, but excluding indebtedness of Oncor Electric Delivery), including debt that became payable upon the consummation of the Merger.

Material Credit Rating Covenants

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of the downgrade of TCEH’s credit rating to below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. Based on requests to post collateral support from utilities that have been received by TCEH and its subsidiaries as of September 30, 2007, TCEH has posted collateral support to the applicable utilities in an aggregate amount equal to $25 million, with $16 million of this amount posted for the benefit of Oncor Electric Delivery.

The PUCT has rules in place to assure adequate credit worthiness of any REP. Under these rules, as a result of the downgrade of TCEH’s credit rating to below investment grade, TCEH has agreed to maintain at all times availability under its credit facilities an amount no less than the aggregate amount of customer deposits and any advanced payments received from customers. As of September 30, 2007, the amount of customer deposits received from customers held by TCEH’s REP subsidiaries totaled approximately $125 million.

ERCOT also has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, as a result of the downgrade of TCEH’s credit rating to below investment grade, TCEH posted additional collateral support of $34 million on March 7, 2007 and $16 million on August 31, 2007, which is subject to periodic adjustments.

Other arrangements of Energy Future Holdings Corp. and its subsidiaries, including certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on credit ratings.

Material Cross Default Provisions

Certain financing arrangements contain provisions that may result in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenants that may result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.

The TCEH Senior Secured Facilities, the EFH Senior Interim Facility and the TCEH Senior Interim Facility, all contain cross-default or cross-acceleration provisions.

Energy Future Holdings Corp. and its subsidiaries enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur

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if Energy Future Holdings Corp. or those subsidiaries were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The entities whose default would trigger cross default vary depending on the contract.

Each of Luminant Construction’s commodity hedging agreements that will be pari passu with the TCEH Senior Secured Facilities contains a cross default provision. In the event of a default by Luminant Construction or its subsidiaries relating to certain obligations of Luminant Construction in an amount equal to or greater than $250 million, the applicable hedge counterparties may terminate the applicable transactions covered by the applicable hedging agreements and require all outstanding obligations thereunder to be settled.

Other arrangements, including leases, have cross default provisions, the triggering of which would not result in a significant effect on liquidity.

Also see Note 10 to the June 30, 2007 Financial Statements and Note 16 to the 2006 year-end Financial Statements for details of guarantees.

Contractual Obligations and Commitments

Pro Forma Long-term Contractual Obligations and Commitments—The following table summarizes our contractual cash obligations as of December 31, 2006 giving pro forma effect to the Transactions.

Contractual Cash Obligations	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years		Total
	(millions of dollars)
Long-term debt—principal	$	639	$	826	$	691	$	39,157	$	41,313
Long-term debt—interest(a)		3,159		6,109		5,879		12,256		27,403
Operating and capital leases(b)		69		126		111		332		638
Contracts related to generation development program(c)		1,401		796		—		—		2,197
Obligations under commodity purchase and services agreements(d)		2,075		2,432		851		1,237		6,595
Total contractual cash obligations(e)	$	7,343	$	10,289	$	7,532	$	52,982	$	78,146

(a) Variable interest payments are calculated based on interest rates in effect at December 31, 2006.

(b) Includes short-term noncancellable leases.

(c) Amounts represent scheduled payments under the contracts for the three proposed new generation units. See Note 16 to the 2006 Financial Statements.

(d) Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments. Amounts presented for variable priced contracts assumed the year-end 2006 price remained in effect for all periods except where contractual price adjustment or index-based prices were specified.

(e) Table does not include estimated 2007 funding of the pension and other postretirement benefits plans totaling approximately $153 million.

The following contractual obligations were excluded from the table above:

• contracts between affiliated entities and intercompany debt;

• individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one counterparty that are more than $1 million on an aggregated basis have been included);

• contracts that are cancelable without payment of a substantial cancellation penalty;

• income tax payments associated with uncertain tax positions that cannot be reasonably estimated;

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• management fees that may be payable to affiliates of the Sponsors;

• rate settlement agreement with the Cities, which is discussed elsewhere in this Current Report on Form 8-K; and

• employment contracts with management.

Interest Rate Risk—Pro Forma

The table below provides information on a pro forma basis after giving effect to the Transactions concerning Energy Future Holdings Corp.’s financial instruments as of December 31, 2006 that are sensitive to changes in interest rates. The weighted average interest rate presented is based on the rate in effect at the reporting date. Capital leases and the effects of unamortized premiums and discounts are excluded from the table. See Note 15 to the 2006 year-end Financial Statements for a discussion of changes in debt obligations.

	Expected Maturity Date																		2006 Total Carrying Amount			2006 Total Fair Value
	2007			2008			2009			2010			2011			There- After
Equity-linked debt:
Fixed rate debt amount	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
Average interest rate		—			—			—			—			—			—			—			—
All other long-term debt: (including current maturities)
Fixed rate debt amount(a)	$	331		$	326		$	129		$	135		$	143		$	19,109		$	20,173		$	20,318
Average interest rate		4.90	%		5.72	%		4.86	%		5.46	%		5.57	%		8.62	%		8.44	%		—
Variable rate debt amount	$	308		$	165		$	206		$	206		$	206		$	20,049		$	21,140		$	21,107
Average interest rate		6.44	%		8.25	%		8.54	%		8.66	%		8.80	%		8.82	%		8.78	%		—
Total Debt	$	639		$	491		$	335		$	341		$	349		$	39,158		$	41,313		$	41,425
Debt swapped to variable:
Amount		—			—			—			—			—			—			—
Average pay rate		—			—			—			—			—			—			—
Average receive rate		—			—			—			—			—			—			—
Debt swapped to fixed:
Amount		—			—			—			—			—			—			—
Average pay rate		—			—			—			—			—			—			—
Average receive rate		—			—			—			—			—			—			—

(a) Reflects the maturity date and not the remarketing date for certain debt that is subject to mandatory tender for remarketing prior to maturity. See Note 15 to the 2006 year-end Financial Statements for details concerning long-term debt subject to mandatory tender for remarketing.

Hedging

We expect to continue to pursue additional hedging arrangements to continually manage our exposure to changes in natural gas prices. These arrangements typically take the form of forward natural gas sales in which TCEH commits to selling certain volumes of natural gas in the future at fixed prices; in effect, these arrangements reduce the exposure of our baseload generation facilities to changes in future power prices that occur as a result of changes in natural gas prices (one of the primary drivers of power prices in the ERCOT markets). Under the terms of our indebtedness after the consummation of the Merger, TCEH will have the ability to secure future hedges on a first-lien basis, pari passu with the TCEH Senior Secured Facilities (as opposed to securing any such hedges with cash collateral or letters of credit).

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BUSINESS

Our Company

We are a Dallas-based energy company that manages a portfolio of competitive and regulated energy businesses in Texas. We are a holding company conducting our operations principally through our subsidiaries, TCEH, Oncor Electric Delivery and their respective subsidiaries. TCEH is a holding company for the Luminant and TXU Energy businesses, which are engaged in competitive electricity market activities largely in Texas. The Luminant businesses include Luminant Power, Luminant Energy and Luminant Construction. Luminant Power, Luminant Energy, Luminant Construction and TXU Energy conduct their operations through a number of separate legal entities that, in accordance with regulatory requirements, operate independently within the competitive Texas power market.

As of June 30, 2007, Luminant Power had 18,365 MW of generation capacity in Texas (which includes 585 MW representing nine combustion turbine units currently operated for an unaffiliated party’s benefit). This amount includes 8,137 MW of low-cost baseload solid fuel generation capacity represented by 2,300 MW of nuclear generation capacity and 5,837 MW of lignite/coal-fueled generation capacity. Luminant Energy supports Luminant Power and TXU Energy by optimizing the performance of the generation assets and sourcing the electricity requirements for TXU Energy’s customers as well as providing related services to other market participants. Luminant Energy is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the United States. Luminant Construction is currently constructing three new lignite coal-fueled generation facilities in Texas with expected generation capacity totaling approximately 2,200 MW. The three facilities are permitted and are expected to come on-line in the 2009-2010 timeframe. See “—Competitive Electric Segment—Luminant Construction” for more information.

TXU Energy provides competitive electricity and related services to more than 2.1 million electricity customers in Texas. As of June 30, 2007, TXU Energy’s estimated share of the total ERCOT market retail residential and small business electric customers was approximately 35% and 25%, respectively.

Oncor Electric Delivery is an electricity distribution and transmission business that provides electricity delivery services to retail electric providers, including TXU Energy, that sell electricity to consumers. Oncor Electric Delivery operates the largest distribution and transmission system in Texas, providing power to more than three million homes and businesses and operating more than 115,000 miles of transmission and distribution lines in Texas. A significant portion of Oncor Electric Delivery’s revenues represent fees for delivery services provided to TCEH. Distribution revenues from TCEH represented 47% of Oncor Electric Delivery’s distribution revenues and 41% of Oncor Electric Delivery’s total revenues for the six months ended June 30, 2007 and 52% of Oncor Electric Delivery’s distribution revenues and 46% of Oncor Electric Delivery’s total revenues for the year ended December 31, 2006.

Upon consummation of the Merger, we and Oncor Electric Delivery implemented certain structural and operational measures based on principles articulated by rating agencies and commitments made by Texas Holdings and Oncor Electric Delivery to the PUCT and the FERC that are intended to further separate Oncor Electric Delivery from Texas Holdings and its other subsidiaries in order to mitigate Oncor Electric Delivery’s credit exposure to those entities and to reduce the risk that the assets and liabilities of Oncor Electric Delivery would be substantively consolidated with the assets and liabilities of Texas Holdings or any of its other subsidiaries in the event of a bankruptcy of one or more of those entities. See “The Transactions—Ring-Fencing” for a description of the material terms of the ring-fencing measures.

For the twelve months ended June 30, 2007, on a pro forma basis, Energy Future Holdings Corp. had Adjusted EBITDA of $5,235 million on a consolidated basis, 24% of which was attributable to Oncor Electric Delivery. See “—Summary Historical and Unaudited Pro Forma Consolidated Financial and Other Data of Energy Future Holdings Corp. and its Subsidiaries” for a definition of Adjusted EBITDA and a reconciliation of net income to Adjusted EBITDA. See the subsections titled “Regulated Delivery Segment” under “Energy

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Future Holdings Corp. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements of Oncor Electric Delivery included elsewhere in this Current Report on Form 8-K for information regarding the results of operations of Oncor Electric Delivery.

Our Market

We operate primarily within the ERCOT market, which represents approximately 85% of electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the system operation of the interconnected transmission system for those systems. ERCOT’s membership consists of 236 members, including electric cooperatives, municipal power agencies, investor-owned independent generators, independent power marketers, transmission service providers and distribution services providers, independent REPs and consumers.

ERCOT represents approximately 75% of the geographical area of Texas, but excludes El Paso, a large part of the Texas Panhandle and two small areas in the eastern part of the state. From 1994 through 2005, peak hourly demand in the ERCOT market grew at a compound annual rate of 2.8%, compared to a compound annual rate of growth of 2.3% for the entire United States over the same period. For 2006, hourly demand ranged from a low of 21,309 MW to a high of 62,339 MW. ERCOT has limited interconnections to other markets outside of ERCOT in the United States, which currently limits potential imports into ERCOT and is currently limited to 1,106 MW of generation capacity (or approximately 2% of peak demand in Texas). In addition, wholesale transactions within the ERCOT market are not subject to regulation by the FERC.

The ERCOT market has experienced significant construction of new generation plants in recent years, with over 29,000 MW of mostly natural gas-fueled combined cycle generation capacity added to the market since 1996. As of May 31, 2007, aggregate net generation capacity of approximately 76,801 MW existed in the ERCOT market, of which 72% was natural gas-fueled. Approximately 21,444 MW, or 27.9%, was lower marginal cost generation capacity such as coal, lignite and nuclear plants. As of May 31, 2007, Luminant Power’s lignite and nuclear baseload plants represented 8,137 MW, or 37.9%, of the total lower marginal cost generation capacity in the ERCOT market. ERCOT has established a target reserve margin level of approximately 12.5%; and the reserve margin at May 17, 2007, was 14.6%, forecast to drop to 12.6% by 2008 and 10.1% by 2009.

Natural gas-fueled generation is the predominant supply resource in the ERCOT market in terms of both the installed generation capacity and generation produced, accounting for approximately 72% of the installed generation capacity and 46% of the electricity produced in the ERCOT market. In the ERCOT market, buyers and sellers enter into bilateral wholesale capacity, power and ancillary services contracts or may participate in the centralized ancillary services market, including balancing energy, which ERCOT administers. An October 1, 2005 report titled “Report on Existing and Potential Electric System Constraints and Needs” found that natural gas-fueled power plants set the market price of power more than 90% of the time in the ERCOT market. As a result, natural gas-fueled plant operators are the marginal suppliers in ERCOT, and wholesale electricity prices are highly correlated to natural gas prices.

The ERCOT market is currently divided into four regions or congestion zones, namely: North, Houston, South and West, which reflect transmission constraints that are commercially significant and which have limits as to the amount of power that can flow across zones. Luminant Power’s baseload generation facilities are located primarily in the North region.

The ERCOT market operates under the reliability standards set by the NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’s main interconnected power transmission grid. ERCOT is responsible for facilitating reliable operations of the bulk electric power supply system in the ERCOT market. The ERCOT independent system operator (“ERCOT ISO”) is responsible for maintaining reliable operations of the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among

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the generation resources and wholesale buyers and sellers. Unlike certain other regional power markets, the ERCOT market is not a centrally dispatched power pool, and the ERCOT ISO does not procure energy on behalf of its members. Members who sell and purchase power are responsible for contracting sales and purchases of power bilaterally. The ERCOT ISO also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.

Our electric distribution and transmission business, Oncor Electric Delivery, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. The transmission business has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated area. We participate with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to meet reliability needs, increase bulk power transfer capability to remove existing constraints and interconnect generation on the ERCOT transmission grid.

We believe that the ERCOT market presents an attractive competitive electric service market due to the following factors:

• market rules support fair and robust competition, while providing opportunities to optimize the generation fleet operations and purchased power requirements;

• peak demand is expected to grow at an average rate of over 2.1% per year over the period 2007 to 2017;

• it is a sizeable market with over 62 GW of peak demand and approximately 34 GW of average demand; and

• as projected by ERCOT, in the absence of additional generation capacity, annual reserve margins are expected to fall below ERCOT’s targeted reserve margin of 12.5% as early as 2009, thus providing opportunities for generation owners and developers. Reserve margin is defined as the percentage by which available capacity is expected to exceed forecasted peak demand.

Our Strengths

• Scale and diversity of business.We believe we have three strong, large-scale electricity businesses in an attractive electric market. Luminant has a large and diversified competitive power generation portfolio with approximately 18,365 MW of generation capacity as of June 30, 2007 (which includes 585 MW representing nine combustion turbine units currently operated for an unaffiliated party’s benefit). Its diversified portfolio consists of approximately 8,137 MW of low-cost solid fuel baseload generation capacity (approximately 72% lignite/coal and 28% nuclear) in ERCOT, a market in which power prices are predominantly set by natural gas-fueled generation that is more costly than the solid fuel that powers Luminant’s baseload generation plants at current commodity levels. In addition, as of June 30, 2007, Luminant owned or operated 10,228 MW of intermediate and peaking facilities, which provide the ability to dispatch assets in periods of high demand and prices. Luminant’s lignite/coal-fueled plants are near lignite reserves that are controlled by Luminant and supply approximately 67% of the fuel used to operate these plants, which reduces Luminant’s reliance on third-party coal suppliers and railroad use. Luminant controls approximately 1.0 billion tons, or over 21 years of fuel (assuming current mine production levels), of proven lignite reserves and operates the nation’s 13th largest mining company. Luminant is also developing and constructing three new lignite coal-fueled generation facilities in Texas with expected generation capacity totaling approximately 2,200 MW of additional installed low-cost baseload capacity. We expect two of these units, representing approximately 1,400 MW, to be operational in 2009 and the remaining unit, representing approximately 800 MW, to be operational in 2010.

TXU Energy is a large scale competitive retailer that provides competitive electricity and related services to more than 2.1 million electricity customers in Texas. As of June 30, 2007, TXU Energy

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held approximately 62% of the retail residential market share in its historical market area located in the north-central, eastern and western parts of Texas, including the Dallas-Fort Worth area. As of June 30, 2007, TXU Energy’s estimated share of the total ERCOT market retail residential and small business electric customers was approximately 35% and 25%, respectively.

Oncor Electric Delivery operates the largest distribution and transmission system in Texas, providing power to more than three million homes and businesses and operating more than 115,000 miles of transmission and distribution lines in Texas. We believe that significant opportunities for investments in transmission and distribution exist in ERCOT, including maintenance, repair and upgrades of the transmission and distribution grid and connecting planned wind generation and other generation projects in ERCOT.

• Low-cost asset base. We are the largest provider of baseload generation power in Texas with approximately 8,137 MW of existing low-cost solid fuel baseload capacity (lignite/coal and nuclear) in a predominantly gas-on-the-margin market. Our baseload generation facilities operate at high utilization levels, incur comparatively low operations and maintenance costs and benefit from a number of long-term fuel contracts on attractive terms.

Our low-cost position is supported by a number of factors, including our control of an estimated 858 million tons of dedicated proven lignite reserves, and in excess of 119 million tons of undedicated proven lignite reserves. Importantly, these lignite reserves, which are near a number of the lignite coal-fueled plants that we operate, provide a low-cost source of fuel for certain of our plants, and reduce our exposure to rising coal and rail contract prices.

• Favorable market dynamics. Our subsidiaries operate primarily in ERCOT, which represents approximately 85% of the electricity consumed in Texas. We believe that the strong regional economic growth in Texas continues to support demand growth for electricity in ERCOT. According to ERCOT, peak demand in ERCOT is expected to grow at an average rate of over 2.1% per year over the period from 2007 to 2017. ERCOT expects reserve margins to continue to decline, which presents additional investment opportunities, while also positively impacting the value of our existing plants. Power prices are generally driven by natural gas prices in ERCOT, where natural gas-fueled plants set the market price approximately 90% of the time. Texas has one of the highest retail energy consumption profiles in the country with approximately 14 MWh per year of consumption per household. ERCOT has experienced over 2.1% annual retail growth over the period from 2002 to 2006, making it one of the fastest growing NERC regions.

Transmission and distribution businesses in ERCOT benefit from favorable regulatory capital recovery mechanisms known as “capital trackers” that we believe enable adequate and timely recovery of transmission investments, advanced meter reading investments and certain other infrastructure investments.

• Strong operating performance.Luminant Power is an industry-leading operator of baseload solid fuel plants. Based on our benchmark analysis, we believe that compared with the U.S. merchant coal plant fleet, Luminant Power’s lignite/coal plants achieved top decile capacity factors and top quartile costs per MWh in 2005 and 2006. Similarly, we believe that our nuclear units achieved top decile capacity factors and top quartile costs per MWh in 2006. Luminant Power’s lignite/coal-fueled plants achieved a capacity factor of 89.1% for 2006 and Luminant Power’s nuclear plants achieved a capacity factor of 98.8% for 2006. Luminant Power’s ongoing operating system initiatives are focused on achieving industry-leading capacity factors while continuing to manage costs. The capacity factor of a power plant is generally the ratio of the actual output of the power plant over a period of time as compared to its potential output if the plant operated at full capacity during such period.

TXU Energy is committed to providing its customers with industry-leading customer service and creating an innovative set of new products and services to meet customer needs. For the twelve months ended June 30, 2007, call answer times averaged under 15 seconds, which dropped from an average of

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over 100 seconds for the same period in 2004. Customer call satisfaction scores in North Texas improved 16 percent in the twelve months ended June 30, 2007, as compared to the twelve months ended June 30, 2006. TXU Energy continues to offer the broadest set of customer products of any retailer in the ERCOT market.

Oncor Electric Delivery continues to progress toward its goal of improving its top-quartile reliability performance, while maintaining top-quartile cost performance. In 2006, Oncor Electric Delivery invested approximately $840 million in its network to construct, rebuild and upgrade transmission lines, to extend the distribution infrastructure, and to pursue certain initiatives in infrastructure maintenance, information technology systems and advanced meter reading. Oncor Electric Delivery continues to transform its network into the nation’s first broadband-enabled smart grid, with approximately 285,000 advanced meters installed at the end of 2006, and it plans to install up to 600,000 advanced meters by the end of 2007. Oncor Electric Delivery also achieved market-leading electric delivery performance in five out of seven key PUCT market metrics in 2006. These metrics measure the success of transmission and distribution companies in facilitating customer transactions in the competitive Texas electricity market.

• Attractive opportunities for capital investment.We have a number of attractive opportunities for capital investment. Luminant Construction is building three, new low-cost lignite coal-fueled generation units in the state of Texas with total estimated capacity of approximately 2,200 MW. The three units consist of one new generation unit at a site owned by Alcoa Inc. that is adjacent to an existing TCEH lignite coal-fueled generation plant site (Sandow) and two units at a TCEH site that was slated for construction of a generation plant a number of years ago (Oak Grove). Aggregate capital expenditures to develop these three units are expected to total approximately $3.25 billion, including all construction, site preparation and mining development costs (not including the purchase of the Three Oaks mine assets).

We believe that these construction projects represent attractive investment opportunities and benefit from a number of strategic advantages, including:

• our incumbent position in the ERCOT market;

• our control of attractive brownfield development sites with access to low-cost lignite fuel;

• our first mover advantage in seeking, siting and permitting approval; and

• our low-cost construction contracts with leading EPC firms.

• Attractive cash flowgeneration.For the twelve months ended June 30, 2007, on a pro forma basis, we generated Adjusted EBITDA of $5,235 million. Specific characteristics of our businesses that support our attractive cash flow generation are outlined in this Current Report on Form 8-K. Our anticipated operating margins, low maintenance capital expenditures and modest working capital requirements are expected to be key drivers of our strong cash flow generation.

• Ability to hedge future cash flows through long-term hedging program.We believe that the strong historical correlation between natural gas prices and power prices in the ERCOT market combined with significant liquidity in certain natural gas markets currently provides an opportunity for management of our exposure to natural gas prices. As a result, we expect to hedge up to 80% of the equivalent natural gas price exposure of our expected baseload generation output on a rolling five-year basis. As of October 10, 2007, approximately 2.6 billion MMBtu of natural gas (equivalent to the natural gas exposure of over 300,000 GWh at an assumed 8.5 MMBtu/MWh market heat rate) have been effectively sold forward by our subsidiaries over the period from 2008 to 2013 at average annual prices ranging from $7.25 per MMBtu to $8.15 per MMBtu. For the period from 2008 to 2012, and taking into consideration the estimated portfolio impacts of our retail electricity business, these transactions result in us having effectively hedged approximately 80% of our expected baseload generation natural gas price exposure for such period (on an average basis for such period). Demonstrating the ability to implement a long-term hedging program on a rolling basis, we have also hedged approximately 60% of our expected baseload generation natural gas price exposure in 2013 at prices above $7.25 per MMBtu.

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We believe this hedging program provides us with visibility and stability of future cash flows.

• Strong leadership. Luminant, TXU Energy and Oncor Electric Delivery have separate leadership teams consistent with the separation of our legacy businesses into three distinct operating entities. Each company has its own chief executive officer who, together with the respective management teams, will focus on optimizing operations and maximizing performance for that specific business unit, independent of the other business units. The management teams for each business are comprised of highly experienced professionals. In addition, four prominent Texans, Donald L. Evans, former U.S. Secretary of Commerce; James R. Huffines, Chairman of the University of Texas Board of Regents; Lyndon L. Olson Jr., former Texas State Representative and former U.S. Ambassador to Sweden; and Kneeland Youngblood, a former director of the U.S. Enrichment Corporation, have joined our Board of Directors. William Reilly, Chairman Emeritus of the World Wildlife Fund and former EPA Administrator, has also joined our Board of Directors and will lead the adoption of corporate governance policies that tie our operations and goals to environmental stewardship. Finally, former U.S. Secretary of State James A. Baker III serves as Advisory Chairman to the General Partner.

Our Strategies

Each of our businesses focuses its operations on key drivers for that business, as described below:

• Luminant focuses on optimizing its existing generation fleet to provide safe, reliable and cost-competitive power, as well as developing and constructing additional power generation capacity to meet the growing demand for power in Texas;

• TXU Energy focuses on providing high quality customer service, including continually improving customer service and developing innovative energy products to meet customers’ needs; and

• Oncor Electric Delivery focuses on achieving a high level of reliability, minimizing service interruption, maintaining safe operations, and investing to improve its transmission and distribution infrastructure.

Other elements of our strategy include:

• Increase value from our existing businesses. Our strategy focuses on striving for consistent top decile performance across our operations in terms of reliability, cost and customer service. We will continue to focus on upgrading four critical skill sets: operational excellence across each business; market leadership; a systematic risk/return mindset applied to all key decisions; and rigorous performance management targeting industry-leading performance standards for productivity, reliability and customer service. An example of how we implement these principles is a program called the “Luminant Operating System,” which is a program to drive ongoing productivity improvements in Luminant Power’s businesses through application of lean operating techniques and deployment of a high-performance industrial culture.

• Pursue growth opportunities across our business lines. We believe building upon and leveraging our scale advantages enables us to sustainably create value by eliminating duplicative costs, efficiently managing supply costs, and building and standardizing distinctive process expertise. Scale also allows us to take part in large capital investments, such as new generation projects and investments in our transmission and distribution system, with a smaller fraction of overall capital at risk and with an enhanced ability to streamline costs. The growth initiatives for each business include:

• Luminant: Construction of three new lignite coal-fueled generation facilities at existing sites with onsite lignite fuel supplies, as well as the development of wind generation projects in the near to

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medium term. Pursuit of new generation opportunities to meet ERCOT’s growing generation needs over the longer term from a diverse range of alternatives such as nuclear, renewables and advanced coal technologies, such as Integrated Gasification Combined Cycle.

• TXU Energy: Retain existing customers and increase the number of customers served both in TXU Energy’s historic territory, as well as in other Texas markets such as Houston, through innovative products and superior customer service.

• Oncor Electric Delivery: Investment in automatic meter reading as well as the construction of new transmission and distribution facilities to meet the needs of the growing Texas market.

• Reduce the volatility of our cash flows through our established risk management strategy.A key component of our risk management strategy is our plan to hedge up to 80% of the natural gas exposure of Luminant Power’s baseload generation output on a rolling five-year basis. The strong historical correlation between natural gas prices and power prices in ERCOT combined with the significant liquidity in certain natural gas markets currently provides an opportunity for management of our exposure to natural gas prices. TCEH has approximately $5.9 billion of available revolving credit and letter of credit borrowing capacity (excluding amounts available under the TCEH Commodity Collateral Posting Facility and outstanding letters of credit) which we believe will provide significant liquidity for its operations, including for TCEH’s long-term hedging strategies, particularly regarding its commodity and market heat rate exposures. In addition, the TCEH Commodity Collateral Posting Facility will support the margin requirements for a significant portion of the natural gas swaps that are a part of the long-term hedging program not otherwise secured by a first lien on TCEH’s assets. In addition, certain existing and future hedging transactions are secured with a first lien security interest in TCEH’s assets, which will reduce the liquidity requirements of entering into commodity hedge transactions because no cash or letter of credit collateral will be required for these transactions. As of the consummation of the Merger, approximately 90% of Luminant’s natural gas hedging transactions were secured by this first lien security interest in TCEH’s assets (including transactions covered by the TCEH Commodity Collateral Posting Facility described under “The Transactions—Debt Financing”).

• Environmental focus.  We are committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce our impact on the environment. We will put in place a Sustainable Energy Advisory Board that will focus on assisting us in pursuing technology development opportunities that utilize the United States’ vast energy resources with technologies designed to reduce our impact on the environment while balancing the need to address the energy requirements of Texas. Our Sustainable Energy Advisory Board will be comprised of individuals who represent the following interests, among others: the environment, customers, Texas economic development and ERCOT reliability standards. In addition, we are focused on and are pursuing opportunities to reduce emissions from our existing and planned new lignite/coal-fueled generation units in ERCOT. As such and in connection with our plans to build three new lignite coal-fueled generation units, we have committed to reduce emissions of mercury, nitrogen oxide and sulfur dioxide at our existing units, so that the total of those emissions from both existing and new lignite coal-fueled units is 20% below 2005 levels. We expect to make these reductions through a combination of investment in new emission control equipment and possible fuel switching. We also expect such investments to provide economic benefits to us by reducing future costs associated with complying with environmental emissions standards.

Our Operating Segments

Energy Future Holdings Corp. has aligned and reports its business activities as two operating segments: Competitive Electric (primarily represented by TCEH) and Regulated Delivery (primarily represented by Oncor Electric Delivery).

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Competitive Electric Segment

The Competitive Electric segment is managed as an integrated business; however, for purposes of operational accountability and performance management, the segment has been divided into Luminant Power, Luminant Energy, Luminant Construction and TXU Energy.

Luminant Power

Luminant Power’s electricity generation fleet consists of 19 plants in Texas with total generating capacity as of June 30, 2007 as shown in the table below:

	Capacity (MW)	Number of Plants	Number of Units(a)
Fuel Type
Nuclear	2,300	1	2
Lignite/coal	5,837	4	9
Natural gas(b)(c)	10,228	14	45
Total	18,365	19	56

(a) Leased units consist of six natural gas-fueled units totaling 390 MW of capacity. All other units are owned.

(b) Includes 1,329 MW representing five units mothballed and not currently available for dispatch.

(c) Includes 585 MW representing nine combustion turbine units currently operated for an unaffiliated third party’s benefit.

The generation plants are located primarily on land owned in fee simple. Nuclear and lignite/coal-fueled (baseload) plants are generally scheduled to run at capacity except for periods of scheduled maintenance activities or, in the case of lignite/coal units, backdown due to low periods of demand. The natural gas-fueled generation units supplement the baseload generation capacity in meeting variable consumption as production from these units can more readily be ramped up or down as demand warrants.

Nuclear Generation Assets

Luminant Power operates two nuclear generation units at the Comanche Peak plant, each of which is designed for a capacity of 1,150 MW. Comanche Peak’s Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity to meet the load requirements in ERCOT. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the refueling cycle results in the refueling of both units during the same year, with the next scheduled to occur in 2008. While one unit is undergoing a refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance, modification and testing activities are completed that cannot be accomplished when the unit is in operation. Over the last 3 years, the refueling outage period per unit has ranged from a high of 38 days in 2004 to a low of 18 days in 2006. The Comanche Peak plant operated at a capacity factor of 98.8% in 2006, which represents top decile performance of US nuclear generation facilities.

Luminant Power has contracts in place for nuclear fuel conversion services through 2008. In addition, Luminant Power has contracts for the acquisition of uranium through 2009 and for nuclear fuel enrichment services through 2008, as well as for nuclear fuel fabrication services through 2018.

Contracts for the acquisition of raw uranium and nuclear fuel conversion services through 2012 and 2009, respectively, are being negotiated. Additional contracts to ensure a portion of nuclear fuel enrichment services through 2020 are being negotiated. Luminant Power does not anticipate any issues with finalizing these contracts and does not anticipate any significant difficulties in acquiring raw uranium and contracting for associated services in the foreseeable future.

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Luminant Power’s on-site used nuclear fuel storage capability is sufficient for five to ten years. The nuclear industry is continuing to review ways to enhance security of used-fuel storage with the NRC to fully utilize physical storage capacity.

The Comanche Peak nuclear generation units have an estimated useful life of 60 years from the date of commercial operation. Therefore, assuming that Luminant Power receives the requisite license extensions, plant decommissioning activities would be scheduled to begin in 2050 for Comanche Peak Unit 1 and 2053 for Unit 2 and common facilities. Decommissioning costs are fully recoverable from Oncor Electric Delivery’s customers through an ongoing delivery surcharge.

Lignite/Coal-Fueled Generation Assets

Luminant Power’s lignite/coal-fueled generation fleet has a nameplate capacity of 5,837 MW and consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units) and Sandow (1 unit) plants. These plants are generally operated at full capacity to meet the load requirements in ERCOT. Maintenance outages are scheduled during off-peak demand periods. Over the last three years, the total annual scheduled and unscheduled outages per unit averaged 33 days. Luminant Power’s lignite/coal-fueled generation fleet operated at a capacity factor of 89.1% in 2006, which represents top decile performance of U.S. coal-fueled generation facilities.

Approximately 67% of the fuel used at Luminant Power’s lignite/coal-fueled generation plants in 2006 was supplied from owned in fee or leased proven surface-minable lignite reserves dedicated to the Big Brown, Monticello and Martin Lake plants, which were constructed adjacent to the reserves. TCEH, through its subsidiaries, owns in fee or has under lease an estimated 858 million tons of proven reserves dedicated to its generation plants, and also owns in fee or has under lease in excess of 119 million tons of proven reserves not currently dedicated to specific generation plants. In 2006, over 22 million tons of lignite were recovered to fuel Luminant Power’s plants. TCEH utilizes owned and/or leased equipment to remove the overburden and recover the lignite.

Lignite mining operations include extensive reclamation activities that return the land to productive uses such as wildlife habitats, commercial timberland and pasture land. In 2006 alone, regulatory authorities approved Luminant Power’s release from further reclamation obligation approximately 8,000 acres of reclaimed land; Luminant Power planted more than 1.2 million trees as part of this reclamation.

Luminant Power supplements its lignite fuel at Big Brown, Monticello and Martin Lake with western coal from the Powder River Basin (PRB) in Wyoming. The coal is purchased from multiple suppliers under contracts of various lengths and is transported from the Powder River Basin to Luminant Power’s generating plants by railcar. Based on its current usage, Luminant Power believes that it has sufficient lignite reserves for the foreseeable future and has contracted 72% of its western coal resources and 100% of the related transportation through 2009.

Natural Gas-Fueled Generation Assets

Luminant Power also operates a fleet of natural gas-fueled generation units, which includes 45 units with a total 10,228 MW of currently available capacity. A significant number of the natural gas-fueled units have the ability to switch between natural gas and fuel oil. The gas units predominantly serve as peaking units that can be more readily ramped up or down as demand warrants.

Luminant Energy

Luminant Energy plays a pivotal role in supporting Luminant Power and TXU Energy by optimizing the performance of the generation assets and sourcing the electricity requirements for TXU Energy’s customers. Luminant Energy manages commodity price exposure across the complementary generation and retail businesses

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on a portfolio basis. Under this approach, Luminant Energy manages the risks of imbalances between generation supply and sales load, which primarily represent exposures to natural gas price movements and market heat rate changes (variations in the relationships between natural gas prices and wholesale electricity prices), through wholesale markets activities that include physical purchases and sales and transacting in financial instruments.

Luminant Energy manages the commodity exposure of the generation and retail portfolio through asset management and hedging activities. Luminant Energy provides TXU Energy with the electricity and related services to meet retail customer demand and the operating requirements of ERCOT. Luminant Energy also supports Luminant Power in selling forward generation and seeking to maximize the economic value of the fleet. In consideration of operational production and customer consumption levels that can be highly variable as well as opportunities for long-term purchases and sales with large wholesale electricity market participants, Luminant Energy buys and sells electricity in the spot and short-term market and executes longer-term forward electricity purchase and sales agreements.

In its hedging activities, Luminant Energy enters into contracts for the physical delivery of electricity and natural gas, exchange traded and “over-the-counter” financial contracts and bilateral contracts with producers, generators and end-use customers. In October 2005, Energy Future Holdings Corp. commenced a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. As of October 10, 2007, 2.6 billion MMBtu of natural gas (equivalent to the natural gas exposure of over 300,000 GWh at an assumed 8.5 MMBtu/MWh market heat rate) have effectively been sold forward by our subsidiaries over the period from 2008 to 2013, principally utilizing natural gas-related financial instruments.

Luminant Energy also dispatches the gas-fueled generation fleet owned and operated by Luminant Power. Luminant Energy’s dispatching activities are performed through a centrally managed real-time operational staff that synthesizes operational activities across the fleet and interfaces with various wholesale market channels. Luminant Energy coordinates the overall commercial strategy for these plants working closely with Luminant Power. In addition, Luminant Energy manages the fuel procurement requirements for the natural gas-fueled generation plants.

Luminant Energy engages in commercial operations such as physical purchases, storage and sales of natural gas, electricity and natural gas trading and third-party asset management. Luminant Energy’s natural gas operations include well-head production contracts, transportation agreements, storage leases and retail sales. Luminant Energy currently manages approximately 18 billion cubic feet of natural gas storage capacity and has a presence outside of Texas in both electricity and natural gas commodity trading.

Luminant Energy manages exposure to wholesale commodity and credit related risk within established transactional risk management policies and limits. Luminant Energy targets best practices in risk management and risk control by employing proven principles used by financial institutions. These controls have been structured so that they are practical in application and consistent with stated business objectives. Risk management processes include capturing transactions, performing and validating valuations and reporting exposures on a daily basis using commodity information systems designed to support a large transactional portfolio. A risk management forum meets regularly to ensure that business practices comply with approved transactional limits, commodities, instruments, exchanges and markets. Transactional risks are monitored and limits are enforced to comply with the established risk policy. Luminant Energy has a strict disciplinary program to address any violations of the risk management policies and periodically reviews these policies to ensure they are responsive to changing market and business conditions.

Luminant Energy is one of the largest purchasers of wind-generated electricity in Texas and the fifth largest in the United States.

Luminant Construction

Luminant Construction is developing three new lignite coal-fueled units in the state of Texas with total estimated capacity of approximately 2,200 MW. The three proposed units consist of one new generation unit at

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an existing Luminant Power lignite coal-fueled generation plant site recently acquired from Alcoa Inc. (Sandow) and two units at a site (Oak Grove) owned by Luminant Power that was originally slated for the construction of a generation plant a number of years ago. Aggregate capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs.

The development program includes up to $450 million for investments in state-of-the-art emissions controls for the three proposed new units. As part of the development program, additional environmental control systems will be included at Luminant Power’s existing generation facilities. Estimates for capital expenditures associated with the full potential scope of these additional environmental control systems are in the range of approximately $1 billion to $1.3 billion. Luminant Power has yet to undertake and complete detailed cost and engineering studies for the additional environmental systems. The cost estimates for capital expenditures at Luminant Power’s existing facilities are subject to change, which change could be substantial as Luminant Power determines the details of and further evaluates the engineering and construction costs related to these investments.

Development and procurement activities for the three proposed units are essentially complete and site construction is well underway. Air permits have been obtained and EPC agreements have been executed with Bechtel Power Corporation and Fluor Enterprises, Inc. The expected on-line dates of the units are as follows: Sandow in 2009 and Oak Grove’s two units in 2009 and 2010.

TXU Energy

TXU Energy serves more than 2.1 million retail electricity customers, of which 1.9 million are in its historical service territory, which was the territory, largely in north Texas, being served by Energy Future Holdings Corp.’s regulated electric utility subsidiary at the time of entering retail competition on January 1, 2002. This territory, which is located in the north-central, eastern and western parts of Texas, has an estimated population in excess of 7 million, about one-third of the population of Texas, and comprises 92 counties and 370 incorporated municipalities, including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler and Killeen.

Texas is one of the fastest growing states in the nation with a diverse and resilient economy and, as a result, has attracted a number of competitors into the deregulated retail electricity market. As a result, competition is expected to continue to be robust. TXU Energy, as an active participant in this competitive market, provides retail electric service to the other areas of ERCOT now open to competition including the Houston, Corpus Christi, and lower Rio Grande Valley areas of Texas. TXU Energy continues to market its services in Texas to add new customers and to retain its existing customers. As of September 2007, there are more than 100 REPs certified to compete within the state of Texas.

As a result of the legislation that restructured the electric utility industry in Texas to provide for retail competition (1999 Restructuring Legislation), effective January 1, 2002, REPs affiliated with electricity delivery utilities were required to charge price-to-beat retail prices, established by the Public Utility Commission of Texas (the Commission), to residential and small business customers located in their historical service territories. The price-to-beat mechanism was intended to spur competition as the rates were set such that competing REPs could profitably offer lower rates. TXU Energy, as a REP affiliated with an electricity delivery utility, was required to charge the price-to-beat retail price, adjusted for fuel factor changes, to these classes of customers until the earlier of January 1, 2005 or the date on which 40% of the electricity consumed by customers in that class was supplied by competing REPs. TXU Energy met the 40% threshold target calculation for its small business customers in December 2003 and began offering rates other than the price-to-beat retail prices to this customer class. Since January 1, 2005, TXU Energy has offered rates different from the price-to-beat retail prices to all customer classes, but was required to make the price-to-beat retail prices available for residential and small business customers in its historical service territory until January 1, 2007. As of January 1, 2007, TXU Energy is no longer required to offer the price-to-beat retail price to any of its customer classes.

In connection with the Merger, TXU Energy announced a 15 percent price reduction for residential customers in its historical service territory who have not already switched to one of the many pricing plans other than the basic month-to-month plan. These customers received a six percent reduction beginning in late March 2007 and an additional four percent reduction in June 2007 and will receive an additional five percent reduction

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effective in late October 2007. In addition, TXU Energy will provide price protection to these customers through December 2008, ensuring that these customers receive the benefits of these savings through two summer seasons of peak energy usage.

Regulated Delivery Segment

The Regulated Delivery segment primarily consists of Oncor Electric Delivery. Oncor Electric Delivery provides the essential service of delivering electricity safely, reliably and economically to end-use consumers through its distribution systems, as well as providing transmission grid connections to merchant power plants and interconnections to other transmission grids in Texas. Operating assets of the segment are located principally in the north-central, eastern and western parts of Texas.

Oncor Electric Delivery is not a buyer or seller of power. It provides transmission services to other electricity distribution companies, cooperatives and municipalities. It provides distribution services to REPs, which sell power to retail customers. Most of Oncor Electric Delivery’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law. Oncor Electric Delivery’s transmission and distribution rates are regulated by the PUCT.

Electricity Transmission

Oncor Electric Delivery’s electric 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 Oncor Electric Delivery’s transmission facilities in coordination with ERCOT.

Oncor Electric Delivery is a member of ERCOT, and the transmission business actively supports the operations of ERCOT and market participants. 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, interconnect to merchant power plants, increase bulk power transfer capability and minimize limitations and constraints on the ERCOT transmission grid. For a more complete description of ERCOT see “ERCOT Market Framework” below.

Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree, the FERC. Network transmission revenues compensate Oncor Electric Delivery for delivery of power over transmission facilities operating at 60 kilovolts (kV) and above. Transformation service revenues compensate Oncor Electric Delivery for substation facilities that transform power from high-voltage transmission to distribution voltages below 60 kV. Other services offered by the transmission business include, but are not limited to: system impact studies, facilities studies and maintenance of transformer equipment, substations and transmission lines owned by other nonretail parties.

Provisions of the 1999 Restructuring Legislation allow Oncor Electric Delivery to annually update its transmission rates to reflect changes in invested capital. These provisions encourage investment in the transmission system to help ensure reliability and efficiency by allowing for timely recovery of and return on new transmission investments.

Oncor Electric Delivery’s transmission facilities include 4,680 circuit miles of 345-kV transmission lines and 9,684 circuit miles of 138- and 69-kV transmission lines. In 2006, 198 circuit miles of new 345-kV transmission lines were constructed. Forty-five generating plants totaling 32,699 MW are directly connected to Oncor Electric Delivery’s transmission system, and 710 distribution substations are served from Oncor Electric Delivery’s transmission system.

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Oncor Electric Delivery’s transmission facilities have the following connections to other transmission grids in Texas:

	Number of Interconnected Lines
	345 kV	138 kV	69 kV
Grid Connections
Centerpoint Energy Inc.	8	—	—
American Electric Power Company, Inc.(a)	4	7	12
Lower Colorado River Authority	6	20	3
Texas Municipal Power Agency	8	9	—
Texas New Mexico Power	2	9	11
Brazos Electric Power Cooperative	4	94	21
Rayburn Country Electric Cooperative	—	27	7
City of Georgetown	—	2	—
Other small systems operating wholly within Texas	—	10	3

(a) One of the 345-kV lines is on asynchronous high voltage current connection with the Southwest Power Pool.

Electricity Distribution.    Oncor Electric Delivery’s electricity distribution business is responsible for the overall safe and efficient operation of distribution facilities, including power delivery, power quality and system reliability. The Oncor Electric Delivery distribution system includes over 3 million points of delivery. The electricity distribution business consists of the ownership, management, construction, maintenance and operation of the distribution system within Oncor Electric Delivery’s certificated service area. Over the past five years, the number of Oncor Electric Delivery’s distribution system points of delivery served has been growing an average of 2% per year, adding approximately 43,000 points of delivery in 2006.

Oncor Electric Delivery’s distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through approximately 3,000 distribution feeders.

The Oncor Electric Delivery distribution system consists of 56,102 miles of overhead primary conductors, 21,879 miles of overhead secondary and street light conductors, 14,578 miles of underground primary conductors and 9,114 miles of underground secondary and street light conductors. The majority of the distribution system operates at 25-kV and 12.5-kV.

Customers.    Oncor Electric Delivery’s transmission customers consist of municipalities, electric cooperatives and other distribution companies. Oncor Electric Delivery’s distribution customers consist of approximately 60 REPs in Oncor Electric Delivery’s certificated service area, including TXU Energy. For the year ended December 31, 2006, distribution revenues from TCEH represented 52% of Oncor Electric Delivery’s distribution revenues and 46% of Oncor Electric Delivery’s total revenues. The retail customers who purchase and consume electricity delivered by Oncor Electric Delivery are free to choose their electricity supplier from REPs who compete for their business.

Legal Proceedings

Litigation—Two putative class and derivative lawsuits and one derivative lawsuit were filed in the United States District Court, Northern District of Texas, Dallas Division in March 2007 against the directors of Energy Future Holdings Corp., Energy Future Holdings Corp., as a nominal defendant, and the Sponsors. On April 27, 2007, the Plaintiffs filed Amended Complaints asserting only derivative claims against the same defendants. The

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lawsuits seek to challenge and enjoin the Merger Agreement. The cases allege that the directors abused their ability to control and influence Energy Future Holdings Corp., committed gross mismanagement and violated various fiduciary duties by approving the Merger Agreement and the Sponsors aided and abetted that alleged conduct. The Plaintiffs contend that the directors violated fiduciary duties owed to shareholders by failing to maximize the value of Energy Future Holdings Corp. and by breaching duties of loyalty and due care by not taking adequate measures to ensure that the interests of shareholders were properly protected. The Merger Agreement allowed Energy Future Holdings Corp. to solicit other proposals from third parties until April 16, 2007 and the transaction was subject to the approval of Energy Future Holdings Corp.’s shareholders, which was obtained at the annual meeting of shareholders on September 7, 2007. Accordingly, Energy Future Holdings Corp. and its directors filed Motions to Dismiss based on the Plaintiffs’ failure to comply with the provisions of the Texas Business Organizations Code (“TBOC”) applicable to filing and pursuing derivative proceedings. The Motions are pending before the Court.

In February and March 2007, three derivative lawsuits were filed in Dallas County state district courts arising out of the Merger Agreement. The suits, filed by putative shareholders, allege that Energy Future Holdings Corp.’s directors, named as defendants, breached fiduciary duties owed Energy Future Holdings Corp. by approving the Merger Agreement. The petitions, now consolidated into one action in the 44th District Court, Dallas County, Texas, include claims that the defendants failed to ensure that the transaction was in the best interest of Energy Future Holdings Corp.; that the directors participated in a transaction where their loyalties were divided and where they were to receive a personal financial benefit; that such alleged conduct constituted a breach of their duties of care, loyalty, good faith, candor and independence owed to Energy Future Holdings Corp.; and that the Sponsors aided and abetted the alleged breaches of fiduciary duties by the directors. Energy Future Holdings Corp. believes that the Plaintiffs failed to comply with provisions of the Texas Business Organizations Code applicable to filing and pursuing derivative proceedings and thus have filed a Motion to Dismiss that is pending before the Court. Additionally, Energy Future Holdings Corp. has filed a Written Statement with the Court advising that, pursuant to the Texas Business Organizations Code, a Derivative Demand Committee of independent and disinterested members of Energy Future Holdings Corp.’s board of directors has been formed and is engaged in the active review, in good faith, of the allegations in the consolidated derivative lawsuits. Consequently, Energy Future Holdings Corp. has requested that the Court enforce the automatic and mandatory stay of the proceedings as provided in the Texas Business Organizations Code until the Derivative Demand Committee has completed its review. On May 16, 2007, the parties agreed to stay the consolidated derivative proceeding pending the Derivative Demand Committee’s review of Plaintiffs’ claims in that proceeding. On May 18, 2007, the Court entered an order staying the action in accordance with Section 21.555 of the TBOC. On July 18, 2007, Energy Future Holdings Corp. filed a Written Statement pursuant to TBOC Section 21.555(c) and an Application for Additional Stay informing the District Court that the Derivative Demand Committee was continuing its active review, in good faith, of the allegations set forth in the derivative lawsuits and accordingly requested an extension of the order staying the action through August 31, 2007. The Court has not yet ruled upon the Written Statement and Application.

In February and March 2007 eight lawsuits were filed in state district court in Dallas County, Texas by putative shareholders against the directors of Energy Future Holdings Corp., Energy Future Holdings Corp., the Sponsors, and certain financial entities, asserting claims on behalf of owners of shares of Energy Future Holdings Corp. common stock as well as seeking to certify a class action on behalf of allegedly similarly situated shareholders. The lawsuits, which have been consolidated into one action in the 44th District Court, Dallas County, Texas, contend that the directors of Energy Future Holdings Corp. violated various fiduciary duties owed plaintiffs and other shareholders in connection with the execution of the Merger Agreement and that the Sponsors and certain financial entities aided and abetted the alleged breaches of fiduciary duties by the directors. Plaintiffs seek to enjoin defendants from consummating the Merger Agreement until such time as a procedure or process is adopted to obtain the highest possible price for shareholders, as well as a request that the Court direct the officers and directors of Energy Future Holdings Corp. to exercise their fiduciary duties in order to obtain a transaction in the best interest of Energy Future Holdings Corp. shareholders. The consolidated suit includes claims that the directors failed to take steps to properly value or maximize the value of Energy Future Holdings

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Corp. and breached their duties of loyalty, good faith, candor and independence owed to Energy Future Holdings Corp. shareholders. The Merger Agreement allowed Energy Future Holdings Corp. to solicit other proposals from third parties until April 16, 2007 and was subject to the approval of Energy Future Holdings Corp.’s shareholders, which was obtained at the annual meeting of shareholders on September 7, 2007. The consolidated suit purports to assert claims by shareholders directly against the directors. Energy Future Holdings Corp. believes that Texas law does not recognize such a cause of action. Consequently, Energy Future Holdings Corp. and its directors have filed a Motion to Dismiss. On May 25, 2007, the Court granted the Motion and dismissed the consolidated putative class action suit with prejudice. On May 31, 2007, Plaintiffs moved for reconsideration of the May 25 Order dismissing the action; however, Plaintiffs subsequently withdrew this motion.

On July 19, 2007, a putative class action lawsuit was filed in the United States District Court, Northern District of Texas, Dallas Division by a putative shareholder against Energy Future Holdings Corp. and its directors asserting a claim under Section 14(a) of the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder, asserting that the preliminary proxy statement of Energy Future Holdings Corp. filed June 14, 2007 fails to adequately describe the relevant facts and circumstances regarding the Merger as well as seeking to certify the litigation as a class action on behalf of allegedly similarly situated shareholders. Energy Future Holdings Corp. has not yet responded to this litigation and, as described below, on July 23, 2007, the Sponsors, joined by Energy Future Holdings Corp. for the limited purpose described below, have entered into a memorandum of understanding with plaintiffs that would result in the dismissal of this litigation if the settlement is approved by the courts. In the event that Energy Future Holdings Corp. is required to respond to this litigation, Energy Future Holdings Corp. will file a Motion to Dismiss based on the fact that this proxy statement clearly and accurately describes the information regarding the Merger and the information necessary for a shareholder to evaluate the proposal to approve the Merger Agreement. We believe the claims made in this litigation are without merit and, therefore, if necessary, we intend to vigorously defend this litigation.

On July 23, 2007, the Sponsors, joined by Energy Future Holdings Corp. for the limited purpose described below, executed a memorandum of understanding with the plaintiffs in certain of the lawsuits described above pursuant to which, if approved by the court in which the litigation is pending, to the extent required, all of the litigation related to the Merger will be dismissed with prejudice. Neither Energy Future Holdings Corp. nor any of its directors agreed to fund any payment or pay any other consideration under the settlement. Energy Future Holdings Corp. did agree to make certain revisions to the final proxy statement as part of the agreement between the Sponsors and the plaintiffs to settle the litigation and agreed that under certain circumstances the termination fee payable by Energy Future Holdings Corp. under the Merger Agreement would be $925 million rather than $1 billion. The settlement of the litigation, subject to court approval, will result in a dismissal of all claims against Energy Future Holdings Corp. and its officers and directors related to the Merger.

On December 1, 2006, a lawsuit was filed in the United States District Court for the Western District of Texas against TXU Generation Company, LP, Oak Grove Management Company LLC and Energy Future Holdings Corp. The complaint seeks declaratory and injunctive relief, as well as the assessment of civil penalties, with respect to the permit application for the construction and operation of the Oak Grove generation plant in Robertson County, Texas. The plaintiffs allege violations of the federal Clean Air Act, Texas Health and Safety Code and Texas Administrative Code and seek to temporarily and permanently enjoin the construction and operation of the Oak Grove generation plant. The complaint also asserts that the permit application was deficient in failing to comply with various modeling and analyses requirements relative to the impact of emissions on the environment. Plaintiffs further request that the court enter an order requiring the defendants to take other appropriate actions to remedy, mitigate and offset alleged harm to the public health and environment. We believe the Oak Grove air permit, granted by the TCEQ, is protective of the environment and that the application for and the processing of the air permit by Oak Grove Management Company LLC with the TCEQ has been in accordance with law. The plaintiffs’ complaint was dismissed by the Federal District Court on May 21, 2007 in response to Energy Future Holdings Corp.’s Motion to Dismiss, and the matter is now on appeal to the Court of Appeals for the Fifth Circuit. We believe that the claims made in this complaint are without merit and, accordingly, intend to vigorously defend this appeal.

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On September 6, 2005 a lawsuit was filed in the U.S. District Court for the Northern District of Texas, Dallas Division against Energy Future Holdings Corp. and C. John Wilder. The plaintiffs’ amended complaint asserts claims on behalf of the plaintiffs and a putative class of owners of certain Energy Future Holdings Corp. securities who tendered such securities in connection with a tender offer conducted by Energy Future Holdings Corp. in 2004. The amended complaint alleges violations of the provisions of Sections 14(e), 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 thereunder. The allegations relate to a tender offer conducted in September and October 2004 for certain equity-linked securities in which it was expressly disclosed that Energy Future Holdings Corp. management was evaluating whether it should recommend to the board of directors that the board reevaluate Energy Future Holdings Corp.’s dividend policy. After the tender offer was closed, and consistent with the disclosure, management did make a recommendation to the board to reevaluate the dividend policy and the board elected to increase the quarterly dividend. The plaintiffs contend that such disclosure in connection with the tender offer was inadequate. We maintain that the disclosure provided in connection with the tender offer regarding the evaluation of the dividend policy was complete and accurate at the time the tender offer was initiated as well as when it was closed. A Motion to Dismiss was filed by the defendants, and the District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice on August 30, 2006. The plaintiffs filed a timely notice of appeal and, on appeal, the U.S. Fifth Circuit Court of Appeals remanded the dismissal to the District Court in light of the decisions in Tellabs, Inc. v. Makor Issues & Rights, Ltd. While we are unable to estimate any possible loss or predict the outcome of this litigation, we believe the claims made in this litigation are without merit and, accordingly, intend to vigorously defend this litigation, including the appeal of the District Court’s order dismissing the complaint.

In November 2002, February 2003 and March 2003, three lawsuits were filed in the U.S. District Court for the Northern District of Texas, Dallas Division, asserting claims under the Employee Retirement Income Security Act (“ERISA”) on behalf of a putative class of participants in and beneficiaries of various employee benefit plans of Energy Future Holdings Corp. These ERISA lawsuits were consolidated, and a consolidated complaint was filed in February 2004 against Energy Future Holdings Corp., the directors of Energy Future Holdings Corp. serving during the putative class period as well as certain officers of Energy Future Holdings Corp. who were the members of the TXU Thrift Plan Committee. The plaintiffs seek to represent a class of participants in such employee benefit plans during the period between April 26, 2001 and October 11, 2002. The plaintiffs filed an initial motion for class certification and, after class certification discovery was completed, the District Court denied plaintiffs’ initial class certification motion without prejudice and granted plaintiffs’ leave to amend their complaint. Plaintiffs’ second class certification motion, filed on the basis of their amended complaint, was denied and the case was ordered dismissed without prejudice on September 29, 2005. The plaintiffs filed an appeal of the dismissal to the Fifth Circuit Court of Appeals. While on appeal, the matter was referred to the Fifth Circuit’s alternative dispute resolution program and subsequently to mediation. While mediation was unsuccessful, further discussions led to an agreement in principle to settle this litigation on December 24, 2006 for $7.25 million, before attorney’s fees, to be paid by Energy Future Holdings Corp. to the thrift plan pursuant a Court approved allocation. A Memorandum of Understanding confirming the agreement in principle was signed on January 24, 2007 and the settlement is in the process of being confirmed with final settlement documents after which the settlement will be submitted to the District Court for approval. We believe the claims are without merit and, in the event the settlement is not approved, intends to vigorously defend the lawsuit, including the appeal. Energy Future Holdings Corp. is, however, unable to estimate any possible loss or predict the outcome of this action in the event the District Circuit rejects the settlement, the Fifth Circuit reverses the dismissal and remands the case to the District Court or the suit is refiled by the plaintiffs or others seeking to assert similar claims.

We are also involved in litigation concerning environmental permits for the three new lignite coal-fueled units that Luminant is developing at Oak Grove and Sandow. See “Energy Future Holding Corp. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Significant Developments—Texas Generation Facilities Development.”

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In addition to the above, Energy Future Holdings Corp. and its subsidiaries is involved in various other legal and administrative proceedings in the normal course of business the ultimate resolution of which, in the opinion of management, should not have a material effect on its financial position, results of operations or cash flows.

Regulatory Investigations—In October 2006, Luminant Energy was notified that the PUCT had begun an informal investigation of its 2005 activities in the ERCOT wholesale electricity market as a result of observations noted in the 2005 State of the Market Report for theERCOT Wholesale Electricity Markets performed by Potomac Economics, an economic consulting firm. The investigation was focused on activities involving bids to sell balancing energy and generation unit commitments. Balancing energy represents approximately five to ten percent of the total energy sold in the ERCOT wholesale market. Luminant Energy has cooperated fully with the PUCT in its informal investigation.

In March 2007, the PUCT issued a Notice of Violation (“NOV”) stating that the PUCT staff is recommending an enforcement action, including the assessment of administrative penalties, against us and certain affiliates for alleged market power abuse by its power generation affiliates and Luminant Energy in ERCOT-administered balancing energy auctions during certain periods of the summer of 2005. The PUCT staff issued a revised NOV in September 2007, in which the proposed administrative penalty amount was reduced from $210 million to $171 million. The revised NOV was necessary, according to the PUCT staff, to correct calculation errors in the initial NOV. As revised, the NOV is premised upon the PUCT staff’s allegation that TXU Portfolio Management’s bidding behavior was not competitive and increased market participants’ costs of balancing energy by approximately $57 million, including approximately $19 million in incremental revenues to Energy Future Holdings Corp. A hearing requested by Luminant Energy to contest the alleged occurrence of a violation and the amount of the penalty in the NOV has been scheduled to start in April 2008. We believe Luminant Energy’s conduct during the period in question was consistent with the PUCT’s rules and policies, and no market power abuse was committed. Energy Future Holdings Corp. is vigorously contesting the NOV. Energy Future Holdings Corp. is unable to predict the outcome of this matter.

Energy Future Holdings Corp. and Luminant Energy have taken actions to reduce the risk of future similar allegations related to the balancing energy segment of the ERCOT wholesale market, including working with the PUCT staff and the PUCT’s independent market monitor to develop a voluntary mitigation plan for approval by the PUCT. Luminant Energy has submitted a voluntary mitigation plan that was approved by the PUCT in July 2007. The PUCT’s approval action has been challenged by some other market participants on procedural grounds and the initial ruling of the Texas District Court has upheld that challenge. TCEH cannot predict whether the PUCT will appeal that ruling or be successful in any such appeal.

The PUCT staff had been investigating TXU Energy with respect to the renewal process for certain small and medium business customers on term service plans. The investigation did not involve residential customers. In June 2007, TXU Energy reached a settlement agreement with the Staff of the PUCT that was approved by the PUCT in July 2007. While TXU Energy expressly denies any violations of rules, it has agreed to pay the PUCT a $5 million settlement as a compromise in this dispute.

In addition to the above, we are involved in various other regulatory investigations in the normal course of business the ultimate resolution of which, in the opinion of management, should not have a material effect on our financial position, results of operations or cash flows.

Environmental Regulations and Related Considerations

Climate Change and Carbon Dioxide. Luminant’s baseload lignite coal-fueled power plants are significant sources of carbon dioxide (“CO₂”) emissions, generating the great majority of the average of 57 million tons of CO₂ that our monitoring indicates our generation plants have produced annually from 2004 to 2006. The three new lignite coal-fueled units being developed will generate substantial additional CO₂ emissions. We participate in a voluntary electric utility industry sector climate change initiative in partnership with the U.S. Department of Energy. This initiative supports the Bush Administration’s greenhouse gas emissions intensity reduction program, Climate VISION. In addition, we continue to participate in a voluntary greenhouse gas emission

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reduction program under the Energy Policy Act of 1992 and since 1995 has reported the results of its program annually to the U.S. Department of Energy.

In conjunction with the Merger agreement, we announced our commitment to reduce CO₂ emissions and intent to join the U.S. Climate Action Partnership (“USCAP”), which is a broad-based group of businesses and leading environmental groups organized to work with the President, the Congress and all other stakeholders to enact environmentally effective and economically sustainable climate change programs. CO₂ is the principal greenhouse gas that we emit. As part of our support of USCAP, we are also pledging to support a mandatory cap and trade program to reduce CO₂ emissions.

Our approach to addressing global climate change is based upon the following principles:

• Climate change is a global issue requiring a comprehensive solution addressing all greenhouse gases, sources and economic sectors in all countries;

• Development of U.S. energy and environmental policy should seek to ensure U.S. energy security and independence;

• Solutions should encourage investment in a diverse supply of new generation to meet U.S. needs to maintain adequate reserve margins and support economic growth, as well as address customer’s needs for affordable and reliable energy;

• Policies should encourage significant investments in research and development and deployment of a broad spectrum of solutions, including energy efficiency, renewable energy and coal, natural gas and nuclear-fueled generation technologies; and

• Any mandate to reduce greenhouse gas emissions should be developed under a market-based framework that is consistent with expected technology development timelines and supports the displacement of old, inefficient power generation technology with advanced, more efficient technology.

Our strategies for lowering greenhouse gas emissions include:

• Investing in technology—We expect to invest up to $2 billion over the next five to seven years for the development and commercialization of cleaner power plant technologies, including integrated gasification combined cycle, the next generation of more efficient ultra-supercritical coal and pulverized coal emissions technology to reduce CO₂ emission intensity. A number of actions, including research and development investments and partnerships, have already been initiated to advance next-generation technologies.

• Providing electricity from renewable sources—We intend to become a leader in providing electricity from renewable sources by more than doubling our purchases of wind power to more than 1,500 MW. We also intend to promote solar power through solar/photovoltaic rebates.

• Committing to demand side management initiatives—We expect that our subsidiaries will invest $400 million over the next five years in programs designed to encourage customer electricity demand efficiencies.

• Reducing CO₂ emissions by increasing production efficiency—We expect to increase production efficiency of its existing generation facilities by up to 2 percent.

• Evaluating the development of a nuclear generation facility—We plan to develop an application to file with the NRC for combined construction and operating licenses for up to 3,400 MW of new nuclear generation capacity at its Comanche Peak nuclear generation plant. We expect to submit the application in 2008. Nuclear generation is the lowest emission source of baseload generation available.

Increasing public concern and political pressure from local, regional, national and international bodies, may result in the passage of new laws mandating limits on greenhouse gas emissions. A series of reports by the

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Intergovernmental Panel on Climate Change earlier this year attracted considerable public attention and concern. Several bills addressing climate change have been introduced in the U.S. Congress and, in April 2007, the U.S. Supreme Court issued a decision ruling the EPA improperly declined to address CO₂ impacts in a rulemaking related to new motor vehicle emissions. While this decision is not directly applicable to power plant emissions, the reasoning of the decision could affect other regulatory programs. Various proposals in the U.S. Congress could require us to purchase offsets or allowances for some or all of our CO₂ emissions, or otherwise affect us based on the amount of CO₂ we generate. The impact on us of any future greenhouse gas regulation will depend in large part on the details of the requirements and the timetable for mandatory compliance. We continue to assess the financial and operational risks posed by possible future legislative changes pertaining to greenhouse gas emissions, but because these proposals are in the formative stages, we are unable to predict any future impacts on our financial condition and operations.

Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions. The federal Clean Air Act includes provisions which, among other things, place limits on the SO2, NOx and mercury emissions produced by certain generation plants. In addition to the new source performance standards applicable to SO2 (associated with acid rain) and NOx (associated with ozone formation), the Clean Air Act requires that fossil-fueled plants have sufficient SO2 emission allowances and meet certain NOx emission standards. Our generation plants meet the current SO2 allowance requirements and NOx emission rates.

In 2005, the EPA issued a final rule to further reduce SO2 and NOx emissions from power plants. The SO2 and NOx reductions required under the Clean Air Interstate Rule (“CAIR”) are based on a cap and trade approach (market-based) in which a cap is put on the total quantity of emissions allowed in 28 eastern states (including Texas), emitters are required to have allowances for each ton emitted, and emitters are allowed to trade emissions under the cap. The CAIR reductions are required to be phased in between 2009 and 2015.

Also in 2005, the EPA published a final rule requiring reductions of mercury emissions from coal-fueled generation plants. The Clean Air Mercury Rule (“CAMR”) is based on a cap and trade approach on a nationwide basis. The mercury reductions are required to be phased in between 2010 and 2018.

SO2 reductions required under the proposed regional haze/visibility rule (or so-called BART rule) only apply to units built between 1962 and 1977. The reductions would be required on a unit-by-unit basis. The EPA provides the option for states to use CAIR to satisfy the BART reductions for electric generating units and Texas has chosen this option.

In connection with our plan to build three new lignite coal-fueled generation units in Texas, we have committed to reduce emissions of NOx, SO2 and mercury at our existing coal-fueled units so that the total of those emissions from both existing and new lignite/coal-fueled units are 20% below 2005 levels. This reduction is expected to be accomplished through the installation of emissions control equipment in both the new and existing units and possible fuel blending at some existing units. These efforts, which will involve incremental equipment investments, as well as additional costs for facility operations and maintenance in the future, will be coordinated with the CAIR, CAMR and BART rules for the most cost-effective compliance plan options. Estimates for capital expenditures associated with the full potential scope of these additional environmental control systems are in the range of approximately $1 billion to $1.3 billion. Luminant Power has yet to undertake and complete detailed cost and engineering studies for the additional environmental systems. The cost estimates for capital expenditures at Luminant Power’s existing facilities are subject to change, which change could be substantial as Luminant Power determines the details of and further evaluates the engineering and construction costs related to these investments.

The Clean Air Act also requires each state to monitor air quality for compliance with federal health standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted new State Implementation Plan rules in July 2007 to deal with 8-hour ozone standards. These rules require further NOx emission reductions from certain of our facilities in the Dallas-Fort Worth area.

We believe that Energy Future Holdings Corp. holds all required material emissions permits for facilities in operation and has applied for or obtained the necessary permits for facilities under construction.

Water. The TCEQ and the EPA have jurisdiction over water discharges (including storm water) from facilities in Texas. We believe facilities of Energy Future Holdings Corp. are presently in material compliance with applicable state and federal requirements relating to discharge of pollutants into water. Energy Future Holdings Corp. believes it holds all required material waste water discharge permits from the TCEQ for facilities

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in operation and has applied for or obtained necessary permits for facilities under construction. We believe we can satisfy the requirements necessary to obtain any required permits or renewals. Recent changes to federal rules pertaining to Spill Prevention, Control and Countermeasure Plans (“SPCC”) for oil-filled electrical equipment and bulk storage facilities for oil will require updating of certain plants and facilities. We have determined that SPCC plans will be required for certain substations, work centers and distribution systems by July 1, 2009. We are currently compiling data for development of these plans.

Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. Energy Future Holdings Corp. believes it possesses all material necessary permits for these activities from the TCEQ for its present operations. Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large power plants were published by the EPA in 2004. As prescribed in the regulations, we began implementing a monitoring program to determine the future actions that might need to be taken to comply with these regulations. In January 2007, a federal court ruled against the EPA in a lawsuit brought by environmental groups challenging aspects of these regulations, and in July 2007, the EPA announced that it was suspending the regulations pending further rulemaking. We cannot predict the impact on our operations of the suspended existing regulations or of any new regulations that replace them.

Radioactive Waste. Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the State of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The State of Texas has agreed to a compact for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by the President in 1998. In 2003, the State of Texas enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal, and in 2004 the State received a license application from such an entity for review. We intend to continue to ship low-level waste material off-site for as long as an alternative disposal site is available. Should existing off-site disposal become unavailable, the low-level waste material will be stored on-site. Our on-site storage capacity at the Comanche Peak plant is expected to be adequate until other off-site facilities become available. (See discussion under “—TCEH Operating Segment—Luminant Power—Nuclear Generation Assets” above.)

Solid Waste, including Fly Ash Associated with Lignite/Coal-Fueled Generation. Treatment, storage and disposal of solid waste and hazardous waste are regulated at the state level under the Texas Solid Waste Disposal Act and at the federal level under the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act. The EPA has issued regulations under the Resource Conservation and Recovery Act of 1976 and the Toxic Substances Control Act, and the TCEQ has issued regulations under the Texas Solid Waste Disposal Act applicable to our facilities. We believe we are in material compliance with all applicable solid waste rules and regulations. In addition, we have registered solid waste disposal sites and have obtained or applied for permits required by such regulations.

Environmental Capital Expenditures. Capital expenditures for our environmental projects totaled $48 million in 2006 and are expected to total approximately $111 million in 2007, exclusive of emissions control equipment investment planned as part of the three-unit Texas generation development program, which is expected to total up to $450 million over the construction period. Estimates for capital expenditures associated with the full potential scope of these additional environmental control systems at Luminant Power’s existing generation facilities are in the range of approximately $1 billion to $1.3 billion. Luminant Power has yet to undertake and complete detailed cost and engineering studies for the additional environmental systems. The cost estimates for capital expenditures at Luminant Power’s existing facilities are subject to change, which change could be substantial as Luminant Power determines the details of and further evaluates the engineering and construction costs related to these investments.

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REGULATION AND RATES

General

2007 Texas Legislative Session

The Texas Legislature convened in its regular biennial session on January 9, 2007 and adjourned on May 28, 2007. The session was not a “sunset” session for the PUCT, so there was no requirement that the Legislature consider any electric industry-related bills. However, various measures pertaining to the electric industry were considered. The primary measures that were under consideration and would have materially affected our businesses and potentially the Merger were ultimately not enacted. New PURA provisions were enacted that ensure the PUCT shall have authority to enforce commitments made in a filing under PURA Section 14.101 (such as the filing with the PUCT made by Texas Holdings and Oncor Electric Delivery on April 25, 2007). In addition, the Sponsors have publicly indicated their intention to:

• Spend more than $30 million per year over five years to provide relief for low-income residents and to pursue new demand side management initiatives in conservation, energy efficiency and weatherization;

• In the current regulatory system, hold a majority of their ownership in Energy Future Holdings Corp. for more than five years after closing of the Merger; and

• Invest significant resources in emerging energy technologies, such as integrated gasification combined cycle coal plants, including an increased commitment to renewable energy.

Luminant

Luminant Power is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to the jurisdiction of the NRC with respect to its nuclear generation plant. NRC regulations govern the granting of licenses for the construction and operation of nuclear generation plants and subject such plants to continuing review and regulation. Luminant Energy holds a power marketer license from the FERC.

Wholesale Market Design

In August 2003, the PUCT adopted a rule that, when implemented, will alter the wholesale market design in ERCOT. The rule requires ERCOT:

• to use a stakeholder process to develop a new wholesale market model;

• to operate a voluntary day-ahead energy market;

• to directly assign all congestion rents to the resources that caused the congestion;

• to use nodal energy prices for resources;

• to provide information for energy trading hubs by aggregating nodes;

• to use zonal prices for loads; and

• to provide congestion revenue rights (but not physical rights).

ERCOT currently has a zonal wholesale market structure consisting of four geographic zones. The proposed location-based congestion-management market is referred to as a “nodal” market because wholesale pricing would differ across the various locational nodes on the transmission grid. The implementation of a nodal market is being done in conjunction with transmission improvements designed to reduce current congestion. In March 2006, the PUCT approved a set of Nodal Protocols, which was filed by ERCOT and describes the operation of a wholesale nodal market, and set an implementation date of no later than January 1, 2009. In August 2006, the PUCT adopted an interim order approving ERCOT’s application for a surcharge imposed on all Qualified Scheduling Entities in ERCOT (including subsidiaries of TCEH) for the purpose of financing 38% of ERCOT’s expected nodal implementation costs. The interim surcharge took effect on October 1, 2006. On May 23, 2007,

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the PUCT adopted an order approving ERCOT’s request for a final nodal-market-implementation surcharge and set the effective date for that surcharge as June 1, 2007. We expect that the annual impact of the final surcharge will be approximately $7 million to $8 million in additional expense. Although we do not expect our competitive position in the ERCOT market to be materially adversely affected by the proposed nodal wholesale market design, we are unable to predict the ultimate impact of the proposed nodal wholesale market design on our operations or financial results.

Nuclear Decommissioning

Luminant Power’s nuclear plant decommissioning costs are fully recoverable from Oncor Electric Delivery’s distribution customers. Through December 31, 2001, decommissioning costs were recovered from consumers based upon a 1992 site-specific study through rates placed in effect under our January 1993 rate increase request. Effective January 1, 2002, decommissioning costs are recovered through a tariff charged to REPs by Oncor Electric Delivery based upon a 2000 redetermination of the 1997 site-specific study, adjusted for trust fund assets, as a component of delivery fees effective under our 2001 Unbundled Cost of Service filing. In 2005, an updated study of the cost to decommission our nuclear generating facility was completed by management and was filed with the PUCT in June 2005. The accompanying testimony concluded that no change to the nuclear decommissioning tariff was warranted at that time. In July 2005, the PUCT’s Policy Development Division issued an order approving the decommissioning cost study and closing the docket.

Regulatory Investigations

Please refer to “Business—Legal Proceedings” elsewhere in this Current Report on Form 8-K for a description of certain regulatory investigations.

TXU Energy

REP Certification Rulemaking

On March 30, 2007, the PUCT publicly requested comments on proposed revisions to its substantive rules governing the certification of REPs that, if ultimately approved, would have (1) expanded the types of transactions that would be considered to constitute the transfer of a REP certificate and (2) subjected a REP to unspecified additional or different financial requirements if it serves one million residential customers in Texas or more and does not have its own investment grade credit rating. The PUCT Staff conducted a workshop on September 24, 2007 to discuss with interested stakeholders potential revisions to the rule and the largest REPs, including TXU Energy, ultimately agreed with the PUCT Staff to compromise rule revision language specifying acceptable additional minimum financial requirements for REPs with at least one million Texas residential customers. In an Open Meeting on October 9, 2007, the PUCT voted to approve revisions to its REP certification rule. The PUCT Commissioners declined to make any revisions to expand the types of transactions that would be considered to constitute the transfer of a REP certificate. The PUCT Commissioners approved the compromise agreed to by the largest REPs and PUCT Staff. The approved revisions provide that REPs that serve one million Texas residential customers or more are subject to additional or different financial requirements as determined by the PUCT unless they meet one of the following specified additional financial requirements: (1) a heightened credit rating of “BBB” for S&P or “Baa2” for Moody’s, or their financial equivalent (satisfied through the REP’s own credit rating, a guaranty of a parent or controlling shareholder with the required credit rating, or a bond, guaranty or corporate commitment of another company with the required credit rating); (2) an increased amount of equity (defined as assets in excess of liabilities); or (3) an increased amount of unused cash resources. The additional financial requirements are not anticipated to significantly increase TCEH’s cost of doing business.

Regulatory Investigations

Please refer to “Business—Legal Proceedings” elsewhere in this Current Report on Form 8-K for a description of certain regulatory investigations.

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Oncor Electric Delivery

General

Because its operations are wholly within Texas, Oncor Electric Delivery believes that it is not a public utility as defined in the Federal Power Act and has been advised by counsel that it is not subject to general regulation under such act.

The PUCT has original jurisdiction over transmission and distribution rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT and has exclusive appellate jurisdiction to review the rate and service orders and ordinances of municipalities. Generally, the PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that does not have the prior approval of the appropriate regulatory authority (the PUCT or municipality with original jurisdiction).

At the state level, PURA, as amended, requires owners or operators of transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility’s own use of its system. The PUCT has adopted rules implementing the state open-access requirements for utilities that are subject to the PUCT’s jurisdiction over transmission services, such as Oncor Electric Delivery.

Report Filed with the PUCT Regarding Merger

In April 2007, Oncor Electric Delivery and Texas Holdings (together, the “Applicants”) filed a Joint Report and Application (“Report”) with the PUCT pursuant to Section 14.101(b) of PURA and PUCT SUBST. R.25.75. As a result of the consummation of the Merger, Texas Holdings owns all or substantially all of the outstanding shares of Energy Future Holdings Corp., and Oncor Electric Delivery remains a direct or indirect wholly-owned subsidiary of Energy Future Holdings Corp. This report contained commitments that took effect upon the closing of the Merger. Such commitments include: maintenance of specified Oncor Electric Delivery debt-to-equity ratios, minimum Oncor Electric Delivery capital expenditure levels, increased spending on demand-side management/energy efficiency programs over the amount in Oncor Electric Delivery’s rates, minimum five year continued majority ownership by the Sponsors and that Oncor Electric Delivery will not incur any indebtedness and will not guarantee or use its assets to secure any affiliate indebtedness incurred to finance the Merger.

Section 14.101(b) of PURA requires that a transaction involving the sale of more than 50% of the stock of a public utility be reported to the PUCT within a reasonable time subsequent to consummation of the transaction and that the PUCT shall determine whether the transaction is consistent with the public interest standards set out therein. Although the Merger does not involve the direct sale of public utility stock, the Applicants filed the Report pursuant to Section 14.101(b) of PURA as it relates to Oncor Electric Delivery. Many of the parties to this proceeding, including Oncor Electric Delivery and the PUCT staff, have agreed on the terms of a settlement of this proceeding. A procedural schedule has been adopted for the consideration of a non-unanimous settlement, with the Hearing on the Merits currently scheduled for December 12-13, 2007. The PUCT does not have authority to approve or reject the transaction.

PUCT Request for Oncor Electric Delivery Rate Filing

At the request of the PUCT, the PUCT Staff filed a petition in March 2007 requesting that the PUCT order Oncor Electric Delivery to file a rate case based on a test year ending December 31, 2006. PUCT Staff stated that it would be advantageous to review Oncor Electric Delivery’s costs prior to major ownership and organizational changes that Energy Future Holdings Corp. has announced in order to establish a baseline from which to assess any cost changes resulting from the announced changes. In April 2007, the PUCT issued an order requiring Oncor Electric Delivery to file a rate case based on a test year ending December 31, 2006. On August 28, 2007, Oncor Electric Delivery made the required filing, and the filing supports a rate increase of approximately $85 million over current rates subject to the original jurisdiction of the PUCT. However, Oncor Electric Delivery

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requested that the PUCT enter an order abating the proceeding, except that the PUCT convene a technical conference to consider a final order in this Docket No. 34040 that would include the following provisions: (i) the PUCT will take “no action” on Oncor Electric Delivery’s proposed rate filing package and will enter an order confirming that Oncor Electric Delivery’s current rates will remain in effect until otherwise changed by a final order of the PUCT or other appropriate jurisdictional authority; (ii) Oncor Electric Delivery will be required to file a system-wide rate case with the PUCT no later than July 1, 2008, based on a test year ended December 31, 2007, consistent with the Settlement Agreement between Oncor Electric Delivery and certain cities in its service territory; (iii) Oncor Electric Delivery will be required to file an Earnings Monitor Report (“EMR”) with the PUCT no later than March 15, 2008, for calendar year 2007, and no later than March 15, 2009, for calendar year 2008, notwithstanding the pendency at the PUCT of this or any other Oncor Electric Delivery rate case; and (iv) the PUCT will enter an accounting order, or similar directive, providing that if Oncor Electric Delivery’s 2008 or 2009 EMR filings demonstrate that Oncor Electric Delivery earned more than a 10.75% return on equity (“ROE”) during the relevant period covered by the EMR filing, on a weather normalized basis, Oncor Electric Delivery will record a credit to the underrecovery balance in its insurance reserve, such that the additional expense would result in Oncor Electric Delivery’s ROE for the relevant period being no higher than 10.75%.

Many of the parties to this case have agreed to abate this case as part of the non-unanimous settlement described above related to the Report filed with the PUCT pursuant to PURA Section 14.101(b). That non-unanimous settlement, which is subject to approval by the PUCT, includes a one-time rate credit to all retail customers of $72 million.

Transmission Rates

In order to recover increased affiliate and third-party transmission costs from REPs, Oncor Electric Delivery is allowed to request an update twice a year to the transmission cost recovery factor (“TCRF”) component of its retail delivery rate charged to REPs. In January 2007, an application was filed to increase the TCRF, which was administratively approved on February 22, 2007 and became effective March 1, 2007. This increase is expected to increase annualized revenues by $14 million. In July 2007, an application was filed to increase the TCRF, which was approved administratively on August 23, 2007 and became effective September 1, 2007. This increase is expected to increase annualized revenues by $26 million and includes the $15 million of the wholesale transmission rate increase which is recoverable from REPs as described below.

In February 2007, Oncor Electric Delivery filed an application for an interim update of its wholesale transmission rate. The application was approved by the PUCT in April 2007 and the new rate went into effect immediately. Annualized revenues are expected to increase by approximately $38 million. Approximately $23 million of this increase is recoverable through transmission rates charged to wholesale customers, and the remaining $15 million is recoverable from REPs through the TCRF component of Oncor Electric Delivery’s delivery rates charged to REPs.

Competitive Renewable Energy Zones

In the first quarter of 2007, the PUCT initiated a docket to identify the transmission facilities necessary to interconnect future renewable energy generating facilities. As part of the docket, the PUCT considered which zones would contain the best renewable energy sources. On July 20, 2007, the PUCT voted to designate zones with generation potential of over 20,000 MW.

The PUCT also opened a project to evaluate potential transmission service providers that are interested in constructing the designated transmission facilities. In connection with this project, Oncor Electric Delivery indicated to the PUCT its interest in constructing any designated transmission facilities, particularly those within its traditional service territory and those that interconnect with Oncor Electric Delivery’s transmission facilities.

The PUCT has not yet determined with specificity the desired capacity for any of the designated zones, and has not yet designated transmission facilities, or the transmission service providers that will construct the

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facilities. As such, Oncor Electric Delivery cannot predict the amount of transmission facilities in competitive renewable energy zones, if any, that it will construct.

2006 Cities Rate Settlement

In January 2006 Oncor Electric Delivery agreed with a steering committee representing 108 cities in Texas (the “Cities”) to defer the filing of a system-wide rate case with the PUCT to no later than June 30, 2008 (based on a test year ending December 31, 2007), unless the Cities and Oncor Electric Delivery mutually agree that such a filing is unnecessary. Oncor Electric Delivery has extended the benefits of the agreement to 292 nonlitigant cities. Based on the final agreements, including the participation of the nonlitigant cities, expected payments to the cities are estimated to total approximately $70 million, including incremental franchise taxes.

This amount is being recognized in earnings over the period from May 2006 through June 2008. Payments under the agreement are expected to be made until new tariffs are effective, which based upon an assumed June 2008 rate case filing, is projected to be mid-2009. Payments under the agreement totaled $18 million in 2006 and are expected to total $30 million in 2007, $16 million in 2008 and $6 million in 2009. See Note 9 to the 2006 year-end Financial Statements.

Advanced Meter Rulemaking

In 2005, the Texas Legislature passed legislation that authorized utilities to impose a surcharge to recover costs incurred in deploying advanced metering and meter information networks. Benefits of the advanced metering installation include improved safety, on-demand meter reading, enhanced outage identification and restoration and system monitoring of voltages. At December 31, 2006, Oncor Electric Delivery had installed approximately 285,000 advanced meters in its service territory and anticipates the installation of up to 600,000 additional advanced meters in 2007, which would represent approximately 25% of the meters on the distribution system. Pursuant to the 2005 legislation, the PUCT conducted two rulemakings related to advance metering, and final rules have been adopted that set forth the technical standards for advanced metering and a process for seeking cost recovery. Oncor Electric Delivery is developing its deployment plan for advanced metering infrastructure and intends to file a surcharge request to seek recovery of investment costs incurred.

Reallocation of Stranded Cost Recovery

PURA requires that to the extent statewide stranded costs, including regulatory assets, exceed $5 billion, any stranded costs in excess of $5 billion should to be reallocated among retail customer rate classes. The PUCT earlier determined that Oncor Electric Delivery’s share of the excess could not be reallocated because of the Settlement Plan and related financing order, which resolved all allocation issues. In February 2007, the PUCT reversed its decision, subjecting Oncor Electric Delivery’s allocation to further review by the State Office of Administrative Hearings. Any reallocation would not impact the total revenues collected by Oncor Electric Delivery, but rather the rate classes, partially shifting the transition charges billed to REPs related to the securitization bonds from industrial and commercial to the residential rate classes. Oncor Electric Delivery believes that the initial decision was correct and cannot determine the ultimate outcome of this proceeding.

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MANAGEMENT

Set forth in the chart below are our board members and executive officers, other than our chief executive officer who resigned from our company following the consummation of the Merger. We have initiated a search for a new chief executive officer.

Name	Age(1)	Position(s)
David Bonderman	64	Director
Donald L. Evans	61	Director
Frederick M. Goltz	36	Director
James R. Huffines	56	Director
Scott Lebovitz	32	Director
Jeffrey Liaw	30	Director
Marc S. Lipschultz	38	Director
Michael MacDougall	36	Director
Lyndon L. Olson	60	Director
Kenneth Pontarelli	37	Director
William K. Reilly	67	Director
Jonathan D. Smidt	34	Director
William Young	43	Director
Kneeland Youngblood	52	Director
James A. Burke	38	Chairman of the Board, President and Chief Executive of TXU Energy
David A. Campbell	39	Executive Vice President and Chief Financial Officer of Energy Future Holdings Corp.
M. Rizwan Chand	44	Senior Vice President of Energy Future Holdings Corp.
Michael P. Childers	46	President and Chief Executive of Luminant Construction
Charles R. Enze	54	President and Chief Executive of Luminant Construction
Michael Greene	61	Chairman of the Board, President and Chief Executive of Luminant Power
Michael T. McCall	50	Chairman of the Board, President and Chief Executive of Luminant Energy
David P. Poole	45	Executive Vice President and General Counsel of Energy Future Holdings Corp.
Jonathan A. Siegler	35	Senior Vice President of Strategy, Mergers and Acquisition of TXU Business Services Company

(1) As of September 1, 2007.

David Bonderman is a founder of TPG. Before forming TPG in 1992, Mr. Bonderman was Chief Operating Officer of the Robert M. Bass Group in Fort Worth, Texas. He serves as a director of Burger King, CoStar Group, Gemalto N.V., and Ryanair Holdings, of which he is Chairman. He also serves on the boards of the Wilderness Society, the Grand Canyon Trust, the World Wildlife Fund, the University of Washington Foundation, and the American Himalayan Foundation.

Donald L. Evanshas been the CEO of the Financial Services Forum since 2005, after serving as the 34th secretary of the U.S. Department of Commerce. As Secretary of Commerce, he oversaw a diverse cabinet agency with some 40,000 workers and a $5.8 billion budget focused on promoting American business. Before serving in

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the cabinet, Secretary Evans was the former CEO of Tom Brown, Inc., a large independent energy company. He formerly served as a member and chairman of the Board of Regents of the University of Texas. Secretary Evans also has served as an officer or board member for a number of civic and philanthropic organizations. He attended the University of Texas at Austin, receiving a B.S. degree in mechanical engineering in 1969 and an M.B.A. in 1973.

Frederick M. Goltz has been with KKR for 10 years. Mr. Goltz is one of the heads of KKR’s Energy and Natural Resources industry team and leads KKR’s efforts in the natural resources sector. He is a director of Accuride. He received a B.A., B.S., Magna Cum Laude, from the University of Pennsylvania, and an M.B.A. from INSEAD, Fontainebleau, France.

James R. Huffinesis chairman of the University of Texas System Board of Regents, on which he has served since 2003. He also is Chairman, Central and South Texas, of PlainsCapital Bank in Austin, Executive Vice President of PlainsCapital Corporation, and a director of Hester Capital Mgmt., PlainsCapital Bank, and PlainsCapital Corp. He previously held senior management positions at Hester Capital Management, L.L.C., and Morgan Keegan & Co. Chairman Huffines also is a former Commissioner of the State of Texas Alcoholic Beverage Commission. He also has served as an officer or board member for a number of civic and philanthropic organizations. He earned a BBA degree in finance from the University of Texas at Austin in 1973 and attended Southwestern Graduate School of Banking at Southern Methodist University.

Scott Lebovitz is a Vice President of Goldman, Sachs & Co. in its Principal Investment Area. He joined Goldman, Sachs & Co. as Financial Analyst in 1997. He was promoted to Vice President in 2003. Mr. Lebovitz serves on the boards of Coffeyville Acquisition LLC and Village Voice Media, LLC. He received a B.S. degree from the University of Virginia.

Jeffrey Liaw is active in TPG’s Energy and Industrial investing practice areas. Before joining TPG, he worked for Bain Capital in their Industrials practice. Mr. Liaw is a Phi Beta Kappa graduate of the University of Texas at Austin and received his M.B.A. with High Distinction from Harvard Business School where he was a Baker Scholar and a Siebel Scholar.

Marc S. Lipschultzhas been with KKR for 12 years. He is one of the heads of KKR’s Energy and Natural Resources industry team and leads KKR’s efforts in the power sector. Currently, he is a director of Accel-KKR Company. He received an A.B., Honors and Distinction, Phi Beta Kappa, from Stanford University and an M.B.A. with High Distinction, Baker Scholar, from Harvard Business School.

Michael MacDougall is a partner of TPG. Prior to joining TPG in 2002, Mr. MacDougall was a vice president in the Principal Investment Area of the Merchant Banking Division of Goldman, Sachs & Co., where he focused on private equity and mezzanine investments. Mr. MacDougall received his M.B.A., with distinction, from Harvard Business School. Prior to attending business school, Mr. MacDougall was an assistant brand manager in the Paper Division of Procter & Gamble. He received his B.B.A., with highest honors, from the University of Texas at Austin. Mr. MacDougall serves on the Board of Directors of Aleris International, Altivity Packaging LLC, Kraton Polymers LLC and Energy Future Holdings Corp. (the holding company formed to acquire TXU Corp.), and he served on the Board of Texas Genco LLC prior to its sale to NRG Energy, Inc. Mr. MacDougall also serves on the Board of The Opportunity Network (a charitable organization that creates access for top-performing New York City public school students to influential networks, career opportunities and competitive colleges) and is the Co-Chair of The Dwight School’s Annual Fund.

Lyndon L. Olsonhas been a Senior Advisor with Citigroup Inc. since 2002, after serving as United States Ambassador to Sweden from 1998 to 2001. He previously was affiliated with Citigroup from 1990 to 1998, as President and CEO of Travelers Insurance Holdings and the Associated Madison Companies, predecessor companies. Before joining Citigroup, he had been President of the National Group Corporation and CEO of its National Group Insurance Company. Ambassador Olson also is a former Chairman and a Member of the Texas

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State Board of Insurance, former President of the National Association of Insurance Commissioners, and a former member of the Texas House of Representatives. He also has served as an officer or board member for a number of civic and philanthropic organizations. Ambassador Olson is a graduate of Baylor University and attended Baylor Law School.

Kenneth Pontarelli is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He joined Goldman, Sachs & Co. as a Financial Analyst in 1992. Subsequently, he worked for Bain & Company, Inc. before rejoining Goldman, Sachs & Co.’s Energy & Power Group as an Associate in 1997. He transferred to the Principal Investment Area in 1999 and was promoted to Managing Director in 2004 and to Partner in 2006. Mr. Pontarelli serves on the boards of Coffeyville Acquisition LLC, Cobalt International Energy, L.P., Horizon Wind Energy, and NextMedia Investors, LLC. He received a B.S. degree from Syracuse University and an M.B.A. from Harvard University.

William K. Reillyis a Senior Advisor to TPG and a founding partner of Aqua International Partners, an investment group that invests in companies that serve the water and renewable energy sectors, having previously served as the seventh Administrator of the U.S. Environmental Protection Agency. Mr. Reilly is a director of DuPont, Eden Springs, Ltd. of Israel, ConocoPhillips and Royal Caribbean International. Before serving as EPA Administrator, he was President of World Wildlife Fund and President of The Conservation Foundation. He previously served as Executive Director of the Rockefeller Task Force on Land Use and Urban Growth, a senior staff member of the President’s Council on Environmental Quality, and Associate Director of the Urban Policy Center and the National Urban Coalition. Reilly has written and lectured extensively on environmental issues and is Co-Chairman of the National Commission on Energy Policy. He served in the U.S. Army to the rank of Captain. He also has served as an officer or board member for a number of civic and philanthropic organizations. An alumnus of Yale University, Mr. Reilly holds a law degree from Harvard University and a master’s degree in urban planning from Columbia University.

Jonathan D. Smidt has been with KKR since 2000. He is a member of both the Energy and Natural Resources and the Consumer Products industry teams. Currently, he is a director of Laureate Education Inc. He holds a B.B.S. and a Postgraduate Diploma in Accounting from the University of Cape Town (South Africa).

William Young is Co-Head of the Goldman Sachs Infrastructure Investment Group. Mr. Young joined Goldman Sachs in 2001 as a Managing Director and Co-Head of the European Structured and Principal Finance Group. In 2002, Mr. Young was promoted to a Partner in the Financing Group, which includes all debt, derivative and equity capital markets activities for the Firm. Mr. Young became Co-Head of the Corporate and Acquisition Finance Group, which included the structured and leveraged finance businesses. Prior to joining Goldman Sachs, Mr. Young was with Citibank for 16 years, working in the Leveraged Finance and Work-Out Group and most recently running its European Securitisation Group. Mr. Young received a B.S. from Purdue University in 1987.

Kneeland Youngblood is founding partner of Pharos Capital Group, a private equity firm that focuses on providing growth and expansion capital to businesses in technology, business services, and health care services. Mr. Youngblood is chairman of the American Beacon Funds, a $30 billion mutual fund company, managed by American Beacon Advisors, a $65 billion investment affiliate of American Airlines. He is a director of Starwood Hotels and Lodging. He also serves on the board of directors of Gap Inc. and the Burger King Corporation. He is a former director of the U.S. Enrichment Corporation, a global energy services company privatized in 1998. He served as a Presidential appointee with Senate confirmation in his role on the Board. Mr. Youngblood is a member of the Council on Foreign Relations and graduated from Princeton University in 1978 with an A.B. in Politics/Science in Human Affairs and earned an M.D. degree from the University of Texas, Southwestern Medical School in 1982.

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James A. Burke has been Chairman of the Board, President and Chief Executive of TXU Energy since August 2005 and Executive Vice President of TCEH since July 2006. From 2004 to 2005, Mr. Burke was Senior Vice President Consumer Markets of TXU Energy. Prior to that time, Mr. Burke was President and Chief Operating Officer of Gexa Energy. Before that, Mr. Burke was Senior Vice President, Reliant Resources Incorporated.

David A. Campbell is Executive Vice President and Chief Financial Officer of Energy Future Holdings Corp. He has held the positions of Executive Vice President, Planning, Strategy and Risk of Energy Future Holdings Corp. since May 2004, has been Chief Financial Officer since March 2006 and Executive Vice President of TCEH since September 2006. Prior to joining our company, Mr. Campbell was a Principal of McKinsey & Company, Inc.

M. Rizwan Chand is Senior Vice President of Energy Future Holdings Corp. He has held the positions of Senior Vice President of Energy Future Holdings Corp. since August 2005 and Senior Vice President of TCEH, Oncor Electric Delivery and Oncor Electric Delivery Transition Bond Company, LLC since July 2005. Prior to July 2005, Mr. Chand was Vice President of Human Resources and Corporate Relations for Kennametal, Inc.

Michael P. Childers is President and Chief Executive of Luminant Construction. He has held the positions of President and Chief Executive of Generation Development of Luminant Construction since August 2006 and Executive Vice President and Chief Executive of Generation Development of TCEH since March 2006. From May 2006 to August 2006, Mr. Childers was President and Chief Executive Officer of Luminant Construction. From 2005 to 2006, he was Senior Vice President of TXU Business Services and Senior Vice President of TCEH. Prior to that time, Mr. Childers was President of the Engineering, Construction and Maintenance Division and Executive Vice President for The Shaw Group. Prior to that time, he was President of Entergy Asset Management. Prior to that time, he was Chief Operating Officer of Entergy Wholesale Management Operations.

Charles R. Enze is President and Chief Executive of Luminant Construction. He has held the positions of President and Chief Executive of Generation Construction of Luminant Construction since August 2006 and Executive Vice President and Chief Executive of Generation Construction of TXU Energy Holdings since June 2006. Prior to that time, Mr. Enze was Vice President of Engineering and Projects for Shell International Exploration & Production.

Michael Greene is Chairman of the Board, President, and Chief Executive of Luminant Power. He joined our company as an engineer in 1969 and has served in a variety of senior positions. Mr. Greene is a director of the Electric Power Research Institute and past chairman of ERCOT and the NERC Stakeholder’s Committee. He is an appointed member of the Texas Railroad Commission’s Natural Gas Reliability Council and is a registered professional engineer in the State of Texas. Mr. Greene graduated from the University of Texas at Arlington with a bachelor’s degree in mechanical engineering.

Michael T. McCall is Chairman of the Board, President and Chief Executive of Luminant Energy. He has held the positions of Chairman of the Board, President and Chief Executive of Luminant Wholesale since August 2005 and Executive Vice President of TCEH since April 2006. From 2004 to 2005, Mr. McCall was Senior Vice President of Luminant Power. From 2003 to 2004, he was President of TXU Gas. From 1999 to 2003, he was Vice President of TXU Business Services Company.

David P. Poole is Executive Vice President and General Counsel of Energy Future Holdings Corp. He has held the positions of Executive Vice President and General Counsel of Energy Future Holdings Corp. since March 2006 and Executive Vice President of TCEH since September 2006. From January 2005 to September 2006, Mr. Poole was Senior Vice President and Chief Legal Officer of Luminant Power. From January 2005 to May 2005, he was Senior Vice President of Energy Future Holdings Corp. From July 2004 to March 2005, Mr. Poole was Senior Vice President of TXU Business Services Company. From May 2004 to July 2004, he was Vice President and Associate General Counsel of TXU Business Services Company. Prior to that time, Mr. Poole was Managing partner of the Dallas office of Hunton & Williams LLP.

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Jonathan A. Siegler is Senior Vice President of Strategy, Mergers and Acquisition of TXU Business Services Company. He has held the position of Vice President of Strategy, Mergers and Acquisition of TXU Business Services Company since August 2004. Prior to that time, Mr. Siegler was Engagement Manager for McKinsey & Company. Prior to that time, he was a Lieutenant in the U.S. Navy.

Executive Compensation

We expect that our Board will consider adopting executive compensation plans that will link compensation with performance. We will continually review our executive compensation programs to ensure that they are competitive.

Employment Agreements

In connection with the Merger, we may enter into new employment agreements and/or amend existing employment agreements with some of Energy Future Holdings Corp.’s existing executive officers on terms to be agreed between us and those persons.

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PRINCIPAL STOCKHOLDERS

As a result of the consummation of the Merger, substantially all of the capital stock of Energy Future Holdings Corp. is held indirectly by the Sponsors and the Investors. The Sponsors own approximately 62% of the partnership interests of Texas Holdings, the direct parent company of Energy Future Holdings Corp. Members of the board of directors of Energy Future Holdings Corp. or managers of Texas Holdings affiliated with each of the Sponsors may be deemed to beneficially own shares owned by such entities or their associated investment funds. Each such individual disclaims beneficial ownership of any such shares in which such individual does not have a pecuniary interest.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Texas Holdings Limited Partnership Agreement

Immediately prior to the closing of the Merger, the Sponsors and the Investors and/or their assignees contributed equity to Texas Holdings in exchange for limited partnership interests in Texas Holdings and entered into a limited partnership agreement with Texas Holdings. Certain third party investors contributed equity to Texas Holdings through intermediate investment vehicles, some of which are controlled by the Sponsors. The limited partnership agreement contains agreements among the parties with respect to restrictions on the issuance or transfer of interests. The Sponsors and certain of the Investors are also party to the limited liability company agreement of the General Partner, which provides, among other things, that the Sponsors control Texas Holdings and have the right to nominate directors to the board of directors of Energy Future Holdings Corp.

Indemnification Agreement

On October 10, 2007, Texas Holdings and Energy Future Holdings Corp. entered into an indemnification agreement with the Sponsors (the “Indemnification Agreement”) to indemnify the Sponsors, their affiliates and related persons from claims against liabilities incurred by the Sponsors, their affiliates and related persons in connection with the Transactions or any future offerings of equity or debt securities by Energy Future Holdings Corp., its subsidiaries or affiliates. Under the Indemnification Agreement the Sponsors, their affiliates and related persons are indemnified against claims for liabilities incurred for actions or omissions relating to the provision of financial advisory, monitoring and management consulting services to the General Partner, Texas Holdings, Energy Future Holdings Corp. and any of their subsidiaries and affiliates. The Indemnification Agreement also indemnifies the directors and officers of each of the General Partner, Texas Holdings, Energy Future Holdings Corp. and any of their subsidiaries and affiliates from claims against liabilities incurred while acting in such capacity.

Registration Rights Agreement

On October 10, 2007, Texas Holdings and Energy Future Holdings Corp. entered into a registration rights agreement with certain shareholders of Energy Future Holdings Corp. pursuant to which such shareholders have certain registration and other rights with respect to shares of common stock they own in Energy Future Holdings Corp.

Sponsor Management Agreement

On October 10, 2007, in connection with the Merger, the Sponsors and LBI entered into a management agreement with Energy Future Holdings Corp. (the “Management Agreement”), pursuant to which affiliates of the Sponsors will provide management, consulting, financial and other advisory services to Energy Future Holdings Corp. Pursuant to the Management Agreement, the Sponsors are entitled to receive an aggregate annual management fee of $35 million, which amount will increase 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of Energy Future Holdings Corp. or in connection with an initial public offering of Energy Future Holdings Corp. or if the parties mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, the Sponsors and LBI are also entitled to receive aggregate transaction fees of $300 million in connection with certain services provided in connection with the Merger and related transactions. In addition, the Management Agreement provides that the Sponsors will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances.

Other Relationships

Over the last fiscal year, there have been no reportable transactions with related persons.

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GLOSSARY

When the following terms and abbreviations appear in this Current Report on Form 8-K, they have the meanings indicated below.

1999 Restructuring Legislation legislation that restructured the electric utility industry in Texas to provide for retail competition

2006 Form 10-K Energy Future Holdings Corp.’s Annual Report on Form 10-K for the year ended December 31, 2006

2006 year-end Financial Statements These audited financial statements include the consolidated balance sheets of Energy Future Holdings Corp. and subsidiaries as of December 31, 2006 and 2005 and the related statements of consolidated income, comprehensive income, cash flows and shareholders’ equity for each of the three years in the period ended December 31, 2006 and the related notes to the financial statements.

APB 25 Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”

Capgemini Capgemini Energy LP, a subsidiary of Cap Gemini North America Inc. that provides business process support services to Energy Future Holdings Corp. and its subsidiaries

Competitive Electric Refers to the Energy Future Holdings Corp. business segment, formerly referred to as TXU Energy Holdings, which included the activities of TCEH.

Energy Future Intermediate Holding Energy Future Intermediate Holding Company LLC, a Delaware limited liability company and subsidiary and Energy Future Holdings Corp.

Energy Future Holdings Corp. Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. This document occasionally makes references to Energy Future Holdings Corp., TCEH or Oncor Electric Delivery when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or of any other affiliate.

EPA U.S. Environmental Protection Agency

EPC engineering, procurement and construction

ERCOT Electric Reliability Council of Texas, the Independent System Operator and the regional coordinator of various electricity systems within Texas

ERISA Employee Retirement Income Security Act

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FASB Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting

FERC U.S. Federal Energy Regulatory Commission

FIN 46R FIN No. 46R (Revised 2003), “Consolidation of Variable Interest Entities”

FIN 47 FIN No. 47, “Accounting for Conditional Asset Retirement Obligations—An Interpretation of FASB Statement No. 143”

FIN 48 FIN No. 48, “Accounting for Uncertainty in Income Taxes”

FSP FASB Staff Position

GAAP generally accepted accounting principles

GW gigawatts

GWh gigawatt-hours

historical service territory the territory, largely in north Texas, being served by TXU Corp.’s regulated electric utility subsidiary at the time of entering retail competition on January 1, 2002

IRS U.S. Internal Revenue Service

June 30, 2007 Financial Statements These unaudited financial statements include the consolidated balance sheet of Energy Future Holdings Corp. and subsidiaries as of June 30, 2007, and the related condensed statements of consolidated income and comprehensive income for the three-month and six-month periods ended June 30, 2007 and 2006, and of cash flows for the six-month periods ended June 30, 2007 and 2006 and the related notes to the financial statements.

kV kilovolts

kWh kilowatt-hours

Luminant Construction or TXU DevCo Refers to wholly owned subsidiaries of Energy Future Holdings Corp. that have been established for the purpose of developing and constructing new generation facilities.

Luminant Energy or TXU Portfolio Management Luminant Energy Company LLC (formerly TXU Portfolio Management Company LP), a subsidiary of TCEH

market heat rate Heat rate is a measure of the efficiency of converting a fuel source to electricity. The market heat rate is based on the price offer of the marginal supplier in Texas (generally natural gas plants) in generating electricity and is calculated by dividing the wholesale market price of electricity by the market price of natural gas.

Merger Agreement Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire Energy Future Holdings Corp.

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Merger Sub Texas Energy Future Merger Sub Corp, a Texas corporation and a wholly-owned subsidiary of Texas Holdings.

MMBtu million British thermal units

Moody’s Moody’s Investors Services, Inc. (a credit rating agency)

MW megawatts

MWh megawatt-hours

NRC U.S. Nuclear Regulatory Commission

Oncor Electric Delivery Refers to Oncor Electric Delivery Company, a subsidiary of Energy Future Holdings Corp., and/or its consolidated bankruptcy remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context. This document occasionally makes references to Energy Future Holdings Corp., TCEH or Oncor Electric Delivery when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of its parents company or of any other affiliate.

PRB Powder River Basin—a coal mining region that covers southeast Montana and northeast Wyoming. Energy Future Holdings Corp. purchases coal from this region from multiple suppliers, which is currently blended with lignite to fuel the Big Brown, Monticello and Martin Lake generating plants.

price-to-beat rate residential and small business customer electricity rates established by the PUCT that (i) were required to be charged in a REP’s historical service territories until the earlier of January 1, 2005 or the date when 40% of the electricity consumed by such customer classes was supplied by competing REPs, adjusted periodically for changes in fuel costs, and (ii) were required to be made available to those customers until January 1, 2007

PUCT or Commission Public Utility Commission of Texas

PURA Texas Public Utility Regulatory Act

REP retail electric provider

S&P Standard & Poor’s Ratings Services, a division of the McGraw Hill Companies Inc. (a credit rating agency)

SEC U.S. Securities and Exchange Commission

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Settlement Plan regulatory settlement plan that received final approval by the PUCT in January 2003

SFAS Statement of Financial Accounting Standards issued by the FASB

SFAS 5 SFAS No. 5, “Contingencies”

SFAS 34 SFAS No. 34, “Capitalization of Interest”

SFAS 71 SFAS No. 71, “Accounting for the Effect of Certain Types of Regulation”

SFAS 87 SFAS No. 87, “Employers’ Accounting for Pensions”

SFAS 106 SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”

SFAS 109 SFAS No. 109, “Accounting for Income Taxes”

SFAS 115 SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities”

SFAS 123R SFAS No. 123 (revised 2004), “Share-Based Payment”

SFAS 133 SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended and interpreted

SFAS 140 SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a replacement of FASB Statement 125”

SFAS 142 SFAS No. 142, “Goodwill and Other Intangible Assets”

SFAS 143 SFAS No. 143, “Accounting for Asset Retirement Obligations”

SFAS 144 SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”

SFAS 146 SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities”

SFAS 157 SFAS No. 157, “Fair Value Measurement”

SFAS 158 SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”

SFAS 159 SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115”

SG&A selling, general and administrative

Short-cut Method refers to the short-cut method under SFAS 133 that allows entities to assume no hedge ineffectiveness in a hedging relationship of interest rate risk if certain conditions are met

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Sponsors The private investment group, consisting of entities advised by or affiliated with KKR, TPG and Goldman Sachs, that directly and indirectly own or will own Texas Holdings and Merger Sub.

TCEQ Texas Commission on Environmental Quality

Texas Competitive Holdings or TCEH Refers to Texas Competitive Electric Holdings Company LLC (formerly TXU Energy Company LLC), a subsidiary of Energy Future Competitive Holdings, and/or its consolidated subsidiaries, depending on context, engaged in electricity generation and wholesale and retail energy markets activities. This document and the SEC filings of Texas Competitive Holdings occasionally make references to Texas Competitive Holdings when describing actions, rights or obligations of its subsidiaries. These references reflect the fact that the subsidiaries are consolidated with Texas Competitive Holdings for financial reporting purposes. However, these references should not be interpreted to imply that Texas Competitive Holdings is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of Texas Competitive Holdings or of any other affiliate.

Texas Holdings or Merger Sub Parent Texas Energy Future Holdings Limited Partnership, a Delaware limited partnership.

TXU Australia Refers to TXU Australia Group Pty Ltd, a former subsidiary of Energy Future Holdings Corp., and its subsidiaries

TXU Big Brown Big Brown Power Company LLC (formerly TXU Big Brown Company LP), a Texas limited liability company and subsidiary of TCEH, which owns two lignite/coal-fueled generation units in Texas

TXU Energy or TXU Energy Retail Refers to TXU Energy Retail Company LLC (formerly TXU Energy Retail Company LP), a subsidiary of TCEH engaged in the retail sale of power to residential and business customers

TXU Europe TXU Europe Limited, a former subsidiary of Energy Future Holdings Corp.

TXU Fuel TXU Fuel Company, a former subsidiary of TCEH

TXU Gas TXU Gas Company, a former subsidiary of Energy Future Holdings Corp.

United States or US United States of America

US Holdings or Energy Future Competitive Holdings Energy Future Competitive Holdings Company (formerly TXU US Holdings Company), a subsidiary of Energy Future Holdings Corp.

VEBA Refers to voluntary employees’ beneficiary association

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

ENERGY FUTURE HOLDINGS CORP.

Unaudited Financial Statements for the Quarterly Period Ended June 30, 2007
Report of Independent Registered Public Accounting Firm	F-2
Condensed Statements of Consolidated Income—Three and Six Months Ended June 30, 2007 and 2006	F-3
Condensed Statements of Consolidated Comprehensive Income—Three and Six Months Ended June 30, 2007 and 2006	F-4
Condensed Statements of Consolidated Cash Flows—Six Months Ended June 30, 2007 and 2006	F-5
Condensed Consolidated Balance Sheets—June 30, 2007 and December 31, 2006	F-7
Notes to Condensed Consolidated Financial Statements	F-8
Audited Financial Statements for the Fiscal Year Ended December 31, 2006
Report of Independent Registered Public Accounting Firm	F-53
Statements of Consolidated Income for each of the three years in the period ended December 31, 2006	F-54
Statements of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 2006	F-55
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2006	F-56
Consolidated Balance sheets, December 31, 2006 and 2005	F-58
Statements of Consolidated Shareholders’ Equity for each of the three years in the period ended December 31, 2006	F-59
Notes to Financial Statements	F-61

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Energy Future Holdings Corp.:

We have reviewed the accompanying condensed consolidated balance sheet of Energy Future Holdings Corp. (formerly known as TXU Corp.) and subsidiaries (“the Company”) as of June 30, 2007, and the related condensed statements of consolidated income and comprehensive income for the three-month and six-month periods ended June 30, 2007 and 2006, and of cash flows for the six-month periods ended June 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Energy Future Holdings Corp. and subsidiaries as of December 31, 2006, and the related statements of consolidated income, comprehensive income, cash flows, and shareholders’ equity for the year then ended (not presented herein); and in our report dated March 1, 2007 (October 16, 2007 as to Note 26), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2006 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Dallas, Texas

August 9, 2007

(October 16, 2007 as to Notes 16 and 17)

F-2

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(millions of dollars, except per share amounts)
Operating revenues	$	2,022		$	2,667		$	3,691		$	4,971
Costs and expenses:
Fuel, purchased power costs and delivery fees		739			658			1,404			1,179
Operating costs		368			341			714			684
Depreciation and amortization		200			207			403			413
Selling, general and administrative expenses		227			181			447			370
Franchise and revenue-based taxes		89			87			176			174
Other income (Note 6)		(16	)		(42	)		(45	)		(55	)
Other deductions (Note 6)		122			221			891			221
Interest income		(17	)		(11	)		(35	)		(20	)
Interest expense and related charges (Note 15)		221			218			418			431
Total costs and expenses		1,933			1,860			4,373			3,397
Income (loss) from continuing operations before income taxes		89			807			(682	)		1,574
Income tax expense (benefit)		(21	)		310			(294	)		561
Income (loss) from continuing operations		110			497			(388	)		1,013
Income from discontinued operations, net of tax effect		11			—			11			60
Net income (loss)	$	121		$	497		$	(377	)	$	1,073
Average shares of common stock outstanding (millions):
Basic		459			458			458			461
Diluted		464			465			458			470
Per share of common stock—Basic:
Net income (loss) from continuing operations	$	0.24		$	1.08		$	(0.85	)	$	2.20
Income from discontinued operations, net of tax effect		0.02			—			0.03			0.13
Net income (loss)	$	0.26		$	1.08		$	(0.82	)	$	2.33
Per share of common stock—Diluted:
Net income (loss) from continuing operations	$	0.24		$	1.07		$	(0.85	)	$	2.16
Income from discontinued operations, net of tax effect		0.02			—			0.03			0.13
Net income (loss)	$	0.26		$	1.07		$	(0.82	)	$	2.29
Dividends declared	$	0.433		$	0.413		$	0.865		$	0.826

See Notes to Financial Statements.

F-3

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(millions of dollars)
Components related to continuing operations:
Income (loss) from continuing operations	$	110		$	497		$	(388	)	$	1,013
Other comprehensive income (loss):
Reclassification of pension and other retirement benefit costs (net of tax expense of $—, —, $3 and —) (Note 13)		1			—			5			—
Cash flow hedges:
Net increase (decrease) in fair value of derivatives held at end of period (net of tax (expense) benefit of $(19), $44, $151 and $(16))		35			(83	)		(281	)		30
Derivative value net (gains) losses related to hedged transactions settled during the period and reported in net income (net of tax (expense) benefit of $(9), $6, $(49) and $6)		(17	)		12			(91	)		11
Total effect of cash flow hedges		18			(71	)		(372	)		41
Total adjustments to net income (loss) from continuing operations		19			(71	)		(367	)		41
Comprehensive income (loss) from continuing operations		129			426			(755	)		1,054
Comprehensive income from discontinued operations		11			—			11			60
Comprehensive income (loss)	$	140		$	426		$	(744	)	$	1,114

See Notes to Financial Statements.

F-4

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2007			2006
	(millions of dollars)
Cash flows—operating activities:
Net income (loss)	$	(377	)	$	1,073
Income from discontinued operations, net of tax effect		(11	)		(60	)
Income (loss) from continuing operations		(388	)		1,013
Adjustments to reconcile income (loss) from continuing operations to cash provided by (used in) operating activities:
Depreciation and amortization		433			444
Deferred income tax expense (benefit)—net		(613	)		319
Impairment of natural gas-fueled generation plants		—			198
Inventory write-off related to natural gas-fueled generation plants		—			3
Charges related to suspended development of generation facilities (Note 2)		716			—
Write-off of deferred transaction costs (Note 6)		38			—
Net gains on sale of assets		(27	)		(24	)
Net effect of unrealized mark-to-market valuations—losses (gains)		1,182			(29	)
Gain on contract settlement		—			(26	)
Bad debt expense		25			30
Stock-based incentive compensation expense		15			9
Other, net		19			16
Changes in operating assets and liabilities		(1,455	)		(49	)
Cash provided by (used in) operating activities from continuing operations		(55	)		1,904
Cash flows—financing activities:
Issuances of securities:
Long-term debt		1,800			100
Common stock		1			180
Retirements/repurchases of securities:
Equity-linked debt		—			(179	)
Pollution control revenue bonds		(143	)		(203	)
Other long-term debt		(68	)		(1,143	)
Common stock		(10	)		(809	)
Change in short-term borrowings:
Commercial paper		(1,296	)		905
Bank borrowings		2,155			800
Common stock dividends paid		(397	)		(384	)
Settlements of minimum withholding tax liabilities under stock-based compensation plans		(93	)		(56	)
Debt premium, discount, financing and reacquisition expenses—net		(15	)		(17	)
Cash provided by (used in) financing activities from continuing operations		1,934			(806	)
Cash flows—investing activities:
Capital expenditures		(1,611	)		(825	)
Nuclear fuel		(30	)		(30	)
Proceeds from sale of assets		4			—
Purchase of lease trust		—			(69	)

F-5

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (cont.)

(Unaudited)

	Six Months Ended June 30,
	2007			2006
	(millions of dollars)
Reduction of restricted cash related to the redemption of pollution control revenue bonds		143			—
Proceeds from sales of nuclear decommissioning trust fund securities		104			144
Investments in nuclear decommissioning trust fund securities		(111	)		(151	)
Proceeds from pollution control revenue bonds deposited with trustee		—			(99	)
Cost to remove retired property		(16	)		(22	)
Investment in unconsolidated affiliate		—			(15	)
Other		11			5
Cash used in investing activities from continuing operations		(1,506	)		(1,062	)
Discontinued operations:
Cash provided by (used in) operating activities		24			(1	)
Cash used in financing activities		—			—
Cash used in investing activities		—			—
Cash provided by (used in) discontinued operations		24			(1	)
Net change in cash and cash equivalents		397			35
Cash and cash equivalents—beginning balance		25			37
Cash and cash equivalents—ending balance	$	422		$	72

See Notes to Financial Statements.

F-6

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2007			December 31, 2006
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	422		$	25
Restricted cash		54			58
Trade accounts receivable—net (Note 7)		1,016			959
Inventories		428			383
Commodity and other derivative contractual assets (Note 12)		299			950
Accumulated deferred income taxes (Note 3)		829			253
Margin deposits related to commodity positions		448			7
Other current assets		189			177
Total current assets		3,685			2,812
Restricted cash		119			258
Investments		742			712
Property, plant and equipment—net		19,387			18,756
Goodwill		542			542
Regulatory assets—net		1,935			2,028
Commodity and other derivative contractual assets (Note 12)		216			345
Other noncurrent assets		362			380
Total assets	$	26,988		$	25,833
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings (Note 8)	$	2,350		$	1,491
Long-term debt due currently (Note 9)		792			485
Trade accounts payable		1,014			1,093
Commodity and other derivative contractual liabilities (Note 12)		429			293
Margin deposits related to commodity positions		35			681
Other current liabilities		993			1,040
Total current liabilities		5,613			5,083
Accumulated deferred income taxes (Note 3)		3,121			4,238
Investment tax credits		353			363
Commodity and other derivative contractual liabilities (Note 12)		876			191
Long-term debt, less amounts due currently (Note 9)		11,917			10,631
Other noncurrent liabilities and deferred credits		4,063			3,187
Total liabilities		25,943			23,693
Commitments and Contingencies (Note 10)
Shareholders’ equity (Note 11):
Common stock without par value: Authorized shares: 1,000,000,000
Outstanding shares: 461,196,630 and 459,244,523		5			5
Additional paid-in capital		1,115			1,104
Retained earnings (deficit)		(117	)		622
Accumulated other comprehensive income		42			409
Total shareholders’ equity		1,045			2,140
Total liabilities and shareholders’ equity	$	26,988		$	25,833

See Notes to Financial Statements.

F-7

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. SIGNIFICANT ACCOUNTING POLICIES AND BUSINESS

Description of Business—Energy Future Holdings Corp. (formerly named TXU Corp.) is a holding company conducting its operations principally through its Texas Competitive Holdings, Oncor Electric Delivery and TXU DevCo subsidiaries and their subsidiaries. Each of these subsidiaries is a separate legal entity with its own assets and liabilities. Texas Competitive Holdings is a holding company whose subsidiaries are engaged in competitive market activities consisting of electricity generation, retail electricity sales to residential and business customers, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. Oncor Electric Delivery is engaged in regulated electricity transmission and distribution operations in Texas. TXU DevCo and its subsidiaries are engaged in the development of new generation facilities in Texas.

On February 25, 2007, Energy Future Holdings Corp. entered into a Merger Agreement under which an investor group led by Kohlberg Kravis Roberts & Co. and Texas Pacific Group (Sponsors) is expected to acquire Energy Future Holdings Corp. if the relevant conditions to closing are satisfied (Proposed Merger).

Energy Future Holdings Corp. has two reportable segments: the Competitive Electric segment (formerly the TXU Energy Holdings segment), which includes the activities of Texas Competitive Holdings, TXU DevCo and a lease trust holding certain combustion turbines, and the Regulated Delivery segment (formerly the Oncor Electric Delivery segment), which includes the activities of Oncor Electric Delivery, its wholly owned bankruptcy-remote financing subsidiary and certain revenues and costs associated with broadband-over-powerlines equipment installation. (See Note 14 for further information concerning reportable business segments.)

Basis of Presentation—The condensed consolidated financial statements of Energy Future Holdings Corp. have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in its 2006 Form 10-K with the exception of the adoption of FIN 48. All adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in the 2006 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

Prior period commodity contract assets and liabilities and cash flow hedge and other derivative assets and liabilities have been combined to conform with the current period presentation (see Note 12).

Discontinued Businesses—Income from discontinued operations in the six months ended June 30, 2007 consisted primarily of insurance settlements related to TXU Europe litigation. Income from discontinued operations in the six months ended June 30, 2006 consisted primarily of a reversal of a TXU Gas income tax reserve due to a favorable resolution of an IRS audit matter. The TXU Gas business was disposed of in October 2004.

Use of Estimates—Preparation of Energy Future Holdings Corp.’s financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including mark-to-market valuations. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are

F-8

made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.

Earnings Per Share—Basic earnings per share available to common shareholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share include the effect of all potential issuances of common shares under stock-based employee compensation and certain debt arrangements. See Note 5 for a reconciliation of basic earnings per share to diluted earnings per share.

Changes in Accounting Standards—Effective January 1, 2007, Energy Future Holdings Corp. adopted FIN 48 as required. FIN 48 provides clarification of SFAS 109 with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. See Note 3 for the impacts of adopting FIN 48 and required disclosures.

In April 2007, the FASB issued FASB Staff Position FIN 39-1, “Amendment of FASB Interpretation No. 39”. This FSP provides additional guidance regarding the offsetting in the balance sheet of cash collateral and contractual fair value amounts and related disclosures. This FSP is effective for fiscal years beginning after November 15, 2007. Energy Future Holdings Corp. is evaluating the impact of this standard on its balance sheet.

2. CHARGES RELATED TO SUSPENDED DEVELOPMENT OF COAL-FUELED GENERATION FACILITIES

In the first quarter of 2007, Energy Future Holdings Corp. recorded a charge totaling $713 million ($463 million after-tax) in connection with the February 2007 suspension by TXU DevCo of the development of eight coal-fueled generation units. This decision and subsequent terminations of equipment orders required an evaluation of the recoverability of recorded assets associated with the development program. The charge included $673 million for the impairment of construction work-in-process asset balances (primarily pre-construction development costs), $11 million for costs arising from terminations of equipment orders and $29 million for the write-off of deferred financing costs. In determining the charge to be recorded, Energy Future Holdings Corp. applied accounting rules for impairment of long-lived assets under SFAS 144 and for exit activities under SFAS 146.

The construction work-in-process asset balances totaled $871 million at March 31, 2007 prior to the writedown and included progress payments made and accruals for amounts due to equipment suppliers, based on percentage of completion estimates, engineering and design services costs, site preparation expenditures, internal salary and related overhead costs for personnel engaged directly in construction management activities and capitalized interest. The construction work-in-process balance subsequent to the writedown totaled $198 million at March 31, 2007 and consisted of $159 million in estimated recovery amounts, using a probability-weighted methodology, from equipment salvage and potential resale activities, and $39 million in equipment projects at existing generation plant sites related to the development program that are expected to have future value. The charge recorded was based on management’s judgments and estimates. The ultimate loss to be realized related to the construction work-in-process assets may differ materially from the estimate recorded in the first quarter of 2007 as amounts due to suppliers for actual work completed are resolved and salvage and resale actions are finalized.

In the second quarter of 2007, Energy Future Holdings Corp. recorded an additional charge totaling $82 million ($54 million after-tax), which consisted almost entirely of the previously disclosed $79 million pretax charge arising from the negotiated termination of certain equipment orders in April 2007. With this agreement, TXU DevCo has now terminated essentially all of the equipment orders, with the exception of certain in-process boilers that may be resold, but remains subject to potential additional termination liabilities as discussed below.

These charges have been classified in other deductions and are reported in the results of the Competitive Electric segment.

F-9

In addition to the termination costs recognized to date, TXU DevCo is exposed to potential liabilities of up to approximately $150 million for termination and suspension costs under the equipment order and construction agreements. Because the amounts ultimately payable to suppliers cannot be reasonably estimated at this time (and may be subject to dispute), no accruals have been established for these contingent liabilities. Additional charges for termination liabilities are expected to be recorded as uncertainties regarding suppliers’ costs incurred as a result of the terminations are resolved.

The construction work-in-process balances increased $46 million in the second quarter of 2007 to $244 million. The increase primarily represents additional previously anticipated fabrication costs for the boilers referred to above, the incurrence of which does not result in an increase in estimated impairment.

3. ADOPTION OF NEW INCOME TAX ACCOUNTING RULES (FIN 48)

FIN 48 requires that each tax position be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable. Energy Future Holdings Corp. has completed its review and assessment of uncertain tax positions and in the quarter ended March 31, 2007 recorded a net benefit to retained earnings and a decrease to noncurrent liabilities of $33 million in accordance with the new accounting rule.

Energy Future Holdings Corp. and its subsidiaries file income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of income tax returns filed by Energy Future Holdings Corp. and any of its subsidiaries for the years ending prior to January 1, 1997, with few exceptions, are complete. Texas franchise tax returns for the years 2002 to 2006 have not been examined.

As expected, the IRS has completed examining Energy Future Holdings Corp.’s US income tax returns for the years 1997 through 2002, and proposed adjustments were received in July 2007. Energy Future Holdings Corp. plans to appeal the proposed adjustments in the third quarter of 2007. The proposed adjustments received from the IRS with respect to the 1997-2002 income tax returns do not materially affect Energy Future Holdings Corp.’s assessment of uncertain tax positions as reflected in the amounts recorded upon adoption of FIN 48.

The total amount of benefits taken on income tax returns that do not qualify for financial statement recognition under FIN 48 total $1.7 billion as of June 30, 2007, the substantial majority of which represents amounts that have been accounted for as noncurrent liabilities instead of deferred income tax liabilities; of this amount, $28 million would increase earnings if recognized (net of an estimated $12 million decrease related to discontinued operations), and $54 million would be recorded as an adjustment to additional paid-in capital if recognized. The balance sheet at June 30, 2007 reflects a reclassification of $893 million from accumulated deferred income tax liabilities to other noncurrent liabilities recorded in the first quarter of 2007.

Energy Future Holdings Corp. classifies interest and penalties related to unrecognized tax benefits as income tax expense. As of June 30, 2007, noncurrent liabilities included a total of $79 million in accrued interest. The amount of interest included in income tax expense for the three and six months ended June 30, 2007 totaled $15 million and $29 million after-tax, respectively.

Energy Future Holdings Corp. does not expect that the total amount of unrecognized tax benefits for the positions assessed as of the date of the adoption will significantly increase or decrease within the next 12 months.

4. TEXAS MARGIN TAX

In May 2006, the Texas legislature enacted a new law that reformed the Texas franchise tax system and replaced it with a new tax system, referred to as the Texas margin tax. The Texas margin tax has been determined to be an income tax for accounting purposes. In accordance with the provisions of SFAS 109, which require that deferred tax assets and liabilities be adjusted for the effects of new income tax legislation in the period of enactment, Energy Future Holdings Corp. estimated and recorded a deferred tax expense of $41 million in the second quarter of 2006.

F-10

In June 2007, an amendment to this law was enacted that included clarifications and technical changes to the provisions of the tax calculation. In the second quarter of 2007, Energy Future Holdings Corp. recorded a deferred tax benefit of $51 million, essentially all of which related to changes in the rate at which a tax credit is calculated as specified in the new law. This estimated benefit is based on the Texas margin tax law in its current form and the current guidance issued by the Texas Comptroller of Public Accounts.

The effective date of the Texas margin tax for Energy Future Holdings Corp. is January 1, 2008. The computation of tax liability will be based on 2007 revenues as reduced by certain deductions and is being accrued in the current year.

Of the total 2007 deferred tax benefit, $30 million was recognized in the Competitive Electric segment results and $21 million was recognized in the Corporate and Other nonsegment results. Of the total 2006 deferred tax charge, $42 million was recognized as a deferred tax charge in the Competitive Electric segment results and $1 million was recognized as a deferred tax benefit in the Corporate and Other nonsegment results.

5. EARNINGS PER SHARE

Basic earnings per share available to common shareholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share include the effect of all potential issuances of common shares under stock-based incentive compensation and certain debt arrangements.

	For the Three Months Ended June 30, 2007								For the Three Months Ended June 30, 2006
	Income (Loss)			Shares		Per Share Amount			Income		Shares	Per Share Amount
Income (loss) from continuing operations—Basic	$	110		458.8		$	.24		$	497	458.0	$	1.08
Dilutive securities/other adjustments:
Convertible senior notes		—		1.5						—	1.5
Equity-linked debt securities		—		—						—	1.0
Stock-based incentive compensation plan		—		3.4						—	5.0
Income (loss) from continuing operations—Diluted	$	110		463.7		$	.24		$	497	465.5	$	1.07
	For the Six Months Ended June 30, 2007								For the Six Months Ended June 30, 2006
	Income (Loss)			Shares		Per Share Amount			Income		Shares	Per Share Amount
Income (loss) from continuing operations—Basic	$	(388	)	458.2		$	(.85	)	$	1,013	461.0	$	2.20
Dilutive securities/other adjustments:
Convertible senior notes		—		1.5						1	1.5
Equity-linked debt securities		—		—						—	1.6
Stock-based incentive compensation plan		—		4.4						—	5.6
Income (loss) from continuing operations—Diluted	$	(388	)	458.2	(a)	$	(.85	)(a)	$	1,014	469.7	$	2.16

(a) Diluted results per share equal basic results per share because of the loss position and antidilution accounting rules.

F-11

6. OTHER INCOME AND DEDUCTIONS

	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2006		2007		2006
Other income:
Gain on contract settlement(a)	$	—	$	26	$	—	$	26
Amortization of gain on sale of TXU Fuel		11		11		23		23
Net gain on sale of other properties		—		1		4		1
Reduction of insurance reserves unrelated to ongoing operations		2		—		7		—
Settlement penalty for coal tonnage delivery deficiency		—		—		3		—
Royalty income from lignite and natural gas leases		2		—		5		—
Other		1		4		3		5
Total other income	$	16	$	42	$	45	$	55
Other deductions:
Charges related to suspended development of generation facilities (Note 2)	$	82	$	—	$	795	$	—
Writeoff of deferred transaction costs(b)		—		—		30		—
Transaction costs related to Proposed Merger		6		—		20		—
Expenses related to InfrastruX Energy Services joint venture(c)		11		—		12		—
Charge for impairment of natural gas-fueled generation plants		—		198		—		198
Inventory write-off related to natural gas-fueled generation plants		—		3		—		3
Credit related to coal contract counterparty claim(d)		—		—		—		(12	)
Costs related to 2006 cities rate settlement		7		—		13		—
Charge for settlement of retail matter with the Commission		5		—		5		—
Pension and other postretirement benefit costs related to discontinued businesses		6		5		9		10
Equity losses—unconsolidated affiliates		—		7		1		7
Other		5		8		6		15
Total other deductions	$	122	$	221	$	891	$	221

(a) In the second quarter of 2006, Energy Future Holdings Corp. recorded income of $26 million upon the settlement of a contract dispute related to antenna site rentals by a telecommunications company. (Reported in Corporate and Other nonsegment results.)

(b) Represents previously deferred costs, consisting primarily of professional fees for tax, legal and other advisory services, in connection with certain previously anticipated strategic transactions (including expected financings) that are no longer expected to be consummated as a result of the Merger Agreement. (Reported in Corporate and Other nonsegment results.)

(c) Consists of previously deferred costs, consisting primarily of professional fees that were written-off due to suspension of the agreement. Of these amounts, $8 million was reported in the Corporate and Other nonsegment results and the balance was reported in the Regulated Delivery segment results.

(d) In the first quarter of 2006, Energy Future Holdings Corp. recorded income of $12 million upon the settlement of a claim against a counterparty for nonperformance under a coal contract. A charge in the same amount was recorded in the first quarter of 2005 for losses due to the nonperformance. (Reported in the Competitive Electric segment results.)

F-12

7. TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Sale of Receivables—Subsidiaries of Energy Future Holdings Corp. participate in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, subsidiaries of Energy Future Holdings Corp. (originators) sell trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of Energy Future Holdings Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities). The current program is subject to renewal in June 2008.

The maximum amount currently available under the program is $700 million, and the program funding was $527 million as of June 30, 2007. Under certain circumstances, the amount of customer deposits held by the originators can reduce the amount of undivided interests that can be sold, thus reducing funding available under the program. Funding availability for all originators is reduced by 100% of the originators’ customer deposits if Texas Competitive Holdings’ fixed charge coverage ratio is less than 2.5 times; 50% if Texas Competitive Holdings’ coverage ratio is less than 3.25 times, but at least 2.5 times; and zero % if Texas Competitive Holdings’ coverage ratio is 3.25 times or more. The originators’ customer deposits, which totaled $119 million, did not affect funding availability at that date as Texas Competitive Holdings’ coverage ratio was in excess of 3.25 times.

All new trade receivables under the program generated by the originators are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflect seasonal variations in the level of accounts receivable, changes in collection trends as well as other factors such as changes in sales prices and volumes. TXU Receivables Company has issued subordinated notes payable to the originators for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originators that was funded by the sale of the undivided interests. The balance of the subordinated notes payable, which is eliminated in consolidation, totaled $350 million and $211 million at June 30, 2007 and December 31, 2006, respectively.

The discount from face amount on the purchase of receivables principally funds program fees paid by TXU Receivables Company to the funding entities. The discount also funds a servicing fee paid by TXU Receivables Company to TXU Business Services Company, a direct subsidiary of Energy Future Holdings Corp. The program fees, also referred to as losses on sale of the receivables under SFAS 140, consist primarily of interest costs on the underlying financing and totaled $20 million and $18 million for the six month periods ending June 30, 2007 and 2006, respectively, and averaged 6.4% and 5.4% (on an annualized basis) of the funding under the program for the first six months of 2007 and 2006, respectively. The servicing fee, which totaled approximately $2 million for the first six months of both 2007 and 2006, compensates TXU Business Services Company for its services as collection agent, including maintaining the detailed accounts receivable collection records. The program fees represent essentially all the net incremental costs of the program on a consolidated basis and are reported in SG&A expenses.

The accounts receivable balance reported in the June 30, 2007 consolidated balance sheet includes $877 million face amount of trade accounts receivable of Texas Competitive Holdings and Oncor Electric Delivery sold to TXU Receivables Company, such amount having been reduced by $527 million of undivided interests sold by TXU Receivables Company. Funding under the program decreased $100 million for the six month period ending June 30, 2007 and increased $29 million for the six month period ending June 30, 2006. Funding increases or decreases under the program are reflected as operating cash flow activity in the statement of cash flows. The carrying amount of the retained interests in the accounts receivable balance approximated fair value due to the short-term nature of the collection period.

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Activities of TXU Receivables Company were as follows:

	Six Months Ended June 30,
	2007			2006
Cash collections on accounts receivable	$	3,964		$	3,705
Face amount of new receivables purchased		(4,003	)		(3,763	)
Discount from face amount of purchased receivables		22			20
Program fees paid		(20	)		(18	)
Servicing fees paid		(2	)		(2	)
Increase in subordinated notes payable		139			29
Operating cash flows used by (provided to) Energy Future Holdings Corp. under the program	$	100		$	(29	)

Upon termination of the program, cash flows would be delayed as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests from the funding entities instead of purchasing new receivables. The level of cash flows would normalize in approximately 16 to 30 days.

Contingencies Related to Sale of Receivables Program—Although TXU Receivables Company expects to be able to pay its subordinated notes from the collections of purchased receivables, these notes are subordinated to the undivided interests of the financial institutions in those receivables, and collections might not be sufficient to pay the subordinated notes. The program may be terminated if either of the following events occurs:

1) all of the originators cease to maintain their required fixed charge coverage ratio and debt to capital (leverage) ratio; or

2) the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds and the financial institutions do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables, not separately to the receivables of each originator.

Trade Accounts Receivable—

	June 30, 2007			December 31, 2006
Gross trade accounts receivable	$	1,557		$	1,599
Undivided interests in accounts receivable sold by TXU Receivables Company		(527	)		(627	)
Allowance for uncollectible accounts related to undivided interests in receivables retained		(14	)		(13	)
Trade accounts receivable—reported in balance sheet	$	1,016		$	959

Gross trade accounts receivable at June 30, 2007 and December 31, 2006 included unbilled revenues of $528 million and $466 million, respectively.

F-14

Allowance for Uncollectible Accounts Receivable—

	2007			2006
Allowance for uncollectible accounts receivable as of January 1	$	13		$	36
Increase for bad debt expense		25			30
Decrease for account write-offs		(33	)		(41	)
Changes related to receivables sold		9			13
Other(a)		—			(15	)
Allowance for uncollectible accounts receivable as of June 30	$	14		$	23

(a) Represents an allowance established in 2005 for a coal contract dispute that was reversed upon settlement in 2006. See Note 6.

Allowances related to undivided interests in receivables sold are reported in current liabilities and totaled $17 million and $26 million at June 30, 2007 and December 31, 2006, respectively.

8. SHORT-TERM FINANCING

Short-term Borrowings—At June 30, 2007 and December 31, 2006, the outstanding short-term borrowings of Energy Future Holdings Corp. and its subsidiaries consisted of the following:

	At June 30, 2007				At December 31, 2006
	Outstanding Amount		Interest Rate(a)		Outstanding Amount		Interest Rate(a)
Bank borrowings	$	2,350	6.19	%	$	195	5.97	%
Commercial paper		—	—			1,296	5.53	%
Total	$	2,350			$	1,491

(a) Weighted average interest rate at the end of the period.

Under the commercial paper programs, Texas Competitive Holdings and Oncor Electric Delivery may issue up to $2.4 billion and $1.0 billion of commercial paper, respectively. At June 30, 2007, Texas Competitive Holdings and Oncor Electric Delivery had no commercial paper outstanding. These programs are effectively supported by existing credit facilities although there is no contractual obligation under the programs to maintain equivalent availability under existing credit facilities. During 2007, the commercial paper borrowings have been largely refinanced through borrowings against existing credit facilities.

Credit Facilities—At June 30, 2007, subsidiaries of Energy Future Holdings Corp. had access to credit facilities with the following terms:

Authorized Borrowers	Maturity Date	At June 30, 2007
		Facility Limit		Letters of Credit		Cash Borrowings		Availability
Texas Competitive Holdings	February 2008	$	1,500	$	—	$	—	$	1,500
Texas Competitive Holdings, Oncor Electric Delivery	June 2008		1,400		512		765		123
Texas Competitive Holdings, Oncor Electric Delivery	August 2008		1,000		—		495		505
Texas Competitive Holdings, Oncor Electric Delivery	March 2010		1,600		248		815		537
Texas Competitive Holdings, Oncor Electric Delivery	June 2010		500		5		230		265
Texas Competitive Holdings	December 2009		500		455		45		—
Total		$	6,500	$	1,220	$	2,350	$	2,930

F-15

The maximum amount Texas Competitive Holdings and Oncor Electric Delivery can directly access under the facilities is $6.5 billion and $3.6 billion, respectively. These facilities may be used for working capital and general corporate purposes, including providing support for issuances of commercial paper and for issuing letters of credit. Availability under these facilities as of June 30, 2007 declined $2.4 billion from December 31, 2006.

On March 1, 2007, a $1.5 billion Texas Competitive Holdings facility maturing in May 2007 was terminated and replaced with a new 364-day facility with terms comparable to the existing facilities. The new credit facility may only be drawn upon if the $1.0 billion credit facility maturing in August 2008 is fully drawn. The facility matures in February 2008 but will terminate earlier on any date Texas Competitive Holdings issues any debt (excluding pollution control revenue bonds and commercial paper) or preferred equity securities or enters into any credit facilities.

All letters of credit under the credit facilities as of June 30, 2007 are the obligations of Texas Competitive Holdings. At June 30, 2007, Texas Competitive Holdings and Oncor Electric Delivery had $2.195 billion and $155 million in outstanding cash borrowings, respectively.

Pursuant to Commission rules, availability under the credit facilities is further reduced by $125 million to provide liquidity to permit TXU Energy Retail to return retail customer deposits, if necessary.

9. LONG-TERM DEBT

Long-term debt—At June 30, 2007 and December 31, 2006, the long-term debt of Energy Future Holdings Corp. consisted of the following:

	June 30, 2007		December 31, 2006
Texas Competitive Holdings
Pollution Control Revenue Bonds:
Brazos River Authority:
5.400% Fixed Series 1994A due May 1, 2029	$	39	$	39
7.700% Fixed Series 1999A due April 1, 2033		111		111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013(a)		16		16
7.700% Fixed Series 1999C due March 1, 2032		50		50
3.830% Floating Series 2001A due October 1, 2030(b)		71		71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011(a)		217		217
3.780% Floating Series 2001D due May 1, 2033(b)		268		268
5.380% Floating Taxable Series 2001I due December 1, 2036(b)		62		62
3.830% Floating Series 2002A due May 1, 2037(b)		45		45
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)		44		44
6.300% Fixed Series 2003B due July 1, 2032		39		39
6.750% Fixed Series 2003C due October 1, 2038		52		52
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014(a)		31		31
5.000% Fixed Series 2006 due March 1, 2041		100		100
Sabine River Authority of Texas:
6.450% Fixed Series 2000A due June 1, 2021		51		51
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011(a)		91		91
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011(a)		107		107

F-16

	June 30, 2007			December 31, 2006
5.200% Fixed Series 2001C due May 1, 2028		70			70
5.800% Fixed Series 2003A due July 1, 2022		12			12
6.150% Fixed Series 2003B due August 1, 2022		45			45
3.850% Floating Series 2006A due November 1, 2041 (interest rate in effect at March 31, 2007)(c)		—			47
3.850% Floating Series 2006B due November 1, 2041, (interest rate in effect at March 31, 2007)(c)		—			46
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028		14			14
3.850% Floating Series 2006 due November 1, 2041, (interest rate in effect at March 31, 2007)(c)		—			50
Other:
6.125% Fixed Senior Notes due March 15, 2008(d)		250			250
7.000% Fixed Senior Notes due March 15, 2013		1,000			1,000
5.860% Floating Senior Notes due September 16, 2008(e)		1,000			—
Capital lease obligations		92			98
Fair value adjustments related to interest rate swaps		11			10
Total Texas Competitive Holdings	$	3,888		$	3,036
Oncor Electric Delivery
6.375% Fixed Senior Notes due May 1, 2012	$	700		$	700
7.000% Fixed Senior Notes due May 1, 2032		500			500
6.375% Fixed Senior Notes due January 15, 2015		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
5.000% Fixed Debentures due September 1, 2007(d)		200			200
7.000% Fixed Debentures due September 1, 2022		800			800
5.735% Floating Senior Notes due September 16, 2008(e)		800			—
Unamortized discount		(16	)		(16	)
Total Oncor Electric Delivery		3,834			3,034
Oncor Electric Delivery Transition Bond Company LLC(f)
2.260% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2007		—			8
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		109			122
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		130			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		145			145
3.520% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2009		131			158
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		221			221
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		290			290
Total Oncor Electric Delivery Transition Bond Company LLC		1,026			1,074
Total Oncor Electric Delivery Consolidated		4,860			4,108
Energy Future Competitive Holdings Company
7.170% Fixed Senior Debentures due August 1, 2007		10			10
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		78			85
9.580% Fixed Notes due in semiannual installments through December 4, 2019		62			62
8.254% Fixed Notes due in quarterly installments through December 31, 2021		58			59

F-17

	June 30, 2007			December 31, 2006
6.156% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037(g)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized premium		4			5
Total Energy Future Competitive Holdings Company		221			230
Energy Future Holdings Corp.
6.375% Fixed Senior Notes Series C due January 1, 2008(d)		200			200
4.800% Fixed Senior Notes Series O due November 15, 2009		1,000			1,000
5.550% Fixed Senior Notes Series P due November 15, 2014		1,000			1,000
6.500% Fixed Senior Notes Series Q due November 15, 2024		750			750
6.550% Fixed Senior Notes Series R due November 15, 2034		750			750
8.820% Building Financing due semiannually through February 11, 2022(h)		93			99
6.856% Floating Convertible Senior Notes due July 15, 2033(g)		25			25
Fair value adjustments related to interest rate swaps		(70	)		(73	)
Unamortized discount		(8	)		(9	)
Total Energy Future Holdings Corp.		3,740			3,742
Total Energy Future Holdings Corp. consolidated		12,709			11,116
Less amount due currently		(792	)		(485	)
Total long-term debt	$	11,917		$	10,631

(a) These series are in the multiannual interest rate 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.

(b) Interest rates in effect at June 30, 2007. These series are in a weekly interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(c) These series were redeemed on May 8, 2007 as a result of the suspension of development of eight coal-fueled generation facilities.

(d) Interest rates swapped to variable on entire principal amount at June 30, 2007.

(e) Interest rates in effect at June 30, 2007. These series are subject to mandatory redemption upon a change in control of Energy Future Holdings Corp., including the Proposed Merger and are subject to optional redemption on or after September 16, 2007.

(f) These bonds are nonrecourse to Oncor Electric Delivery and were issued to securitize a regulatory asset.

(g) Interest rates in effect at June 30, 2007.

(h) Energy Future Holdings Corp. and Texas Competitive Holdings replaced their guarantees of this financing with a $144 million letter of credit in June 2007.

Debt-related Activity in 2007—In May 2007, Texas Competitive Holdings redeemed at par the Sabine River Authority of Texas Series 2006A and 2006B pollution control revenue bonds with aggregate principal amounts of $47 million and $46 million, respectively, and the Trinity River Authority of Texas Series 2006 pollution control revenue bonds with an aggregate principal amount of $50 million. All three bond series were issued in conjunction with the development of eight coal-fueled generation plants, which has been suspended. Restricted cash retained upon issuance of the bonds was used to fund substantially all of the redemption amount.

In March 2007, Texas Competitive Holdings and Oncor Electric Delivery issued floating rate senior notes with an aggregate principal amount of $1.0 billion and $800 million, respectively. The floating rate is based on LIBOR plus 50 basis points for Texas Competitive Holdings (subject to an increase of 25 basis points in the event of a downgrade in Texas Competitive Holdings’ credit rating) and 37.5 basis points for Oncor Electric Delivery (subject to an increase of up to 50 basis points in the event of a downgrade in Oncor Electric Delivery’s credit rating). The notes mature in September 2008, but are subject to mandatory redemption upon a change in control of Energy Future Holdings Corp., including consummation of the Proposed Merger.

F-18

Fair Value Hedges—Energy Future Holdings Corp. uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At June 30, 2007, $650 million of fixed rate debt had been effectively converted to variable rates through interest rate swap transactions, expiring through 2008. These swaps qualified for and were designated as fair value hedges in accordance with SFAS 133 (under the short-cut method as the conditions for assuming no ineffectiveness are met). Interest rate swaps related to $1.85 billion principal amount of debt were dedesignated as fair value hedges in January 2007. Offsetting swap positions were entered into and both the original swaps and offsetting positions are subsequently being marked-to-market in net income.

Long-term debt fair value adjustments—

	Six Months Ended June 30, 2007
Long-term debt fair value adjustments related to interest rate swaps at beginning of period—net reduction in debt carrying value	$	(63	)
Fair value adjustments during the period		1
Recognition of net gains on settled fair value hedges(a)		(1	)
Recognition of net losses on dedesignated fair value hedges(b)		4
Long-term debt fair value adjustments at end of period—net reduction in debt carrying value (net out-of-the-money value of swaps)	$	(59	)

(a) Net value of settled in-the-money fixed-to-variable swaps recognized in net income when the hedged transactions are recognized. Amount is pretax.

(b) Net value of dedesignated out-of-the money fixed-to-variable swaps recognized in net income when the hedged transactions are recognized. Amount is pretax.

Any changes in unsettled swap fair values of active positions reported as fair value adjustments to debt amounts are offset by changes in derivative assets and liabilities.

10. COMMITMENTS AND CONTINGENCIES

Generation Development

Subsidiaries of Energy Future Holdings Corp. have executed EPC agreements for the development of three lignite/coal-fueled generation units in Texas. Such subsidiaries or the EPC contractors have placed orders for critical long lead-time equipment, including boilers, turbine generators and air quality control systems for the two units at Oak Grove and one unit at Sandow, and construction of the three units has commenced.

The existing air permit for the Sandow facility was issued to Alcoa Inc. pursuant to a consent decree issued by a federal court and is expected to be transferred to a Energy Future Holdings Corp. subsidiary pursuant to a development agreement that includes a long-term power supply arrangement with Alcoa Inc. The consent decree contains certain provisions that create risk to the project; however, Energy Future Holdings Corp. has reached a negotiated settlement with the US Department of Justice and the EPA that would resolve the consent decree issues, including one related to the deadline for commercial operation of the facility. In February 2007, the federal court approved this settlement, but it is subject to pending appeal. There can be no assurance that the appeals court would not overturn the ruling, which would result in an adverse impact on the project.

A Energy Future Holdings Corp. subsidiary has received the air permit for the Oak Grove units, which was approved by the TCEQ in June 2007. The Oak Grove air permit is the subject of motions for rehearing at the TCEQ and collateral litigation in state and federal court and is expected to be appealed. While Energy Future Holdings Corp. does not expect the appeal to be successful, and it believes the collateral litigation is without merit and intends to vigorously defend such litigation and appeals, there can be no assurance that the appeal or collateral litigation will not have an adverse impact on the project.

F-19

Capital expenditures under the construction-related agreements for the three generation units totaled approximately $1.0 billion as of June 30, 2007. If the agreements had been canceled as of that date, subsidiaries of Energy Future Holdings Corp. would have incurred an estimated termination obligation of up to approximately $340 million. This estimated gross cancellation exposure of approximately $1.4 billion at June 30, 2007 excludes any potential recovery values for assets acquired to date and for assets already owned prior to executing such agreements that are intended to be utilized for these projects.

Litigation

Two putative class and derivative lawsuits and one derivative lawsuit were filed in the United States District Court, Northern District of Texas, Dallas Division in March 2007 against the directors of Energy Future Holdings Corp., Energy Future Holdings Corp., as a nominal defendant, and the Sponsors. On April 27, 2007, the Plaintiffs filed Amended Complaints asserting only derivative claims against the same defendants. The lawsuits seek to challenge and enjoin the Merger Agreement. The cases allege that the directors abused their ability to control and influence Energy Future Holdings Corp., committed gross mismanagement and violated various fiduciary duties by approving the Merger Agreement and the Sponsors aided and abetted that alleged conduct. The Plaintiffs contend that the directors violated fiduciary duties owed to shareholders by failing to maximize the value of Energy Future Holdings Corp. and by breaching duties of loyalty and due care by not taking adequate measures to ensure that the interests of shareholders were properly protected. The Merger Agreement allowed Energy Future Holdings Corp. to solicit other proposals from third parties until April 16, 2007 and the transaction is subject to the approval of Energy Future Holdings Corp.’s shareholders. Accordingly, Energy Future Holdings Corp. and its directors filed Motions to Dismiss based on the Plaintiffs failure to comply with the provisions of the Texas Business Organizations Code applicable to filing and pursuing derivative proceedings. The Motions are pending before the Court.

In February and March 2007, three derivative lawsuits were filed in Dallas County state district courts arising out of the Merger Agreement. The suits, filed by putative shareholders, allege that Energy Future Holdings Corp.’s directors, named as defendants, breached fiduciary duties owed Energy Future Holdings Corp. by approving the Merger Agreement. The petitions, now consolidated into one action in the 44^th District Court, Dallas County, Texas, include claims that the defendants failed to ensure that the transaction was in the best interest of Energy Future Holdings Corp.; that the directors participated in a transaction where their loyalties were divided and where they were to receive a personal financial benefit; that such alleged conduct constituted a breach of their duties of care, loyalty, good faith, candor and independence owed to Energy Future Holdings Corp.; and that the Sponsors aided and abetted the alleged breaches of fiduciary duties by the directors. Energy Future Holdings Corp. believes that the Plaintiffs failed to comply with provisions of the Texas Business Organizations Code applicable to filing and pursuing derivative proceedings and thus have filed a Motion to Dismiss that is pending before the Court. Additionally, Energy Future Holdings Corp. has filed a Written Statement with the Court advising that, pursuant to the Texas Business Organizations Code, a Derivative Demand Committee of independent and disinterested members of Energy Future Holdings Corp.’s board of directors has been formed and is engaged in the active review, in good faith, of the allegations in the consolidated derivative lawsuits. Consequently, Energy Future Holdings Corp. has requested that the Court enforce the automatic and mandatory stay of the proceedings as provided in the Texas Business Organizations Code (TBOC) until the Derivative Demand Committee has completed its review. On May 16, 2007, the parties agreed to stay the consolidated derivative proceeding pending the Derivative Demand Committee’s review of Plaintiffs’ claims in that proceeding. On May 18, 2007, the Court entered an order staying the action in accordance with Section 21.555 of the TBOC. On July 18, 2007, Energy Future Holdings Corp. filed a Written Statement pursuant to TBOC Section 21.555(c) and an Application for Additional Stay informing the District Court that the Derivative Demand Committee was continuing its active review, in good faith, of the allegations set forth in the derivative lawsuits and accordingly requested an extension of the order staying the action through August 31, 2007. The Court has not yet ruled upon the Written Statement and Application.

In February and March 2007 eight lawsuits were filed in state district court in Dallas County, Texas by putative shareholders against the directors of Energy Future Holdings Corp., Energy Future Holdings Corp., the Sponsors, and certain financial entities, asserting claims on behalf of owners of shares of Energy Future

F-20

Holdings Corp. common stock as well as seeking to certify a class action on behalf of allegedly similarly situated shareholders. The lawsuits, which have been consolidated into one action in the 44^th District Court, Dallas County, Texas, contend that the directors of Energy Future Holdings Corp. violated various fiduciary duties owed plaintiffs and other shareholders in connection with the execution of the Merger Agreement and that the Sponsors and certain financial entities aided and abetted the alleged breaches of fiduciary duties by the directors. Plaintiffs seek to enjoin defendants from consummating the Merger Agreement until such time as a procedure or process is adopted to obtain the highest possible price for shareholders, as well as a request that the Court direct the officers and directors of Energy Future Holdings Corp. to exercise their fiduciary duties in order to obtain a transaction in the best interest of Energy Future Holdings Corp. shareholders. The consolidated suit includes claims that the directors failed to take steps to properly value or maximize the value of Energy Future Holdings Corp. and breached their duties of loyalty, good faith, candor and independence owed to Energy Future Holdings Corp. shareholders. The Merger Agreement allowed Energy Future Holdings Corp. to solicit other proposals from third parties until April 16, 2007 and is subject to the approval of Energy Future Holdings Corp.’s shareholders. The consolidated suit purports to assert claims by shareholders directly against the directors. Energy Future Holdings Corp. believes that Texas law does not recognize such a cause of action. Consequently, Energy Future Holdings Corp. and its directors have filed a Motion to Dismiss. On May 25, 2007, the Court granted the Motion and dismissed the consolidated putative class action suit with prejudice. On May 31, 2007, Plaintiffs moved for reconsideration of the May 25 Order dismissing the action. The motion is pending before the Court. Energy Future Holdings Corp. believes the claims made in this litigation are without merit and, therefore, intends to vigorously defend this litigation.

On July 19, 2007, a putative class action lawsuit was filed in the United States District Court, Northern District of Texas, Dallas Division by a putative shareholder against Energy Future Holdings Corp. and its directors asserting a claim under Section 14(a) of the Securities Exchange Act of 1934 and the rules and regulations thereunder, asserting that the preliminary proxy statement of Energy Future Holdings Corp. filed June 14, 2007 fails to adequately describe the relevant facts and circumstances regarding the Proposed Merger as well as seeking to certify the litigation as a class action on behalf of allegedly similarly situated shareholders. Energy Future Holdings Corp. has not yet responded to this litigation and, as described below, on July 23, 2007, the Sponsors, joined by Energy Future Holdings Corp. for the limited purpose described below, have entered into a memorandum of understanding with plaintiffs that would result in the dismissal of this litigation if the settlement is approved by the courts. In the event that Energy Future Holdings Corp. is required to respond to this litigation, Energy Future Holdings Corp. will file a Motion to Dismiss based on the fact that this proxy statement clearly and accurately describes the information regarding the Proposed Merger and the information necessary for a shareholder to evaluate the proposal to approve the Merger Agreement. Energy Future Holdings Corp. believes the claims made in this litigation are without merit and, therefore, if necessary, Energy Future Holdings Corp. intends to vigorously defend this litigation.

On July 23, 2007, the Sponsors, joined by Energy Future Holdings Corp. for the limited purpose described below, executed a memorandum of understanding with the plaintiffs in certain of the lawsuits described above pursuant to which, if approved by the court in which the litigation is pending, to the extent required, all of the litigation related to the Proposed Merger will be dismissed with prejudice. Neither Energy Future Holdings Corp. nor any of its directors agreed to fund any payment or pay any other consideration under the settlement. Energy Future Holdings Corp. did agree to make certain revisions to the final proxy statement as part of the agreement between the Sponsors and the plaintiffs to settle the litigation and agreed that under certain circumstances the termination fee payable by Energy Future Holdings Corp. under the Merger Agreement would be $925 million rather than $1 billion. The settlement of the litigation, subject to court approval, will result in a dismissal of all claims against Energy Future Holdings Corp. and its officers and directors related to the Proposed Merger.

On December 1, 2006, a lawsuit was filed in the United States District Court for the Western District of Texas against TXU Generation Company LP, Oak Grove Management Company, LLC and Energy Future Holdings Corp. The complaint sought declaratory and injunctive relief, as well as the assessment of civil penalties, with respect to the permit application for the construction and operation of the Oak Grove Steam Electric Station in Robertson County, Texas. The plaintiffs allege violations of the Federal Clean Air Act, Texas

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Health and Safety Code and Texas Administrative Code and sought to temporarily and permanently enjoin the construction and operation of the Oak Grove generation plant. The complaint also asserted that the permit application was deficient in failing to comply with various modeling and analyses requirements relative to the impact of emissions from the Oak Grove plant. Plaintiffs further requested that the District Court enter an order requiring the defendants to take other appropriate actions to remedy, mitigate and offset alleged harm to the public health and environment. Energy Future Holdings Corp. believes the Oak Grove air permit granted by the TCEQ on June 13, 2007 is protective of the environment and that the application for and the processing of the air permit by Oak Grove Management Company LLC with the TCEQ has been in accordance with applicable law. Energy Future Holdings Corp. and the other defendants filed a Motion to Dismiss the litigation, which was granted by the District Court on May 21, 2007. The Plaintiffs have appealed the District Court’s dismissal of the case to the Fifth Circuit Court of Appeals. Energy Future Holdings Corp. believes the District Court properly granted the Motion to Dismiss and while Energy Future Holdings Corp. is unable to estimate any possible loss or predict the outcome of this litigation in the event the Fifth Circuit Court of Appeals reverses the District Court, Energy Future Holdings Corp. maintains that the claims made in the complaint are without merit. Accordingly, Energy Future Holdings Corp. intends to vigorously defend the appeal and this litigation in the event the Fifth Circuit reverses the District Court.

On September 6, 2005 a lawsuit was filed in the United States District Court for the Northern District of Texas, Dallas Division against Energy Future Holdings Corp. and C. John Wilder. The plaintiffs’ amended complaint asserts claims on behalf of the plaintiffs and a putative class of owners of certain Energy Future Holdings Corp. securities who tendered such securities in connection with a tender offer conducted by Energy Future Holdings Corp. in 2004. The amended complaint alleges violations of the provisions of Sections 14(e), 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5. The allegations relate to a tender offer conducted in September and October 2004 for certain equity-linked securities in which it was expressly disclosed that Energy Future Holdings Corp. management was evaluating whether it should recommend to the board of directors that the board reevaluate Energy Future Holdings Corp.’s dividend policy. After the tender offer was closed, and consistent with the disclosure, management did make a recommendation to the board to reevaluate the dividend policy and the board elected to increase the quarterly dividend. The plaintiffs contend that such disclosure in connection with the tender offer was inadequate. Energy Future Holdings Corp. maintains that the disclosure provided in connection with the tender offer regarding the evaluation of the dividend policy was complete and accurate at the time the tender offer was initiated as well as when it was closed. A Motion to Dismiss was filed by the defendants, and the District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice on August 30, 2006. The plaintiffs filed a timely notice of appeal, and the matter is now before the Fifth Circuit Court of Appeals with briefing of the appeal completed. While Energy Future Holdings Corp. is unable to estimate any possible loss or predict the outcome of this litigation in the event the Fifth Circuit Court of Appeals reverses the District Court, Energy Future Holdings Corp. believes the claims made in this litigation are without merit and, accordingly, intends to vigorously defend this litigation, including the appeal of the District Court’s order dismissing the litigation.

In November 2002, February 2003 and March 2003, three lawsuits were filed in the US District Court for the Northern District of Texas, Dallas Division, asserting claims under Employee Retirement Income Security Act (ERISA) on behalf of a putative class of participants in and beneficiaries of various employee benefit plans of Energy Future Holdings Corp. These ERISA lawsuits were consolidated, and a consolidated complaint was filed in February 2004 against Energy Future Holdings Corp., the directors of Energy Future Holdings Corp. serving during the putative class period as well as certain officers of Energy Future Holdings Corp. who were the members of the TXU Thrift Plan Committee. The plaintiffs seek to represent a class of participants in such employee benefit plans during the period between April 26, 2001 and October 11, 2002. The plaintiffs filed an initial motion for class certification and, after class certification discovery was completed, the District Court denied plaintiffs’ initial class certification motion without prejudice and granted plaintiffs’ leave to amend their complaint. Plaintiffs’ second class certification motion, filed on the basis of their amended complaint, was denied, and the case was ordered dismissed without prejudice on September 29, 2005. The plaintiffs filed an appeal of the dismissal to the Fifth Circuit Court of Appeals. While on appeal, the matter was referred to the Fifth

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Circuit’s alternative dispute resolution program and subsequently to mediation. While mediation was unsuccessful, further discussions led to an agreement in principle to settle this litigation on December 24, 2006 for $7.25 million, before attorneys’ fees, to be paid by Energy Future Holdings Corp. to the Thrift Plan pursuant to a Court approved allocation. A Memorandum of Understanding confirming the agreement in principle was signed on January 24, 2007, and the settlement is in the process of being confirmed with final settlement documents after which the settlement will be submitted to the District Court for approval. Energy Future Holdings Corp. believes the claims are without merit and, in the event the settlement is not approved, intends to vigorously defend the lawsuit, including the appeal. Energy Future Holdings Corp. is, however, unable to estimate any possible loss or predict the outcome of this action in the event the District Court rejects the settlement, the Fifth Circuit reverses the dismissal and remands the case to the District Court or the suit is refiled by the plaintiffs or others seeking to assert similar claims.

In October, November and December 2002 and January 2003, a number of lawsuits were filed against Energy Future Holdings Corp. and certain of its officers and directors. These lawsuits were consolidated and lead plaintiffs were appointed by the District Court. The consolidated complaint alleged violations of the Securities Exchange Act of 1934, as amended, Rule 10b-5 and the Securities Act of 1933, as amended. On January 20, 2005, Energy Future Holdings Corp. executed a memorandum of understanding settling this litigation. After preliminary certification of a settlement class and notice to such class, the District Court conducted a hearing and thereafter on November 8, 2005 granted final approval of the settlement. Certain members of the settlement class who objected to the settlement appealed the orders approving the settlement to the Fifth Circuit Court of Appeals. The appeal was dismissed on June 11, 2007 and as a result, the District Court’s Judgment is final and not subject to further appeal.

Regulatory Investigations

In March 2007, the Commission issued a Notice of Violation (NOV) stating that the Commission Staff is recommending an enforcement action, including the assessment of administrative penalties, against Energy Future Holdings Corp. and certain affiliates for alleged market power abuse by its power generation affiliates and TXU Portfolio Management in ERCOT-administered balancing energy auctions during certain periods of the summer of 2005. The NOV is premised upon the Commission Staff’s allegation that TXU Portfolio Management’s bidding behavior was not competitive and increased market participants’ costs of balancing energy by approximately $70 million, including approximately $20 million in incremental revenues to Energy Future Holdings Corp. The Commission Staff has recommended that TXU Portfolio Management and its affiliates be required to pay administrative penalties in the amount of $140 million and pay the $70 million in incremental costs purportedly incurred by market participants. A hearing requested by TXU Portfolio Management to contest the alleged occurrence of a violation and the amount of the penalty in the NOV has been scheduled to start in April 2008. Energy Future Holdings Corp. believes TXU Portfolio Management’s conduct during the period in question was consistent with the Commission’s rules and policies, and no market power abuse was committed. Energy Future Holdings Corp. is vigorously contesting the NOV. Energy Future Holdings Corp. is unable to predict the outcome of this matter.

Energy Future Holdings Corp. and TXU Portfolio Management have taken actions to reduce the risk of future similar allegations related to the balancing energy segment of the ERCOT wholesale market, including working with the Commission Staff and the Commission’s independent market monitor to develop a voluntary mitigation plan for approval by the Commission. TXU Portfolio Management has submitted a voluntary mitigation plan that was approved by the Commission in July 2007.

As previously disclosed, the Commission Staff had been investigating TXU Energy Retail with respect to the renewal process for certain small and medium business customers on term service plans. The investigation did not involve residential customers. In June 2007, TXU Energy Retail reached a settlement agreement with the Staff of the Commission that was approved by the Commission in July 2007. While TXU Energy Retail expressly denies any violations of rules, it has agreed to pay the Commission a $5 million settlement as a compromise in this dispute.

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Other Proceedings

In addition to the above, Energy Future Holdings Corp. and its subsidiaries are involved in various other legal and administrative proceedings in the normal course of business the ultimate resolution of which, in the opinion of management, should not have a material effect on its financial position, results of operations or cash flows.

Guarantees

Overview—As discussed below, Energy Future Holdings Corp. and its subsidiaries have entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions. Guarantees issued or modified after December 31, 2002 are subject to the recognition and initial measurement provisions of FIN 45, which requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.

Disposed TXU Gas operations—In connection with the TXU Gas transaction in October 2004, Energy Future Holdings Corp. agreed to indemnify Atmos Energy Corporation for certain qualified environmental claims that may arise in relation to the assets acquired by Atmos Energy Corporation. Energy Future Holdings Corp. is not required to indemnify Atmos Energy Corporation until the aggregate of all such qualified claims exceeds $10 million, and Energy Future Holdings Corp. is only required to indemnify Atmos Energy Corporation for 50% of qualified claims between $10 million and $20 million. The maximum amount that Energy Future Holdings Corp. would be required to pay Atmos Energy Corporation pursuant to this environmental indemnity, which expires on October 1, 2007, is $192.5 million. In addition, until October 1, 2014, Energy Future Holdings Corp. agreed to indemnify Atmos Energy Corporation for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos Energy Corporation, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. In each case, Energy Future Holdings Corp.’s indemnification is limited to 10 years from the disposition date. The maximum aggregate amount that Energy Future Holdings Corp. may be required to pay is $1.9 billion. The estimated fair value of the indemnification recorded upon completion of the TXU Gas transaction was $2.5 million. To date, Energy Future Holdings Corp. has not been required to make any payments to Atmos Energy Corporation under any of these indemnity obligations, and no such payments are currently anticipated.

In 1992, a discontinued engineering and construction business of TXU Gas completed construction of a plant, the performance of which is guaranteed by TXU Gas through 2008. The maximum contingent liability under the guarantee is approximately $108 million. No claims have been asserted under the guarantee, and none are currently anticipated. Energy Future Holdings Corp. retains this contingent liability under the terms of the TXU Gas transaction agreement.

Residual value guarantees in operating leases—Energy Future Holdings Corp. or a subsidiary is the lessee under various operating leases that guarantee the residual values of the leased facilities. At June 30, 2007, the aggregate maximum amount of residual values guaranteed was approximately $205 million with an estimated residual recovery of approximately $202 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the lease portfolio is approximately four years. A significant portion of the maximum guarantee amount relates to leases entered into prior to December 31, 2002.

Indebtedness guarantee—In 1990, Energy Future Competitive Holdings Company repurchased an electric co-op’s minority ownership interest in the Comanche Peak nuclear generation plant and assumed the co-op’s indebtedness to the US government for the facilities. The indebtedness is included in long-term debt reported in the consolidated balance sheet. Energy Future Competitive Holdings Company is making principal and interest payments to the co-op in an amount sufficient for the co-op to make payments on its indebtedness. Energy Future Competitive Holdings Company guaranteed the co-op’s payments, and in the event that the co-op fails to make its payments on the indebtedness, the US government would assume the co-op’s rights under the agreement, and such payments would then be owed directly by Energy Future Competitive Holdings Company. At June 30, 2007, the balance of the indebtedness was $120 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities.

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Letters of Credit

At June 30, 2007, Texas Competitive Holdings had outstanding letters of credit under its revolving credit facilities in the amount of $499 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions, and $46 million for miscellaneous credit support requirements.

Texas Competitive Holdings has outstanding letters of credit under its revolving credit facilities totaling $455 million at June 30, 2007 to support existing floating rate pollution control revenue bond debt of $446 million principal amount. The letters of credit are available to fund the payment of such debt obligations and expire in 2009.

As of June 30, 2007, Texas Competitive Holdings had outstanding letters of credit under its revolving credit facilities totaling $77 million to support mining reclamation activities and certain collection agent activities performed for REPs in Energy Future Holdings Corp.’s historical service territory.

Energy Future Holdings Corp. and Texas Competitive Holdings have previously guaranteed the obligations under the lease agreement for Energy Future Holdings Corp.’s current headquarters building. These obligations include future undiscounted base rent payments. As a result of the March 2007 downgrade by S&P of Texas Competitive Holdings’ credit rating to below investment grade, Texas Competitive Holdings has provided a $144 million letter of credit to replace Energy Future Holdings Corp.’s and its guarantees of these obligations.

Security Interest

A first-lien security interest has been placed on the two lignite/coal-fueled generation units at Texas Competitive Holdings’ Big Brown plant to support commodity hedging transactions entered into by TXU DevCo. The lien can be used to secure obligations related to current and future hedging transactions of TXU DevCo or its affiliates for up to an aggregate of 1.2 billion MMBtu of natural gas.

11. SHAREHOLDERS’ EQUITY

Declaration of Dividend—At its May 2007 meeting, the Board of Directors of Energy Future Holdings Corp. declared a quarterly dividend of $0.4325 per share, which was paid on July 2, 2007 to shareholders of record on June 1, 2007. At its February 2007 meeting, the Board of Directors of Energy Future Holdings Corp. declared a quarterly dividend of $0.4325 per share, which was paid on April 2, 2007 to shareholders of record on March 2, 2007.

Dividend Restrictions—At June 30, 2007, there were no significant restrictions on the payment of regular quarterly common stock dividends; except that, the Merger Agreement prohibits Energy Future Holdings Corp. from increasing the regular quarterly common stock dividend to an amount greater than $0.4325 without the prior approval of the Sponsors.

Common Stock Repurchase—Energy Future Holdings Corp. has board of directors’ authority to repurchase up to 23 million shares of Energy Future Holdings Corp. common stock through the end of 2007. Under this authority, Energy Future Holdings Corp. repurchased 153 thousand shares in the second quarter of 2007. The Merger Agreement generally prohibits Energy Future Holdings Corp. from making common stock repurchases without the prior approval of the Sponsors.

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Shareholders’ Equity—The following table presents the changes to shareholders’ equity during the six months ended June 30, 2007:

	Common Stock		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
Balance at December 31, 2006	$	5	$	1,104		$	622		$	409		$	2,140
Common stock issuances		—		1			—			—			1
Common stock repurchases		—		(10	)		—			—			(10	)
Net effects of cash flow hedges		—		—			—			(372	)		(372	)
Reclassification of pension and other retirement benefit costs		—		—			—			5			5
Dividends		—		—			(397	)		—			(397	)
Net loss		—		—			(377	)		—			(377	)
Effect of adoption of FIN 48		—		—			33			—			33
Effects of stock-based incentive compensation plans(a)		—		(77	)		—			—			(77	)
Excess tax benefit on stock-based compensation		—		82			—			—			82
Cost of Thrift Plan shares issued by LESOP trustee		—		6			—			—			6
Effects of executive deferred compensation plan		—		10			—			—			10
Other		—		(1	)		2			—			1
Balance at June 30, 2007	$	5	$	1,115		$	(117	)	$	42		$	1,045

(a) Includes $93 million in settlements of minimum withholding tax liabilities.

12. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

The following table breaks down commodity and other derivative contractual assets and liabilities as presented in the balance sheet into the two major components:

	June 30, 2007
	Commodity contracts			Cash flow hedges and other derivatives		Netting adjustments(a)			Total
Assets:
Current assets	$	243		$	359	$	(303	)	$	299
Noncurrent assets		112			172		(68	)		216
Total	$	355		$	531	$	(371	)	$	515
Liabilities:
Current liabilities	$	701		$	31	$	(303	)	$	429
Noncurrent liabilities		810			134		(68	)		876
Total	$	1,511		$	165	$	(371	)	$	1,305
Net assets (liabilities)	$	(1,156	)	$	366	$	—		$	(790	)

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	December 31, 2006
	Commodity contracts			Cash flow hedges and other derivatives		Netting adjustments(a)			Total
Assets:
Current assets	$	276		$	698	$	(24	)	$	950
Noncurrent assets		162			248		(65	)		345
Total	$	438		$	946	$	(89	)	$	1,295
Liabilities:
Current liabilities	$	278		$	39	$	(24	)	$	293
Noncurrent liabilities		183			73		(65	)		191
Total	$	461		$	112	$	(89	)	$	484
Net assets (liabilities)	$	(23	)	$	834	$	—		$	811

(a) Represents the effects of netting assets and liabilities at the counterparty agreement level.

Commodity Contract Assets and Liabilities—Commodity contract assets and liabilities primarily represent mark-to-market values of natural gas and electricity derivative instruments that have not been designated as cash flow hedges or “normal” purchases or sales under SFAS 133.

Current and noncurrent commodity contract assets are stated net of applicable credit (collection) and performance reserves totaling $10 million and $9 million at June 30, 2007 and December 31, 2006, respectively. Performance reserves are provided for direct, incremental costs to settle the contracts.

Commodity contract assets/liabilities at June 30, 2007 include “day one” losses of $164 million associated with contracts entered into in the first six months of 2007 at below market prices. Essentially all of this amount represents losses associated with transactions using natural gas financial instruments intended to economically hedge exposure to future changes in electricity prices. The losses were recorded as a reduction of revenues, consistent with other mark-to-market gains and losses, and were included in the results of the Competitive Electric segment.

Commodity contract assets/liabilities at June 30, 2007 includes a “day one” gain of $30 million associated with a long-term power purchase agreement entered into in the second quarter of 2007. The gain was recorded as an increase to revenues, consistent with other mark-to-market gains and losses, and was included in the results of the Competitive Electric segment.

Cash Flow Hedge and Other Derivative Assets and Liabilities—Cash flow hedge and other derivative assets and liabilities primarily represent mark-to-market values of commodity contracts that have been designated as cash flow hedges as well as interest rate swap agreements. The change in fair value of derivative assets and liabilities related to cash flow hedges are recorded as other comprehensive income or loss to the extent the hedges are effective; the ineffective portion of the change in fair value is included in net income. A portion of the interest rate swaps have been designated as fair value hedges and the change in fair value of such hedges are recorded as an increase or decrease in the carrying value of the debt (see Note 9); changes in fair value of other interest rate swaps are included in net income.

As previously disclosed, a significant portion of natural gas financial instruments entered into to hedge future changes in electricity prices had been designated and accounted for as cash flow hedges. In March 2007, these instruments were dedesignated as cash flow hedges as allowed under SFAS 133. Subsequent changes in the fair value of these instruments are being marked-to-market in net income.

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A summary of cash flow hedge and other derivative assets and liabilities follows:

	June 30, 2007		December 31, 2006
Current and noncurrent assets:
Commodity-related cash flow hedges	$	445	$	933
Debt-related interest rate swaps		71		4
Other		15		9
Total	$	531	$	946
Current and noncurrent liabilities:
Commodity-related cash flow hedges	$	20	$	23
Debt-related interest rate swaps		145		89
Total	$	165	$	112

Other Cash Flow Hedge Information—Energy Future Holdings Corp. experienced cash flow hedge ineffectiveness of $1 million in net losses and $114 million in net gains for the three and six month periods ended June 30, 2007, respectively. For the corresponding periods of 2006, the amounts were $141 million and $128 million in net gains, respectively. These amounts are pretax and are reported in revenues.

The net effect of recording unrealized mark-to-market gains and losses arising from hedge ineffectiveness (versus recording gains and losses upon settlement) includes the above amounts as well as the effect of reversing unrealized ineffectiveness gains and losses recorded in previous periods to offset realized gains and losses in the current period. Such net unrealized effect totaled $5 million in net losses and $94 million in net gains for the three and six month periods ended June 30, 2007, respectively, and $145 million and $144 million in net gains for the three and six month periods ended June 30, 2006, respectively.

As of June 30, 2007, commodity positions accounted for as cash flow hedges, which represent a small portion of economic hedge positions, reduce exposure to variability of future cash flows from future revenues or purchases through 2010.

Cash flow hedge amounts reported in the Statements of Condensed Consolidated Comprehensive Income exclude period net gains and losses associated with cash flow hedges settled within the periods presented. These amounts totaled $5 million and $16 million in after-tax net losses for the three and six month periods ended June 30, 2007, respectively, and $14 million and $18 million in after-tax net gains for the three and six month periods ended June 30, 2006, respectively.

Energy Future Holdings Corp. expects that $44 million of after-tax net gains related to cash flow hedges included in accumulated other comprehensive income will be reclassified into net income during the next twelve months as the related hedged transactions affect net income. Of this amount, $50 million in gains relate to commodity hedges and $6 million in losses relate to debt-related hedges.

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13. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) COSTS

Net pension and OPEB costs for the three and six months ended June 30, 2007 and 2006 are comprised of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Components of net pension costs:
Service cost	$	9		$	11		$	20		$	21
Interest cost		36			34			71			68
Expected return on assets		(38	)		(37	)		(79	)		(73	)
Prior service cost		—			1			1			1
Net loss		6			8			10			16
Net pension cost		13			17			23			33
Components of net OPEB costs:
Service cost		4			3			6			6
Interest cost		14			15			27			30
Expected return on assets		(5	)		(5	)		(10	)		(10	)
Net transition obligation		1			1			1			1
Prior service cost		(1	)		(1	)		(2	)		(2	)
Net loss		3			7			13			15
Net OPEB costs		16			20			35			40
Net pension and OPEB costs		29			37			58			73
Less amounts deferred principally as a regulatory asset or property		(17	)		(21	)		(29	)		(41	)
Net amounts recognized as expense	$	12		$	16		$	29		$	32

The discount rate reflected in net pension and OPEB costs in 2007 is 5.90%. The expected rate of return on plan assets reflected in the 2007 cost amounts is 8.75% for the pension plan and 8.67% for the OPEB plan.

In accordance with accounting rules under SFAS 158, following is the detail of amounts reclassified from accumulated other comprehensive income (AOCI) to net pension and OPEB costs for the three months and six months ended June 30, 2007, respectively:

	Three Months Ended June 30, 2007									Six Months Ended June 30, 2007
	Pension Plan			OPEB Plan			Total			Pension Plan			OPEB Plan			Total
Net transition obligation	$	—		$	1		$	1		$	—		$	1		$	1
Prior service cost		—			(1	)		(1	)		1			(2	)		(1	)
Net loss		6			3			9			10			13			23
Total		6			3			9			11			12			23
Less amounts related to a regulatory asset		(4	)		(4	)		(8	)		(8	)		(7	)		(15	)
Net pretax amounts reclassified from AOCI	$	2		$	(1	)	$	1		$	3		$	5		$	8

Energy Future Holdings Corp. expects to make a $1 million required contribution to its pension plan in 2007.

14. SEGMENT INFORMATION

Energy Future Holdings Corp.’s operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

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Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, retail electricity sales to residential and business customers, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. These activities are conducted principally by subsidiaries of Texas Competitive Holdings. The results of this segment also include the activities of TXU DevCo and its subsidiaries, which are engaged in the development of new generation facilities, and the activities of a lease trust holding certain combustion turbines.

Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor Electric Delivery, including its wholly owned bankruptcy-remote financing subsidiary, and also include certain revenues and costs associated with broadband-over-powerlines equipment installation.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses, interest on Energy Future Holdings Corp. and Energy Future Competitive Holdings Company debt and activities involving mineral interest holdings.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies. Energy Future Holdings Corp. evaluates performance based on income from continuing operations. Energy Future Holdings Corp. accounts for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Operating revenues:
Competitive Electric	$	1,666		$	2,349		$	2,983		$	4,359
Regulated Delivery		589			604			1,207			1,166
Corporate and Other		12			14			23			27
Eliminations		(245	)		(300	)		(522	)		(581	)
Consolidated	$	2,022		$	2,667		$	3,691		$	4,971
Regulated revenues included in operating revenues:
Competitive Electric	$	—		$	—		$	—		$	—
Regulated Delivery		589			604			1,207			1,166
Corporate and Other		—			—			—			—
Eliminations		(232	)		(284	)		(497	)		(551	)
Consolidated	$	357		$	320		$	710		$	615
Affiliated revenues included in operating revenues:
Competitive Electric	$	2		$	3		$	3		$	4
Regulated Delivery		232			284			497			551
Corporate and Other		11			13			22			26
Eliminations		(245	)		(300	)		(522	)		(581	)
Consolidated	$	—		$	—		$	—		$	—
Income (loss) from continuing operations:
Competitive Electric	$	129		$	461		$	(342	)	$	981
Regulated Delivery		54			86			140			151
Corporate and Other		(73	)		(50	)		(186	)		(119	)
Consolidated	$	110		$	497		$	(388	)	$	1,013

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15. SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations—

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Operating revenues:
Regulated	$	589		$	604		$	1,207		$	1,166
Unregulated		1,678			2,363			3,006			4,386
Intercompany sales eliminations—regulated		(232	)		(284	)		(497	)		(551	)
Intercompany sales eliminations—unregulated		(13	)		(16	)		(25	)		(30	)
Total operating revenues		2,022			2,667			3,691			4,971
Costs and operating expenses:
Fuel, purchased power costs and delivery fees—unregulated(a)		739			658			1,404			1,179
Operating costs—regulated		207			194			402			385
Operating costs—unregulated		161			147			312			299
Depreciation and amortization—regulated		114			117			234			231
Depreciation and amortization—unregulated		86			90			169			182
Selling, general and administrative expenses—regulated		49			43			90			90
Selling, general and administrative expenses—unregulated		178			138			357			280
Franchise and revenue-based taxes—regulated		60			59			121			119
Franchise and revenue-based taxes—unregulated		29			28			55			55
Other income		(16	)		(42	)		(45	)		(55	)
Other deductions		122			221			891			221
Interest income		(17	)		(11	)		(35	)		(20	)
Interest expense and related charges		221			218			418			431
Total costs and operating expenses		1,933			1,860			4,373			3,397
Income (loss) from continuing operations before income taxes	$	89		$	807		$	(682	)	$	1,574

(a) Includes unregulated cost of fuel consumed of $245 million and $250 million for the three months ended June 30, 2007 and 2006, respectively, and $477 million and $415 million for the six months ended June 30, 2007 and 2006, respectively. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

The operations of the Competitive Electric segment are included above as unregulated as the Texas wholesale and retail electricity markets are open to competition. However, retail pricing to residential customers in the historical service territory was subject to certain price controls until December 31, 2006.

Interest Expense and Related Charges—

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Interest	$	237		$	224		$	452		$	438
Amortization of debt discounts, premiums and issuance costs		8			4			12			8
Capitalized interest, including debt portion of allowance for borrowed funds used during construction		(24	)		(10	)		(46	)		(15	)
Total interest expense and related charges	$	221		$	218		$	418		$	431

F-31

Restricted Cash—

	Balance Sheet Classification
	At June 30, 2007				At December 31, 2006
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Pollution control revenue bond funds held by trustee (See Note 9)	$	1	$	102	$	—	$	241
Amounts related to securitization (transition) bonds		52		17		55		17
All other		1		—		3		—
Total restricted cash	$	54	$	119	$	58	$	258

Inventories by Major Category—

	June 30, 2007		December 31, 2006
Materials and supplies	$	186	$	189
Fuel stock		97		94
Natural gas in storage		110		75
Environmental energy credits and emission allowances		35		25
Total inventories	$	428	$	383

Investments—

	June 30, 2007		December 31, 2006
Nuclear decommissioning trust	$	474	$	447
Assets related to employee benefit plans, principally employee savings programs		200		197
Land		36		36
Note receivable from Capgemini		25		25
Investment in unconsolidated affiliates		2		3
Miscellaneous other		5		4
Total investments	$	742	$	712

Property, Plant and Equipment—As of June 30, 2007 and December 31, 2006, property, plant and equipment of $19.4 billion and $18.8 billion, respectively, is stated net of accumulated depreciation and amortization of $12.7 billion and $12.4 billion, respectively.

Asset Retirement Obligations—These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of Oncor Electric Delivery’s rate setting.

F-32

The following table summarizes the changes to the asset retirement liability, reported in other noncurrent liabilities and deferred credits in the consolidated balance sheet, during the six months ended June 30, 2007:

Asset retirement liability at December 31, 2006	$	585
Additions:
Accretion		19
Reductions:
Mining reclamation cost adjustments		(2	)
Mining reclamation payments		(13	)
Asset retirement liability at June 30, 2007	$	589

Intangible Assets—Intangible assets other than goodwill are comprised of the following:

	As of June 30, 2007						As of December 31, 2006
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Intangible assets subject to amortization included in property, plant and equipment:
Capitalized software placed in service	$	435	$	352	$	83	$	423	$	339	$	84
Land easements		180		67		113		180		65		115
Total	$	615	$	419	$	196	$	603	$	404	$	199

Aggregate Energy Future Holdings Corp. amortization expense for intangible assets for the three months ended June 30, 2007 and 2006 totaled $8 million and $6 million, respectively. Aggregate Energy Future Holdings Corp. amortization expense for intangible assets for the six months ended June 30, 2007 and 2006 totaled $15 million and $14 million, respectively. At June 30, 2007, the weighted average remaining useful lives of capitalized software and land easements were six years and 69 years, respectively. The estimated aggregate amortization expense for each of the five succeeding fiscal years from December 31, 2006 is as follows:

Year	Amortization Expense
2007	$	33
2008		28
2009		18
2010		9
2011		6

Goodwill (net of accumulated amortization) as of June 30, 2007 and December 31, 2006 totaled $542 million with $517 million at Texas Competitive Holdings and $25 million at Oncor Electric Delivery.

F-33

Regulatory Assets and Liabilities—

	June 30, 2007		December 31, 2006
Regulatory assets
Generation-related regulatory assets securitized by transition bonds	$	1,246	$	1,316
Employee retirement costs		451		461
Storm-related service recovery costs		142		138
Securities reacquisition costs		108		112
Recoverable deferred income taxes—net		90		90
Employee severance costs		42		44
Total regulatory assets		2,079		2,161
Regulatory liabilities
Investment tax credit and protected excess deferred taxes		61		63
Over-collection of securitization (transition) bond revenues		34		34
Nuclear decommissioning cost over-recovery		26		17
Other regulatory liabilities		23		19
Total regulatory liabilities		144		133
Net regulatory assets	$	1,935	$	2,028

Regulatory assets totaling $121 million have been reviewed and approved by the Commission and are earning a return. The unamortized amounts of these regulatory assets reflected in the above table totaled $97 million at June 30, 2007 and $100 million at December 31, 2006. The assets that have been approved by the Commission and are not earning a return totaled $1.275 billion at June 30, 2007 and $1.343 billion at December 31, 2006, and have a remaining recovery period of nine to 44 years, including the regulatory assets securitized by transition bonds that have a remaining recovery period of nine years.

Supplemental Cash Flow Information—

	Six Months Ended June 30,
	2007		2006
Cash payments related to continuing operations:
Interest (net of amounts capitalized)	$	386	$	434
Income taxes	$	214	$	18
Noncash investing and financing activities:
Noncash construction expenditures	$	213	$	63

16. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

On October 10, 2007, Energy Future Holdings Corp., a Texas corporation formerly known as TXU Corp., completed its Merger with Merger Sub, a wholly-owned subsidiary of Texas Energy Future Holdings Limited Partnership (Parent). As a result of the Merger, Energy Future Holdings Corp. became a wholly-owned subsidiary of Parent.

The Merger is being accounted for under the purchase method of accounting whereby the total cost of the transaction is being allocated to Energy Future Holdings Corp.’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values, and the excess of the purchase price over the fair value of net assets acquired is recorded as goodwill.

Energy Future Holdings Corp. expects to refinance $2.0 billion of its Senior Unsecured Bridge Facility obtained to finance the Merger with senior unsecured notes (the “Notes”). The Notes will be unconditionally

F-34

guaranteed by Energy Future Competitive Holdings Company and Energy Future Intermediate Holding Company LLC, 100% owned subsidiaries of Energy Future Holdings Corp. (collectively the “Guarantors”) on an unsecured basis. The guarantees issued by the Guarantors will be full and unconditional, joint and several guarantees of the Notes. The guarantees will rank equally with any unsecured senior indebtedness of the Guarantors and will be effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of Energy Future Holdings Corp., either direct or indirect, will not guarantee the senior unsecured notes (collectively the “Non-Guarantors”). The debt agreements will restrict Energy Future Holdings Corp.’s ability to pay dividends or make investments.

The following tables present the condensed consolidating statements of income of Energy Future Holdings Corp. (“Parent/Issuer”), the Guarantors and the Non-Guarantors for the three-month and six-month periods ended June 30, 2007 and 2006, the condensed consolidating statements of cash flows of the Parent/Issuer, the Guarantors and the Non-Guarantors for the six-month periods ended June 30, 2007 and 2006 and the condensed consolidating balance sheets as of June 30, 2007 and December 31, 2006 of the Parent/Issuer, the Guarantors and the Non-Guarantors.

F-35

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Three Months Ended June 30, 2007

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,389		$	(367	)	$	2,022
Costs and expenses
Fuel, purchased power costs and delivery fees		—			—			1,005			(266	)		739
Operating costs		—			—			426			(58	)		368
Depreciation and amortization		—			—			200			—			200
Selling, general and administrative expenses		20			—			249			(42	)		227
Franchise and revenue-based taxes		—			—			88			1			89
Other income		—			—			(16	)		—			(16	)
Other deductions		18			—			105			(1	)		122
Interest income		(43	)		(65	)		(114	)		205			(17	)
Interest expense and related charges		181			60			186			(206	)		221
Total costs and expenses		176			(5	)		2,129			(367	)		1,933
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries		(176	)		5			260			—			89
Income tax expense (benefit)		(75	)		2			52			—			(21	)
Equity in earnings of subsidiaries		222			351			328			(901	)		—
Income from continuing operations		121			354			536			(901	)		110
Income from discontinued operations, net of tax effect		—			—			11			—			11
Net income	$	121		$	354		$	547		$	(901	)	$	121

F-36

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Three Months Ended June 30, 2006

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,968		$	(301	)	$	2,667
Costs and expenses
Fuel, purchased power costs and delivery fees		—			—			943			(285	)		658
Operating costs		—			—			345			(4	)		341
Depreciation and amortization		—			—			207			—			207
Selling, general and administrative expenses		18			—			175			(12	)		181
Franchise and revenue-based taxes		—			—			87			—			87
Other income		—			—			(42	)		—			(42	)
Other deductions		5			—			216			—			221
Interest income		(16	)		(51	)		(88	)		144			(11	)
Interest expense and related charges		152			29			185			(148	)		218
Total costs and expenses		159			(22	)		2,028			(305	)		1,860
Income (loss) before income taxes and equity earnings of subsidiaries		(159	)		22			940			4			807
Income tax expense (benefit)		(66	)		6			371			(1	)		310
Equity in earnings of subsidiaries		590			553			285			(1,428	)		—
Net income	$	497		$	569		$	854		$	(1,423	)	$	497

F-37

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Six Months Ended June 30, 2007

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	4,486		$	(795	)	$	3,691
Costs and expenses
Fuel, purchased power costs and delivery fees		—			—			1,976			(572	)		1,404
Operating costs		—			—			844			(130	)		714
Depreciation and amortization		—			—			403			—			403
Selling, general and administrative expenses		40			—			502			(95	)		447
Franchise and revenue-based taxes		—			—			176			—			176
Other income		—			—			(45	)		—			(45	)
Other deductions		84			—			807			—			891
Interest income		(78	)		(125	)		(224	)		392			(35	)
Interest expense and related charges		350			114			344			(390	)		418
Total costs and expenses		396			(11	)		4,783			(795	)		4,373
Income (loss) from continuing operations before income taxes and equity in earnings (losses) of subsidiaries		(396	)		11			(297	)		—			(682	)
Income tax expense (benefit)		(152	)		4			(146	)		—			(294	)
Equity in earnings (losses) of subsidiaries		(133	)		503			986			(1,356	)		—
Income (loss) from continuing operations		(377	)		510			835			(1,356	)		(388	)
Income from discontinued operations, net of tax effect		—			—			11			—			11
Net income (loss)	$	(377	)	$	510		$	846		$	(1,356	)	$	(377	)

F-38

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Six Months Ended June 30, 2006

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	5,556		$	(585	)	$	4,971
Costs and expenses
Fuel, purchased power costs and delivery fees		—			—			1,733			(554	)		1,179
Operating costs		—			—			691			(7	)		684
Depreciation and amortization		—			—			413			—			413
Selling, general and administrative expenses		34			—			361			(25	)		370
Franchise and revenue-based taxes		—			—			174			—			174
Other income		—			—			(55	)		—			(55	)
Other deductions		6			—			215			—			221
Interest income		(31	)		(89	)		(160	)		260			(20	)
Interest expense and related charges		291			47			364			(271	)		431
Total costs and expenses		300			(42	)		3,736			(597	)		3,397
Income (loss) from continuing operations before income taxes and equity in earnings of subsidiaries		(300	)		42			1,820			12			1,574
Income tax expense (benefit)		(111	)		13			658			1			561
Equity in earnings of subsidiaries		1,262			1,086			484			(2,832	)		—
Income from continuing operations		1,073			1,115			1,646			(2,821	)		1,013
Income from discontinued operations, net of tax effect		—			—			60			—			60
Net income	$	1,073		$	1,115		$	1,706		$	(2,821	)	$	1,073

F-39

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2007

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net income (loss)	$	(377	)	$	510		$	846		$	(1,356	)	$	(377	)
Income from discontinued operations, net of tax		—			—			(11	)		—			(11	)
Income (loss) from continuing operations		(377	)		510			835			(1,356	)		(388	)
Adjustments to reconcile income (loss) from continuing operations to cash provided by (used in) operating activities:
Equity in (earnings) losses of subsidiaries		133			(503	)		(986	)		1,356			—
Depreciation and amortization		—			—			433			—			433
Deferred income tax expense (benefit)—net		11			—			(624	)		—			(613	)
Impairments and other asset writedowns charges		63			—			691			—			754
Net losses from unrealized mark-to-market valuations		—			—			1,182			—			1,182
Other, net		11			—			22			—			33
Net changes in operating assets and liabilities		811			547			(1,508	)		(1,306	)		(1,456	)
Cash provided by (used in) operating activities		652			554			45			(1,306	)		(55	)
Cash flows—financing activities:
Issuances of securities:
Long-term debt		—			—			1,800			—			1,800
Common stock		1			—			—			—			1
Retirements/repurchases of securities:
Long-term debt		—			(1	)		(210	)		—			(211	)
Common stock		(10	)		—			—			—			(10	)
Change in short term borrowings		—			—			859			—			859
Cash dividends paid		(397	)		(567	)		(743	)		1,310			(397	)
Change in advances—affiliates		(114	)		—			(660	)		774			—
Other, net		(93	)		—			(15	)		—			(108	)
Cash provided by (used in) financing activities		(613	)		(568	)		1,031			2,084			1,934
Cash flows—investing activities:
Capital expenditures and nuclear fuel		(38	)		—			(1,603	)		—			(1,641	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			104			—			104
Investments in nuclear decommissioning trust fund securities		—			—			(111	)		—			(111	)
Change in advances—affiliates		—			14			764			(778	)		—
Other, net		(1	)		—			143			—			142
Cash provided by (used in) investing activities		(39	)		14			(703	)		(778	)		(1,506	)
Cash flows—discontinued operations:
Operating activities		—			—			24			—			24
Financing activities		—			—			—			—			—
Investing activities		—			—			—			—			—
Cash provided by discontinued operations		—			—			24			—			24
Net change in cash and cash equivalents		—			—			397			—			397
Cash and cash equivalents—beginning balance		—			—			25			—			25
Cash and cash equivalents—ending balance	$	—		$	—		$	422		$	—		$	422

F-40

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2006

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net income	$	1,073		$	1,115		$	1,706		$	(2,821	)	$	1,073
Income from discontinued operations, net of tax		—			—			(60	)		—			(60	)
Income from continuing operations		1,073			1,115			1,646			(2,821	)		1,013
Adjustments to reconcile income from continuing operations to cash provided by (used in) operating activities:
Equity in earnings of subsidiaries		(1,262	)		(1,086	)		(484	)		2,832			—
Depreciation and amortization		—			—			444			—			444
Deferred income tax expense – net		270			—			49			—			319
Impairment and other asset writedown charges		—			—			201			—			201
Net gains from unrealized mark-to-market valuations		—			—			(29	)		—			(29	)
Other, net		1			—			4			—			5
Net changes in operating assets and liabilities		(363	)		618			757			(1,061	)		(49	)
Cash provided by (used in) operating activities		(281	)		647			2,588			(1,050	)		1,904
Cash flows—financing activities:
Issuances of securities:
Long-term debt		—			—			100			—			100
Common stock		180			—			—			—			180
Retirements/repurchases of securities:
Long-term debt		(861	)		(2	)		(662	)		—			(1,525	)
Common stock		(809	)		—			—			—			(809	)
Change in short term borrowings		—			—			1,705			—			1,705
Cash dividends paid		(384	)		(286	)		(742	)		1,028			(384	)
Change in advances—affiliates		1,733			—			691			(2,424	)		—
Other, net		(57	)		—			(16	)		—			(73	)
Cash provided by (used in) financing activities		(198	)		(288	)		1,076			(1,396	)		(806	)
Cash flows—investing activities:
Capital expenditures and nuclear fuel		—			—			(855	)		—			(855	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			144			—			144
Investments in nuclear decommissioning trust fund securities		—			—			(151	)		—			(151	)
Change in advances—affiliates		—			(290	)		(2,156	)		2,446			—
Investment in collateral trust		533			—			(533	)		—			—
Other, net		1			(69	)		(132	)		—			(200	)
Cash provided by (used in) investing activities		534			(359	)		(3,683	)		2,446			(1,062	)
Cash flows—discontinued operations:
Operating activities		—			—			(1	)		—			(1	)
Financing activities		—			—			—			—			—
Investing activities		—			—			—			—			—
Cash used in discontinued operations		—			—			(1	)		—			(1	)
Net change in cash and cash equivalents		55			—			(20	)		—			35
Cash and cash equivalents—beginning balance		—			—			37			—			37
Cash and cash equivalents—ending balance	$	55		$	—		$	17		$	—		$	72

F-41

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets at June 30, 2007

	Millions of Dollars
	Parent/ Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—	$	422	$	—		$	422
Restricted cash		—		—		54		—			54
Advances to parent		—		570		2,451		(3,021	)		—
Trade accounts receivable—net		6		1		1,359		(350	)		1,016
Income taxes receivable		53		—		—		(53	)		—
Accounts receivable from affiliates		—		146		—		(146	)		—
Notes receivable from affiliates		—		—		1,533		(1,533	)		—
Inventories		—		—		428		—			428
Commodity and other derivative contractual assets		11		—		288		—			299
Accumulated deferred income taxes		—		—		835		(6	)		829
Margin deposits related to commodity positions		—		—		448		—			448
Other current assets		2		—		213		(26	)		189
Total current assets		72		717		8,031		(5,135	)		3,685
Restricted cash		—		—		119		—			119
Investments		11,315		6,565		3,610		(20,748	)		742
Property, plant and equipment—net		50		—		19,337		—			19,387
Notes receivable from affiliates		12		—		2,380		(2,392	)		—
Goodwill		—		—		542		—			542
Regulatory assets—net		—		—		1,935		—			1,935
Commodity and other derivative contractual assets		74		—		142		—			216
Accumulated deferred income taxes		113		390		—		(503	)		—
Other noncurrent assets		149		8		240		(35	)		362
Total assets	$	11,785	$	7,680	$	36,336	$	(28,813	)	$	26,988
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	—	$	—	$	2,350	$	—		$	2,350
Advances from affiliates		3,021		—		—		(3,021	)		—
Long-term debt due currently		197		17		578		—			792
Trade accounts payable-nonaffiliates		6		—		1,358		(350	)		1,014
Accounts payable to affiliates		27		—		119		(146	)		—
Notes payable to affiliates		1,500		—		33		(1,533	)		—
Commodity and other derivative contractual liabilities		17		—		412		—			429
Margin deposits related to commodity positions		—		—		35		—			35
Accumulated deferred income taxes		6		—		—		(6	)		—
Other current liabilities		236		8		828		(79	)		993
Total current liabilities		5,010		25		5,713		(5,135	)		5,613
Accumulated deferred income taxes		—		—		3,624		(503	)		3,121
Investment tax credits		—		—		353		—			353
Commodity and other derivative contractual liabilities		125		—		751		—			876
Notes or other liabilities due affiliates		2,035		—		357		(2,392	)		—
Long-term debt, less amounts due currently		3,448		122		8,347		—			11,917
Other noncurrent liabilities and deferred credits		122		—		3,975		(34	)		4,063
Total liabilities		10,740		147		23,120		(8,064	)		25,943
Total shareholders’ equity		1,045		7,533		13,216		(20,749	)		1,045
Total liabilities and shareholders’ equity	$	11,785	$	7,680	$	36,336	$	(28,813	)	$	26,988

F-42

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets at December 31, 2006

	Millions of Dollars
	Parent/ Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—	$	25	$	—		$	25
Restricted cash		—		—		58		—			58
Advances to parent		—		584		1,821		(2,405	)		—
Trade accounts receivable—net		5		1		1,165		(212	)		959
Income taxes receivable		165		—		—		(165	)		—
Accounts receivable from affiliates		—		146		—		(146	)		—
Notes receivable from affiliates		—		—		1,533		(1,533	)		—
Inventories		—		—		383		—			383
Commodity and other derivative contractual assets		2		—		948		—			950
Accumulated deferred income taxes		—		5		253		(5	)		253
Margin deposits related to commodity positions		—		—		7		—			7
Other current assets		8		—		176		(7	)		177
Total current assets		180		736		6,369		(4,473	)		2,812
Restricted cash		—		—		258		—			258
Investments		12,457		6,902		1,682		(20,329	)		712
Property, plant and equipment—net		33		—		18,723		—			18,756
Notes receivable from affiliates		12		700		3,073		(3,785	)		—
Goodwill		—		—		542		—			542
Regulatory assets—net		—		—		2,028		—			2,028
Commodity and other derivative contractual assets		11		—		334		—			345
Accumulated deferred income taxes		118		391		—		(509	)		—
Other noncurrent assets		150		—		245		(15	)		380
Total assets	$	12,961	$	8,729	$	33,254	$	(29,111	)	$	25,833
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term borrowings	$	—	$	—	$	1,491	$	—		$	1,491
Advances from affiliates		2,402		—		—		(2,402	)		—
Long-term debt due currently		—		17		468		—			485
Trade accounts payable—nonaffiliates		18		—		1,286		(211	)		1,093
Accounts payable to affiliates		102		—		47		(149	)		—
Notes payable to affiliates		1,500		—		33		(1,533	)		—
Commodity and other derivative contractual liabilities		21		—		272		—			293
Margin deposits related to commodity positions		—		—		681		—			681
Accumulated deferred income taxes		5		—		—		(5	)		—
Other current liabilities		236		21		955		(172	)		1,040
Total current liabilities		4,284		38		5,233		(4,472	)		5,083
Accumulated deferred income taxes		—		—		4,747		(509	)		4,238
Investment tax credits		—		—		363		—			363
Commodity and other derivative contractual liabilities		63		—		128		—			191
Notes or other liabilities due affiliates		2,714		700		371		(3,785	)		—
Long-term debt, less amounts due currently		3,643		124		6,864		—			10,631
Other noncurrent liabilities and deferred credits		117		—		3,086		(16	)		3,187
Total liabilities		10,821		862		20,792		(8,782	)		23,693
Total shareholders' equity		2,140		7,867		12,462		(20,329	)		2,140
Total liabilities and shareholders' equity	$	12,961	$	8,729	$	33,254	$	(29,111	)	$	25,833

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17. MERGER RELATED TRANSACTIONS

Overview

On October 10, 2007, Energy Future Holdings Corp., a Texas corporation formerly known as TXU Corp., completed its Merger with Merger Sub, a wholly-owned subsidiary of Texas Energy Future Holdings Limited Partnership (Parent). As a result of the Merger, Energy Future Holdings Corp. became a wholly-owned subsidiary of Parent. Parent is controlled by investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners (collectively, the Sponsor Group).

The aggregate purchase price paid for all of the equity securities of TXU Corp. (on a fully-diluted basis) was approximately $32.4 billion, which purchase price was funded by the equity financing from the Sponsor Group and certain other investors and by the new credit facilities described below. These new credit facilities also funded the repayment of existing credit facilities as discussed below. The purchase amount is exclusive of costs directly associated with the Merger, including legal, consulting and other professional service fees and certain effects of the regulatory settlement discussed below.

The Merger is being accounted for under the purchase method of accounting whereby the total cost of the transaction is being allocated to Energy Future Holdings Corp.’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values, and the excess of the purchase price over the fair value of net assets acquired is recorded as goodwill. The allocation of the purchase price to the net assets of Energy Future Holdings Corp. and the resulting goodwill determination are not yet final. The allocation is expected to result in a significant amount of goodwill, an increase in the carrying value of property, plant and equipment and deferred income tax liabilities as well as new identifiable intangible assets and liabilities. Reported earnings in the future will reflect increases in interest, depreciation and amortization expenses.

TCEH Senior Secured Facilities

Overview—In connection with the Merger, TCEH, as borrower, and US Holdings, have entered into a credit agreement, and related security and other agreements, with a group of lenders led by Citibank, N.A. that provides senior secured financing of up to $24.5 billion plus the amount of the TCEH Commodity Collateral Posting Facility (as defined below) (the TCEH Senior Secured Facilities), consisting of:

• a senior secured initial term loan facility (the TCEH Initial Term Loan Facility) in an aggregate principal amount of up to $16.45 billion;

• a senior secured delayed draw term loan facility in an aggregate principal amount of up to $4.1 billion (the TCEH Delayed Draw Term Loan Facility), of which $2.15 billion was drawn at the closing of the Merger;

• a senior secured letter of credit facility in an aggregate principal amount of up to $1.25 billion (the TCEH Letter of Credit Facility);

• a senior secured revolving credit facility in an aggregate principal amount of up to $2.7 billion (the TCEH Revolving Facility), which includes borrowing capacity available for letters of credit and for borrowings on same-day notice; and

• a senior secured cash posting credit facility (the TCEH Commodity Collateral Posting Facility) that is expected to fund the cash posting requirements for a significant portion of TCEH’s long-term hedging program that is not otherwise secured by means of a first lien under the security arrangements described below. The amount drawn on this Facility on October 10, 2007 was $378 million as of October 10, 2007.

Interest Rates and Fees—Loans under the TCEH Senior Secured Facilities (other than the TCEH Commodity Collateral Posting Facility) bear interest at per annum rates equal to, at TCEH’s option, (i) adjusted

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LIBOR plus 3.50% or (ii) a base rate (the higher of (1) the prime rate of Citibank, N.A. and (2) the federal funds effective rate plus 0.50%) plus 2.50%. There is a margin adjustment mechanism in relation to term loans, revolving loans and letters of credit commencing after delivery of the financial statements for the first full fiscal quarter ending after October 10, 2007, under which the applicable margins may be reduced based on leverage ratio targets to be determined.

A commitment fee is payable quarterly in arrears and upon termination at a rate per annum equal to 0.50% of the average daily unused portion of the TCEH Revolving Facility. The commitment fee will be subject to reduction, commencing after delivery of the financial statements for the first full fiscal quarter ending after October 10, 2007, based on leverage ratio targets to be determined.

A commitment fee is payable quarterly in arrears and upon termination on the undrawn portion of the commitments in respect of the TCEH Delayed Draw Term Loan Facility at a rate per annum equal to, prior to the first anniversary of October 10, 2007, 1.25% per annum, and thereafter, 1.50% per annum.

Letter of credit fees under the TCEH Revolving Facility are payable quarterly in arrears and upon termination at a rate per annum equal to the spread over adjusted LIBOR under the TCEH Revolving Facility, less the issuing bank’s fronting fee.

TCEH will pay a fixed quarterly maintenance fee through maturity for having procured the TCEH Commodity Collateral Posting Facility regardless of actual borrowings under the facility. In addition, TCEH will pay interest at LIBOR on actual borrowed amounts under the TCEH Commodity Collateral Posting Facility which will be offset by interest earned on collateral deposits to counterparties, thereby making this facility largely a fixed cost facility regardless of utilization.

Guarantees and Security—Guarantee. The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis, by US Holdings, TCEH and each existing and subsequently acquired or organized direct or indirect wholly-owned U.S. restricted subsidiary of TCEH (other than certain immaterial subsidiaries and other subsidiaries to be agreed upon), subject to certain other exceptions.

Security. The TCEH Senior Secured Facilities, including the guarantees thereof and certain commodity and other hedging and trading transactions, are secured by (a) substantially all of the assets of US Holdings, TCEH and TCEH’s subsidiaries who are guarantors of such facilities as described above, and (b) pledges of the capital stock of TCEH and each material wholly-owned restricted subsidiary of TCEH directly owned by TCEH or any guarantor (limited in the case of pledges of capital stock of any foreign subsidiaries, to 65% of the capital stock of any first-tier material foreign subsidiary).

Covenants—The TCEH Senior Secured Facilities contain customary negative covenants, restricting, subject to certain exceptions, US Holdings, TCEH and TCEH’s restricted subsidiaries from, among other things:

• incurring additional debt;

• incurring additional liens;

• entering into mergers and consolidations;

• sales of assets;

• dividends, redemptions or other distributions in respect of capital stock;

• acquisitions, investments, loans and advances; and

• payments and modifications of certain subordinated and other material debt.

In addition, the TCEH Senior Secured Facilities require that US Holdings, TCEH and their restricted subsidiaries maintain a maximum secured leverage ratio beginning on September 30, 2008 of 7.25 to 1.00 and observe certain customary reporting requirements and other affirmative covenants.

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Maturity and Amortization—The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments beginning on December 31, 2007 in an aggregate annual amount equal to 1% of the original principal amount of such facility, with the balance payable on October 10, 2014. The TCEH Delayed Draw Term Facility is required to be repaid in equal quarterly installments beginning on the last day of the first fiscal quarter to occur after October 10, 2009 in an aggregate annual amount equal to 1% of the actual principal outstanding under the TCEH Delayed Draw Term Loan Facility as of such date, with the balance payable on October 10, 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time from and after the closing date until October 10, 2013. The TCEH Letter of Credit Facility will mature on October 10, 2014. The TCEH Commodity Collateral Posting Facility will mature on December 31, 2012.

Events of Default—The TCEH Senior Secured Facilities contain certain customary events of default for senior leveraged acquisition financings the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments.

Senior Unsecured Bridge Facility—TCEH

Overview—On October 10, 2007, US Holdings, TCEH and TCEH Finance, Inc, a Delaware corporation and wholly-owned subsidiary of TCEH (TCEH Finance and, together with TCEH, the Co-Borrowers), entered into senior unsecured credit facilities (TCEH Unsecured Bridge Facilities).

The TCEH Unsecured Bridge Facilities provide senior unsecured financing of $6.75 billion, consisting of a:

• $5.0 billion senior unsecured cash-pay term loan facility with a term of eight years (the TCEH Initial Cash-Pay Loans); and

• $1.75 billion senior unsecured toggle term loan facility with a term of nine years (the TCEH Initial Toggle Loans and, together with the TCEH Initial Cash-Pay Loans, the TCEH Initial Loans).

If any borrowings under the TCEH Unsecured Bridge Facilities remain outstanding on October 10, 2008, the lenders will have the option to exchange such TCEH Initial Loans for senior cash-pay notes (the TCEH Senior Cash-Pay Exchange Notes) or senior toggle notes (the TCEH Senior Toggle Exchange Notes and, together with the TCEH Senior Cash-Pay Exchange Notes, the TCEH Senior Exchange Notes), respectively, which the Co-Borrowers will issue under a senior indenture. The maturity date of any TCEH Initial Loans that are not exchanged for TCEH Senior Exchange Notes will automatically be extended to the October 10, 2015, in the case of the TCEH Initial Cash-Pay Loans and October 10, 2016 in the case of the TCEH Initial Toggle Loans. The TCEH Senior Cash-Pay Exchange Notes will mature on October 10, 2015, and the TCEH Senior Toggle Exchange Notes will mature on October 10, 2016. Holders of the TCEH Senior Exchange Notes will have registration rights.

Interest Rate—Subject to specified caps, borrowings under the TCEH Unsecured Bridge Facilities for the first six-month period from the closing of the TCEH Unsecured Bridge Facilities will bear interest at a rate equal to LIBOR plus (i) 325 basis points, in the case of the TCEH Initial Cash-Pay Loans and (ii) 350 basis points, in the case of the TCEH Initial Toggle Loans (in each case, the TCEH Initial Margin). Interest for the three-month period commencing at the end of the initial six-month period, subject to specified caps, shall be payable at prevailing LIBOR for the interest period plus the TCEH Initial Margin plus 50 basis points. Thereafter, subject to specified caps, interest will be increased by an additional 25 basis points at the beginning of each three-month period subsequent to the initial nine-month period, for so long as the TCEH Initial Loans are outstanding. If issued, the interest rate on the TCEH Senior Exchange Notes will be the same as the interest rate borne by the TCEH Initial Loans; provided, that if any TCEH Senior Exchange Notes are transferred by the lender to a third-party purchaser, the interest rate on those notes will be fixed at the interest rate in effect on the transfer date.

Prepayments and Redemptions—The Co-Borrowers will be required to make an offer to repay loans under the TCEH Unsecured Bridge Facilities and, following October 10, 2008, repurchase TCEH Senior Exchange

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Notes with net proceeds from specified asset sales. In addition, after any payments required to be made to repay the TCEH Unsecured Bridge Facilities, the Co-Borrowers will be required to offer to repay loans and, if issued, to repurchase the TCEH Senior Exchange Notes upon the occurrence of a change of control. Prior to October 10, 2008, the Co-Borrowers will also be required to prepay outstanding TCEH Initial Loans with the net proceeds of any refinancing debt.

The Co-Borrowers may voluntarily repay outstanding TCEH Initial Loans, in whole or in part, at their option at any time upon three business days’ prior notice, at par plus accrued and unpaid interest and subject to, in the case of TCEH Initial Loans based on LIBOR, customary “breakage” costs with respect to such LIBOR loans, other than customary “breakage” costs with respect to LIBOR loans. The Co-Borrowers may optionally redeem the TCEH Senior Exchange Notes other than fixed-rate exchange notes, if issued, in whole or in part, at any time at par plus accrued and unpaid interest to the redemption date, provided that it also optionally prepays any outstanding TCEH Initial Loans on a pro rata basis.

If any TCEH Senior Exchange Note is sold by a lender to a third-party purchaser, and the interest rate on such TCEH Senior Exchange Note becomes fixed, such TCEH Senior Exchange Note will be non-callable until October 10, 2011, in the case of the TCEH Senior Cash-Pay Exchange Notes, and until October 10, 2012, in the case of the TCEH Senior Toggle Exchange Notes, subject to equity clawback and make-whole provisions consistent with those applicable to the notes offered hereby, and will be callable thereafter at a specified premium. The premium will decline ratably on each yearly anniversary of the date of such sale to zero two years prior to the final maturity date, in the case of the TCEH Senior Cash-Pay Exchange Notes, and one year, in the case of the TCEH Senior Toggle Exchange Notes.

Guarantee—All obligations under the TCEH Unsecured Bridge Facilities and, if the TCEH Senior Exchange Notes are issued, the senior indenture, are jointly and severally guaranteed on a senior basis by US Holdings and each of TCEH’s domestic subsidiaries that guarantees obligations under the TCEH Senior Secured Facilities.

Certain Covenants and Events of Default—The TCEH Unsecured Bridge Facilities and the senior indenture contain a number of covenants that, among other things, restrict, subject to certain exceptions, the Co-Borrowers’ ability to:

• incur additional indebtedness;

• create liens;

• engage in mergers or consolidations;

• sell or transfer assets and subsidiary stock;

• pay dividends and distributions or repurchase their capital stock;

• make certain investments, loans or advances;

• prepay certain indebtedness;

• enter into agreements that restrict the payment of dividends by subsidiaries or the repayment of intercompany loans and advances; and

• engage in certain transactions with affiliates.

In addition, the TCEH Unsecured Bridge Facilities and the senior indenture impose certain requirements as to future subsidiary guarantors. The TCEH Unsecured Bridge Facilities and the senior indenture also contain certain customary affirmative covenants consistent with those in the TCEH Senior Secured Facilities, to the extent applicable, and certain customary events of default.

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Senior Unsecured Bridge Facility – Energy Future Holdings Corp.

Overview—On October 10, 2007, in connection with the Merger and the repayment of certain existing indebtedness, Energy Future Holdings Corp. entered into senior unsecured credit facilities (Energy Future Holdings Corp. Unsecured Bridge Facilities).

Energy Future Holdings Corp.’s Unsecured Bridge Facilities provide senior unsecured financing of $4.5 billion, consisting of a:

• $2.0 billion senior unsecured cash-pay term loan facility with a term of ten years (Energy Future Holdings Corp. Initial Cash-Pay Loans); and

• $2.5 billion senior unsecured toggle term loan facility with a term of ten years (Energy Future Holdings Corp. Initial Toggle Loans and, together with Energy Future Holdings Corp. Initial Cash-Pay Loans, Energy Future Holdings Corp. Initial Loans).

If any borrowings under Energy Future Holdings Corp. Unsecured Bridge Facilities remain outstanding on October 10, 2008, the lenders will have the option at any time or from time to time to exchange such Energy Future Holdings Corp. Initial Loans for senior cash-pay notes (Energy Future Holdings Corp. Senior Cash-Pay Exchange Notes) or senior toggle notes (Energy Future Holdings Corp. Senior Toggle Exchange Notes and, together with Energy Future Holdings Corp. Senior Cash-Pay Exchange Notes, Energy Future Holdings Corp. Senior Exchange Notes) that Energy Future Holdings Corp. will issue under a senior indenture. The maturity date of any Energy Future Holdings Corp. Initial Loans that are not exchanged for Energy Future Holdings Corp. Senior Exchange Notes will automatically be extended to October 10, 2017. Energy Future Holdings Corp. Senior Exchange Notes will also mature on October 10, 2017. Holders of Energy Future Holdings Corp. Senior Exchange Notes will have registration rights.

Interest Rate—Subject to specified caps, borrowings under Energy Future Holdings Corp. Unsecured Bridge Facilities for the first six-month period from the closing of the TCEH Senior Secured Facilities will bear interest at a rate equal to LIBOR plus (i) 400 basis points, in the case of Energy Future Holdings Corp. Initial Cash-Pay Loans and (ii) 425 basis points, in the case of Energy Future Holdings Corp. Initial Toggle Loans (in each case, Energy Future Holdings Corp. Initial Margin). Interest for the three-month period commencing at the end of the initial six-month period, subject to specified caps, shall be payable at prevailing LIBOR for the interest period plus (A) Energy Future Holdings Corp. Initial Margin plus (B) 50 basis points. Thereafter, subject to specified caps, interest will be increased by an additional 25 basis points at the beginning of each three-month period subsequent to the initial nine-month period, for so long as Energy Future Holdings Corp. Initial Loans are outstanding. If issued, the interest rate on Energy Future Holdings Corp. Senior Exchange Notes will be the same as the interest rate borne by Energy Future Holdings Corp. Initial Loans; provided, that if any Energy Future Holdings Corp. Senior Exchange Notes are transferred by the lender to a third-party purchaser, the interest rate on those notes will be fixed at the interest rate in effect on the transfer date.

Prepayments and Redemptions—Energy Future Holdings Corp. will be required to make an offer to repay loans under Energy Future Holdings Corp. Unsecured Bridge Facilities and, following October 10, 2008, repurchase Energy Future Holdings Corp. Senior Exchange Notes with net proceeds from specified asset sales. In addition, after any payments required to be made to repay the TCEH Senior Secured Facilities, Energy Future Holdings Corp. will be required to offer to repay loans and, if issued, to repurchase Energy Future Holdings Corp. Senior Exchange Notes upon the occurrence of a change of control. Prior to October 10, 2008, Energy Future Holdings Corp. will also be required to prepay outstanding Energy Future Holdings Corp. Initial Loans with the net proceeds of any refinancing debt.

Energy Future Holdings Corp. may voluntarily repay outstanding Energy Future Holdings Corp. Initial Loans, in whole or in part, at its option at any time upon three business days’ prior notice, at par plus accrued and unpaid interest and subject to, in the case of Energy Future Holdings Corp. Initial Loans based on LIBOR, customary “breakage” costs with respect to such LIBOR loans, other than customary “breakage” costs with respect to LIBOR loans. Energy Future Holdings Corp. may optionally redeem Energy Future Holdings Corp.

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Senior Exchange Notes other than fixed-rate exchange notes, if issued, in whole or in part, at any time at par plus accrued and unpaid interest to the redemption date, provided that it also optionally prepays any outstanding Energy Future Holdings Corp. Initial Loans on a pro rata basis.

If any Energy Future Holdings Corp. Senior Exchange Note is sold by a lender to a third-party purchaser, and the interest rate on such Energy Future Holdings Corp. Senior Exchange Note becomes fixed, such Energy Future Holdings Corp. Senior Exchange Note will be non-callable for the first four years from October 10, 2008, subject to equity clawback and make-whole provisions consistent with those applicable to the notes offered hereby, and will be callable thereafter at a specified premium. The premium will decline ratably on each yearly anniversary of the date of such sale to zero on October 10, 2015.

Guarantee—All obligations under Energy Future Holdings Corp. Unsecured Bridge Facilities and, if Energy Future Holdings Corp. Senior Exchange Notes are issued, the senior indenture are jointly and severally guaranteed on a senior unsecured basis by Intermediate Holding and US Holdings.

Certain Covenants and Events of Default—Energy Future Holdings Corp. Unsecured Bridge Facilities and the senior indenture contain a number of covenants that, among other things, restrict, subject to certain exceptions, Energy Future Holdings Corp.’s ability to:

• incur additional indebtedness;

• create liens;

• engage in mergers or consolidations;

• sell or transfer assets and subsidiary stock;

• pay dividends and distributions or repurchase its capital stock;

• make certain investments, loans or advances;

• prepay certain indebtedness;

• enter into agreements that restrict the payment of dividends by subsidiaries or the repayment of intercompany loans and advances; and

• engage in certain transactions with affiliates.

In addition, Energy Future Holdings Corp. Unsecured Bridge Facilities and the senior indenture impose certain requirements as to future subsidiary guarantors. Energy Future Holdings Corp. Unsecured Bridge Facilities and the senior indenture also contain certain customary affirmative covenants consistent with those in TCEH Senior Secured Facilities, to the extent applicable.

Intercreditor Agreement

On October 10, 2007, in connection with the Merger, TCEH, US Holdings and the subsidiary guarantors under the TCEH Senior Secured Facilities entered into a Collateral Agency and Intercreditor Agreement (the Intercreditor Agreement) with Citibank, N.A., and four secured commodity hedge counterparties (Secured Commodity Hedge Counterparties).

The Intercreditor Agreement provides that the lien granted to the Secured Commodity Hedge Counterparties should rank pari passu with the lien granted to the secured parties under the TCEH Senior Secured Facilities on the collateral under the TCEH Senior Secured Facilities and the Secured Commodity Hedge Counterparties will be entitled to share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral in an amount provided in the TCEH Credit Agreement. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will have voting rights with respect to any amendment or waiver of any provision of the Intercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties’ lien on such collateral relative to the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to the Secured Commodity

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Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the lien granted to the secured parties under the TCEH Senior Secured Facilities.

Revolving Credit Facility—Oncor

Overview—Oncor has entered into a revolving credit agreement (the Oncor Credit Agreement) to provide for a secured revolving credit facility in an aggregate principal amount of up to $2.0 billion (the Oncor Revolving Credit Facility).

Interest Rates and Fees—Loans under the Oncor Revolving Credit Facility bear interest at per annum rates equal to, at Oncor’s option, (i) adjusted LIBOR plus a spread of 0.275% to 0.800% (which spread shall depend on the rating assigned to Oncor’s senior secured debt) or (ii) a base rate (the higher of (1) the prime rate of JPMorgan Chase Bank, N.A. and (2) the federal funds effective rate plus 0.50%). Based on Oncor’s current ratings, its LIBOR-based borrowings will bear interest at LIBOR plus 0.575%.

A facility fee is payable quarterly in arrears and upon termination or commitment reduction at a rate per annum equal to 0.100% to 0.200% (such spread shall depend on the rating assigned to Oncor’s senior secured debt) of the commitments under the Oncor Revolving Credit Facility. Based on Oncor’s current ratings, its facility fee will be 0.175%.

A utilization fee is payable quarterly in arrears and upon termination on the average daily amount outstanding (to the extent of borrowings in excess of 50% of the commitments) under the Oncor Revolving Credit Facility at a rate per annum equal to 1.25% per annum.

Letter of credit fees under the Oncor Revolving Credit Facility are payable quarterly in arrears and upon termination at a rate per annum equal to the spread over adjusted LIBOR under the Oncor Revolving Credit Facility, less the issuing bank’s fronting fee.

Security—The Oncor Revolving Credit Facility, including hedging transactions, will be secured, on a post-closing basis, by certain of Oncor’s assets used in connection with its the transmission and distribution business.

Covenants—The Oncor Revolving Credit Facility contains customary covenants for facilities of this type, restricting, subject to certain exceptions, Oncor and its subsidiaries from, among other things:

• incurring additional liens;

• entering into mergers and consolidations;

• sales of substantial assets; and

• acquisitions and investments in subsidiaries.

In addition, the Oncor Revolving Credit Facility requires that Oncor maintain a maximum consolidated senior debt to capitalization ratio of 0.65 to 1.00 and observe certain customary reporting requirements and other affirmative covenants.

Maturity—Amounts borrowed under the Oncor Revolving Credit Facility may be reborrowed from time to time from and after October 10, 2007 until October 10, 2013.

Events of Default -The Oncor Revolving Credit Facility contains certain customary events of default for facilities of this type the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments.

TXU Receivables Program

Also in connection with the Merger, the accounts receivable securitization program was amended. Concurrently, the financial institutions required that Oncor Electric Delivery repurchase all of the receivables it had previously sold to TXU Receivables Company totaling $113 million, which amount was refinanced by the Oncor Electric Delivery Revolving Facility.

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Repayment of Existing Credit Facilities

On October 10, 2007, in connection with the Merger, TCEH and Oncor repaid in full all outstanding borrowings totaling $2.4 billion together with interest and all other amounts due in connection with such repayment under the $6.5 billion of existing credit facilities. TCEH and Oncor also repaid floating rate senior notes with an aggregate principal amount of $1.0 billion and $800 million, respectively. (See Note 8).

Management Agreement

On October 10, 2007, in connection with the Merger, Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P., Goldman, Sachs & Co. and Lehman Brothers Inc. entered into a management agreement with Energy Future Holdings Corp. (the Management Agreement), pursuant to which affiliates of the investors will provide management, consulting, financial and other advisory services to Energy Future Holdings Corp. Pursuant to the Management Agreement, the Sponsor Group is entitled to receive an aggregate annual management fee of $35.0 million, which amount will increase 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of Energy Future Holdings Corp. or in connection with an initial public offering of Energy Future Holdings Corp. or if the parties mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, the Sponsor Group is also entitled to receive aggregate transaction fees of $300 million in connection with certain services provided in connection with the Merger and related transactions. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances.

Tax Sharing Agreement

In connection with the Merger, on October 10, 2007, Oncor, Oncor Holdings and Energy Future Holdings Corp. entered into a tax sharing agreement stating that, among other things, the allocation of tax liability to each of Oncor Holdings and Oncor will occur substantially as if these entities were stand-alone corporations and will require tax payments determined on that basis (without duplication for taxes paid by a subsidiary of Oncor or Oncor Holdings).

Oncor Limited Liability Company Agreement

In connection with the Merger, Oncor was converted from a Texas corporation to a Delaware limited liability company under the laws of the States of Texas and Delaware and entered into a limited liability company agreement (as amended, the Oncor LLC Agreement). The Oncor LLC Agreement provides that the independent directors of Oncor (who must comprise a majority of the members of Oncor’s board of directors), acting by majority vote, shall have the authority to prevent Oncor from making any distribution if they determine that it is in Oncor’s best interests to retain such amounts to meet expected future requirements (including continued compliance with the debt-to-equity ratio established from time to time by the Public Utility Commission of the State of Texas for ratemaking purposes). The Oncor LLC Agreement also provides that the Board of Directors of Oncor shall not distribute any amounts to Oncor’s member(s) to the extent that the Board of Directors of Oncor determines in good faith that it is necessary to retain such amounts to meet expected future requirements of the applicable entity. In addition to such restrictions on distributions, the Oncor LLC Agreement contains certain separateness provisions that require Oncor to conduct its activities separate and distinct from the activities of Energy Future Holdings Corp. and its other subsidiaries, including, without limitation, holding itself out as a separate legal entity.

F-51

Tender Offers and Consent Solicitations

On September 25, 2007, Energy Future Holdings Corp. commenced offers to purchase and consent solicitations with respect to $1.0 billion in aggregate principal amount of Energy Future Holdings Corp.’s outstanding 4.80% Series O Senior Notes due 2009, $250 million in aggregate principal amount of TCEH’s outstanding 6.125% Senior Notes due 2008 and $1.0 billion in aggregate principal amount of TCEH’s outstanding 7.000% Senior Notes due 2013. On the closing date of the Merger, Energy Future Holdings Corp. purchased an aggregate of $996 million, $247 million and $995 million of these notes, respectively.

Oncor Agreement in Principle with Stakeholders and PUCT Staff

On October 5, 2007, Oncor and Texas Energy Future Holdings Limited Partnership (TEF) reached an agreement in principle with major interested parties to resolve all outstanding issues in the PUCT review related to the proposed merger of TXU Corp. with Merger Sub including the outstanding rate case. TEF was formed by a group of investors led by Kohlberg Kravis Roberts & Co. (KKR) and Texas Pacific Group (TPG) to facilitate the merger. The agreement, which was filed with the PUCT, was conditional upon the completion of the Merger and is subject to approval by the PUCT.

In addition to commitments Oncor made in its filings in the PUCT review, the stipulated agreement includes the following provisions, among others:

• Oncor will agree to $72 million in rate refunds, which is intended for all retail customers in its service territory, which will be requested by the parties to the settlement agreement. It is the intent of the parties to the agreement that the benefits of the credit flow directly to consumers, rather than to retail electric providers.

• The PUCT will dismiss Oncor’s Electric Delivery pending rate case. Consistent with its existing agreement with the cities it serves, Oncor will file a system-wide rate case no later than July 1, 2008 based on a test-year ended December 31, 2007.

• Oncor will write off regulatory assets of approximately $56 million related to storm costs and 2002 restructuring expenses.

• TEF and Oncor will limit the dividends paid by Oncor through December 31, 2012, to an amount not to exceed Oncor’s net income (determined in accordance with GAAP), subject to certain defined adjustments.

• Oncor will commit to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions.

• Oncor will commit to $100 million in spending over the five-year period ending December 31, 2012 on demand side management or other energy efficiency initiatives. This spending will not be recoverable in rates.

F-52

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Energy Future Holdings Corp.:

We have audited the accompanying consolidated balance sheets of Energy Future Holdings Corp. (formerly known as TXU Corp.) and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related statements of consolidated income, comprehensive income, cash flows and shareholders’ equity for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy Future Holdings Corp. and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 5 to the Notes to Financial Statements, the Company changed its method of accounting for stock based compensation with the election to early adopt Statement of Financial Accounting Standards No. 123 (revised 2004) Share-Based Payment, effective October 1, 2004.

/s/     Deloitte & Touche LLP

Dallas, Texas

March 1, 2007

(October 16, 2007 as to Note 26)

F-53

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars, except per share amounts)
Operating revenues	$	10,856		$	10,662		$	9,216
Costs and expenses:
Fuel, purchased power costs and delivery fees		2,784			4,261			3,755
Operating costs		1,373			1,425			1,429
Depreciation and amortization		830			776			760
Selling, general and administrative expenses		819			781			1,091
Franchise and revenue-based taxes		390			364			367
Other income		(121	)		(151	)		(148	)
Other deductions		269			45			1,172
Interest income		(46	)		(48	)		(28	)
Interest expense and related charges		830			802			695
Total costs and expenses		7,128			8,255			9,093
Income from continuing operations before income taxes, extraordinary gain (loss) and cumulative effect of changes in accounting principles		3,728			2,407			123
Income tax expense		1,263			632			42
Income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles		2,465			1,775			81
Income from discontinued operations, net of tax effect (Note 3)		87			5			378
Extraordinary gain (loss), net of tax effect (Note 4)		—			(50	)		16
Cumulative effect of changes in accounting principles, net of tax effect (Note 5)		—			(8	)		10
Net income	$	2,552		$	1,722		$	485
Exchangeable preferred membership interest buyback premium (Note 17)		—			—			849
Preference stock dividends		—			10			22
Net income (loss) available for common stock	$	2,552		$	1,712		$	(386	)
Average shares of common stock outstanding (millions):
Basic		460			476			600
Diluted		467			486			600
Per share of common stock—Basic:
Net income (loss) from continuing operations available for common stock	$	5.36		$	3.71		$	(1.32	)
Income from discontinued operations, net of tax effect		0.19			0.01			0.63
Extraordinary gain (loss), net of tax effect		—			(0.10	)		0.03
Cumulative effect of changes in accounting principles, net of tax effect		—			(0.02	)		0.02
Net income (loss) available for common stock	$	5.55		$	3.60		$	(0.64	)
Per share of common stock—Diluted:
Net income (loss) from continuing operations available for common stock	$	5.27		$	2.61		$	(1.32	)
Income from discontinued operations, net of tax effect		0.19			0.01			0.63
Extraordinary gain (loss), net of tax effect		—			(0.10	)		0.03
Cumulative effect of changes in accounting principles, net of tax effect		—			(0.02	)		0.02
Net income (loss) available for common stock	$	5.46		$	2.50		$	(0.64	)
Dividends declared	$	1.67		$	1.26		$	0.47

See Notes to Financial Statements.

F-54

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Components related to continuing operations:
Income from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles	$	2,465		$	1,775		$	81
Other comprehensive income (loss), net of tax effects:
Minimum pension liability adjustments (net of tax (expense) benefit of ($38), $25 and ($7))		71			(46	)		14
Cash flow hedges:
Net change in fair value of derivatives held at end of period (net of tax (expense) benefit of $(304), $24 and $40)		568			(47	)		(75	)
Derivative value net losses (gains) reported in net income that relate to hedged transactions recognized in the period (net of tax (expense) benefit of $(8), $42 and $23)		(15	)		77			44
Total effect of cash flow hedges		553			30			(31	)
Total adjustments to net income from continuing operations		624			(16	)		(17	)
Comprehensive income from continuing operations		3,089			1,759			64
Components related to discontinued operations:
Income from discontinued operations, net of tax effect		87			5			378
Minimum pension liability adjustments (net of tax expense of $—, $— and $5)		—			—			10
Cumulative foreign currency translation adjustment		—			—			(145	)
Cash flow hedges:
Derivative value net gains reported in net income that relate to hedged transactions recognized in the period (net of tax expense of $—, $— and $3)		—			—			(6	)
Total adjustments to net income from discontinued operations		—			—			(141	)
Comprehensive income from discontinued operations		87			5			237
Extraordinary gain (loss), net of tax effect		—			(50	)		16
Cumulative effect of changes in accounting principles, net of tax effect		—			(8	)		10
Comprehensive income	$	3,176		$	1,706		$	327

See Notes to Financial Statements.

F-55

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Cash flows—operating activities:
Net income	$	2,552		$	1,722		$	485
Income from discontinued operations, net of tax effect		(87	)		(5	)		(378	)
Extraordinary (gain) loss, net of tax effect		—			50			(16	)
Cumulative effect of changes in accounting principles, net of tax effect		—			8			(10	)
Income from continuing operations before extraordinary (gain) loss and cumulative effect of changes in accounting principles		2,465			1,775			81
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		893			836			826
Deferred income tax expense, including utilization of net operating loss carryforwards		756			481			(11	)
Losses on early extinguishment of debt		1			—			416
Asset writedown charges		6			11			196
Charge (credit) related to impaired leases		(2	)		(16	)		180
Net gains on sale of assets, including amortization of deferred gains		(69	)		(89	)		(135	)
Net effect of unrealized mark-to-market valuations		(272	)		18			109
Impairment of natural gas-fueled generation plants		198			—			—
Customer appreciation bonus charge (net of amounts credited to customers in 2006)		122			—			—
Shareholders’ litigation settlement accrual		—			—			84
Bad debt expense		68			56			90
Stock-based incentive compensation expense		27			32			56
Recognition of losses on dedesignated cash flow hedges		12			20			26
Recognition of gain on dedesignated fair value hedges		(6	)		(10	)		(15	)
Charge related to coal contract counterparty claim		—			12			—
Net equity loss (income) from unconsolidated affiliate		14			—			(1	)
Change in regulatory-related liabilities		1			(81	)		(70	)
Changes in operating assets and liabilities:
Accounts receivable—trade		337			(335	)		(246	)
Impact of accounts receivable sales program		(44	)		197			(73	)
Inventories		(21	)		(55	)		15
Accounts payable—trade		(219	)		(47	)		223
Commodity contract assets and liabilities		—			76			(5	)
Cash flow hedge and other derivative assets and liabilities		—			(9	)		(22	)
Margin deposits—net		564			61			34
Other—net assets		(92	)		35			(165	)
Other—net liabilities		215			(175	)		165
Cash provided by operating activities of continuing operations		4,954			2,793			1,758
Cash flows—financing activities:
Issuances of securities:
Long-term debt		243			180			5,090
Common stock		180			83			112

F-56

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS (cont.)

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Retirements/repurchases of securities:
Long-term debt held by subsidiary trusts		—			—			(546	)
Equity-linked debt securities		(179	)		(106	)		(1,105	)
Other long-term debt		(1,512	)		(269	)		(3,088	)
Exchangeable preferred membership interests		—			—			(750	)
Preference stock		—			(300	)		—
Preferred securities of subsidiaries		—			(38	)		(75	)
Common stock		(1,012	)		(1,137	)		(4,687	)
Change in short-term borrowings:
Commercial paper		939			358			—
Banks		(245	)		230			210
Cash dividends paid:
Common stock		(764	)		(544	)		(150	)
Preference stock		—			(11	)		(22	)
Premium paid for redemption of exchangeable preferred membership interests		—			—			(1,102	)
Excess tax benefit on stock-based incentive compensation		41			28			—
Debt premium, discount, financing and reacquisition expenses		(23	)		(37	)		(406	)
Cash used in financing activities of continuing operations		(2,332	)		(1,563	)		(6,519	)
Cash flows—investing activities:
Capital expenditures		(2,180	)		(1,047	)		(912	)
Nuclear fuel		(117	)		(57	)		(87	)
Dispositions of businesses		—			—			4,814
Purchase of lease trust		(69	)		—			—
Proceeds from sales of assets		20			77			27
Change in collateral trust		—			—			525
Proceeds from sales of nuclear decommissioning trust fund securities		207			191			88
Investments in nuclear decommissioning trust fund securities		(223	)		(206	)		(103	)
Investment in unconsolidated affiliate		(15	)		—			—
Proceeds from pollution control revenue bonds deposited with trustee		(240	)		—			—
Costs to remove retired property		(40	)		(44	)		(40	)
Other		(7	)		48			(32	)
Cash provided by (used in) investing activities of continuing operations		(2,664	)		(1,038	)		4,280
Discontinued operations:
Cash provided by (used in) operating activities		30			(265	)		(79	)
Cash used in financing activities		—			—			(10	)
Cash provided by (used in) investing activities		—			4			(153	)
Cash provided by (used in) discontinued operations		30			(261	)		(242	)
Net change in cash and cash equivalents		(12	)		(69	)		(723	)
Cash and cash equivalents—beginning balance		37			106			829
Cash and cash equivalents—ending balance	$	25		$	37		$	106

See Notes to Financial Statements.

F-57

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2006		2005
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	25	$	37
Restricted cash		58		54
Trade accounts receivable—net (Note 13)		959		1,328
Income taxes receivable		—		14
Inventories		383		364
Commodity contract assets (Note 18)		276		1,603
Cash flow hedge and other derivative assets (Note 19)		698		65
Accumulated deferred income taxes (Note 11)		253		717
Margin deposits related to commodity positions		7		247
Other current assets		178		129
Total current assets		2,837		4,558
Restricted cash		258		16
Investments		712		643
Property, plant and equipment—net		18,756		17,192
Goodwill		542		542
Regulatory assets—net		2,028		1,826
Commodity contract assets (Note 18)		162		338
Cash flow hedge and other derivative assets (Note 19)		248		75
Other noncurrent assets		379		349
Total assets	$	25,922	$	25,539
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings (Note 14)	$	1,491	$	798
Long-term debt due currently (Note 15)		485		1,250
Trade accounts payable		1,093		1,026
Commodity contract liabilities (Note 18)		278		1,481
Cash flow hedge and other derivative liabilities (Note 19)		39		275
Margin deposits related to commodity positions		681		357
Other current liabilities		1,040		1,163
Total current liabilities		5,107		6,350
Accumulated deferred income taxes (Note 11)		4,238		3,697
Investment tax credits		363		384
Commodity contract liabilities (Note 18)		183		516
Cash flow hedge and other derivative liabilities (Note 19)		73		91
Long-term debt, less amounts due currently (Note 15)		10,631		11,332
Other noncurrent liabilities and deferred credits		3,187		2,694
Total liabilities		23,782		25,064
Commitments and Contingencies (Note 16)
Shareholders’ equity (Note 17)		2,140		475
Total liabilities and shareholders’ equity	$	25,922	$	25,539

See Notes to Financial Statements.

F-58

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED SHAREHOLDERS’ EQUITY

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Common stock without par value (number of authorized shares—1,000,000,000):
Balance at beginning of year		5			2			48
Effect of two-for-one stock split		—			3			—
Issuances under Direct Stock Purchase and Dividend Reinvestment Plan		—			—			4
Effects of stock-based incentive compensation plans		—			—			5
Issuance of shares under equity-linked debt securities		—			—			101
Value of Thrift Plan shares released by LESOP trustee (Note 21)		—			—			3
Cancellation of repurchased common stock		—			—			(161	)
Other		—			—			2
Balance at end of year (number of shares outstanding: 2006—459,244,523; 2005—470,845,978; and 2004—479,705,760)		5			5			2
Additional paid-in capital:
Balance at beginning of year		1,840			2,806			8,097
Common stock repurchases		(1,012	)		(1,092	)		(4,737	)
Net premium on repurchase of exchangeable preferred membership interests		—			—			(849	)
Discount (premium) on repurchase of equity-linked debt securities (related to equity component) and reversal of contract adjustment payment liability		—			(13	)		96
Effects of stock-based incentive compensation plans		27			33			38
Excess tax benefit on stock-based compensation		41			28			—
Cancellation of repurchased common stock		—			—			161
Issuance of shares under equity-linked debt securities		180			75			—
Value of Thrift Plan shares released by LESOP trustee (Note 21)		2			1			—
Effects of executive deferred compensation plan		13			—			—
Effect of two-for-one stock split		—			(3	)		—
Other		13			5			—
Balance at end of year	$	1,104		$	1,840		$	2,806
Retained earnings:
Balance at beginning of year	$	(1,168	)	$	(2,283	)	$	(2,498	)
Net income		2,552			1,722			485
Dividends declared on common stock ($1.67, $1.26 and $0.47 per share)		(768	)		(598	)		(251	)
Dividends on preference stock ($0, $3,278 and $7,240 per share)		—			(10	)		(22	)
LESOP dividend deduction tax benefit and other		6			1			3
Balance at end of year		622			(1,168	)		(2,283	)
Accumulated other comprehensive gain (loss), net of tax effects:
Foreign currency translation adjustments:
Balance at beginning of year		—			—			145
Change during the year		—			—			(90	)
Amounts related to disposed businesses		—			—			(55	)
Balance at end of year		—			—			—

F-59

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED SHAREHOLDERS’ EQUITY (cont.)

	Year Ended December 31,
	2006			2005			2004
	(millions of dollars)
Pension and other postretirement employee benefit liability adjustments:
Balance at beginning of year		(60	)		(14	)		(38	)
Change in minimum pension liability		71			(46	)		23
SFAS 158 transition adjustment		(13	)		—			—
Amounts related to disposed businesses		—			—			1
Balance at end of year		(2	)		(60	)		(14	)
Amounts related to cash flow hedges:
Balance at beginning of year		(142	)		(172	)		(135	)
Change during the year		553			30			(38	)
Amounts related to disposed businesses		—			—			1
Balance at end of year		411			(142	)		(172	)
Total accumulated other comprehensive gain (loss) at end of year		409			(202	)		(186	)
Total common stock equity at end of year		2,140			475			339
Preference stock:
Balance at beginning of year	$	—		$	300		$	300
Preference stock redemption		—			(300	)		—
Balance at end of year		—			—			300
Shareholders’ equity at end of year	$	2,140		$	475		$	639

See Notes to Financial Statements.

F-60

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING POLICIES

Description of Business—Energy Future Holdings Corp. (formerly named TXU Corp.) is a holding company conducting its operations principally through its Texas Competitive Electric Holdings Company LLC (Texas Competitive Holdings), Oncor Electric Delivery Company (Oncor Electric Delivery) and TXU Generation Development Company LLC (TXU DevCo) subsidiaries. Texas Competitive Holdings is a holding company whose subsidiaries are engaged in competitive market activities consisting of electricity generation, retail electricity sales to residential and business customers, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. Oncor Electric Delivery is engaged in regulated electricity transmission and distribution operations in Texas. TXU DevCo is engaged in the development of new lignite/coal-fueled generation facilities.

On February 26, 2007, Energy Future Holdings Corp. announced that it had entered into a Merger Agreement, with Merger Sub Parent and Merger Sub, whereby Energy Future Holdings Corp. would merge with Merger Sub and Energy Future Holdings Corp. would become a wholly-owned subsidiary of Merger Sub Parent. See Note 26.

Energy Future Holdings Corp. has two reportable segments: the Competitive Electric segment (which includes Texas Competitive Holdings and TXU DevCo’s activities) and the Regulated Delivery segment. (See Note 24 for further information concerning reportable business segments.)

Basis of Presentation—The consolidated financial statements of Energy Future Holdings Corp. have been prepared in accordance with accounting principles generally accepted in the US and on the same basis as the audited financial statements included in Energy Future Holdings Corp.’s Annual Report on Form 10-K for the year ended December 31, 2005, except for the reporting of wholesale electricity trading activities and ERCOT electricity balancing transactions as discussed below under “Revenue Recognition.” All other adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. As discussed below, certain reclassifications have been made to conform prior period data to current period presentation. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

Commodity contract and derivative assets and liabilities and margin deposits reported in the consolidated balance sheet each reflect counterparty netting in accordance with legal right of offset agreements.

Discontinued Businesses—Note 3 presents detailed information regarding the effects of discontinued businesses, the results of which have been classified as discontinued operations.

Use of Estimates—Preparation of Energy Future Holdings Corp.’s financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including mark-to-market valuation adjustments. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.

Earnings Per Share—Basic earnings per share available to common shareholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share include the effect of all potential issuances of common shares under stock-based employee compensation and certain debt arrangements. The 2005 diluted per share results reflect an unfavorable impact associated with the

F-61

November 2004 accelerated share repurchase program which was settled in May 2005. The program is discussed in Note 17. Because Energy Future Holdings Corp. intended to settle in cash the difference between the initial price of the shares and the actual costs of the shares purchased by the counterparty under the program, accounting rules require that earnings used in the diluted earnings per share calculation be reduced by the change in the fair value of the settlement liability during the year, which totaled $498 million (without tax benefit). See Note 2 for a reconciliation of basic earnings per share to diluted earnings per share.

Derivative Instruments and Mark-to-Market Accounting—Energy Future Holdings Corp. enters into contracts for the purchase and sale of electricity, natural gas and other commodities and also enters into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. If the instrument meets the definition of a derivative under SFAS 133, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses, unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the balance sheet. This recognition is referred to as “mark-to-market” accounting. The fair values of Energy Future Holdings Corp.’s unsettled commodity-related derivative instruments under mark-to-market accounting are reported in the balance sheet as commodity contract assets or liabilities. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. Under the exception criteria of SFAS 133, Energy Future Holdings Corp. may elect the “normal” purchase and sale exemption; further, Energy Future Holdings Corp. may designate derivatives as a cash flow or fair value hedge. A derivative contract may be designated as a “normal” purchase or sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market).

Because derivative instruments are frequently used as economic hedges, SFAS 133 allows the designation of these hedges as cash flow or fair value hedges provided certain conditions are met. A cash flow hedge mitigates the risk associated with variable future cash flows (e.g., a forecasted sale of electricity in the future at market prices), while a fair value hedge mitigates risk associated with fixed future cash flows (e.g., debt with fixed interest rate payments). In accounting for changes in value of cash flow hedges, derivative assets and liabilities are recorded on the balance sheet with an offset to other comprehensive income or loss to the extent the hedges are effective and the hedged transaction remains probable of occurring. If the hedged transaction is no longer probable of occurring, hedge accounting is discontinued. Amounts recorded in other comprehensive income are reclassified into net income as the related hedged transactions settle and affect earnings. If the hedged transaction becomes probable of not occurring, the amount recorded in other comprehensive income is immediately reclassified to net income. Changes in value of fair value hedges are recorded as derivative assets or liabilities with an offset to net income, and the carrying value of the related asset or liability (hedged item) is adjusted for the change in fair value with an offset to net income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or loss is amortized into income over the remaining life of the hedged item. In the statement of cash flow, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions.

To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedged item. Assessment of the hedge’s effectiveness is tested at least quarterly throughout its term to continue to qualify for hedge accounting. Changes in fair value that represent hedge ineffectiveness, even if the hedge continues to be assessed as effective, are immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the change in value of the hedging instrument over the change in value of the hedged item. The “short-cut” method under SFAS 133 allows entities to assume no hedge ineffectiveness in a hedging relationship of interest rate risk if certain conditions are met. If all short-cut conditions are met, then the hedge results in no ineffectiveness gains and losses, as the hedge is considered 100% effective, and no future effectiveness testing is required. See Notes 15, 18 and 19 for additional details concerning hedging activity.

Revenue Recognition—Energy Future Holdings Corp. records revenue from electricity sales and delivery service under the accrual method of accounting. Revenues are recognized when electricity or delivery services

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are provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue).

Under a realignment of the wholesale energy operations effective January 1, 2006, management of wholesale purchases and sales of electricity for purposes of balancing electricity supply and demand was segregated from the buying and selling of electricity for trading purposes. Previously, all wholesale electricity purchases and sales were managed in aggregate under a “portfolio management” structure, as the primary activity was energy balancing, and all wholesale activity utilized (and continues to utilize) contracts for physical delivery. Financial derivative instruments, as are common in natural gas markets, are not as readily available in the Texas electricity market. The realignment reflects an expectation of a growing market for electricity trading in Texas. Under the previous structure, all purchases and sales scheduled with ERCOT for delivery were reported gross in the income statement, and “booked-out” sales and purchases (agreement with the counterparty to net settle before scheduling for delivery) were reported net. Effective with the January 1, 2006 realignment, those contracts that are separately managed as a trading book and scheduled for physical delivery are reported net upon settlement in accordance with existing accounting rules (EITF 02-3). All transactions reported net, including booked-out contracts, are reported as a component of revenues. Gross revenues from electricity trading activities totaled $1.3 billion in 2006.

In addition, Energy Future Holdings Corp. revised its reporting of ERCOT electricity balancing transactions effective with 2006 reporting. These transactions represent wholesale purchases and sales of electricity for real-time balancing purposes as measured in 15-minute intervals. As is industry practice, these purchases and sales with ERCOT, as the balancing energy clearinghouse agent, are reported net. Energy Future Holdings Corp. had historically reported the net amount as a component of purchased power cost as the activity consistently represented a net purchase of electricity prior to 2005 due in part to Energy Future Holdings Corp.’s retail load exceeding generation volumes. More recently, the balancing activity has frequently resulted in net revenues due in part to generation volumes increasingly exceeding retail load. Energy Future Holdings Corp. believes that presentation of this activity as a component of revenues more appropriately reflects Energy Future Holdings Corp.’s market position. Accordingly, net electricity balancing transactions are reported in revenues and the prior years’ amounts have been reclassified. The amount reported in revenues totaled $31 million in net purchases in 2006, $225 million in net sales in 2005 and $92 million in net purchases in 2004.

Realized and unrealized gains and losses from transacting in energy-related derivative instruments are reported as a component of revenues. See discussion above under “Derivative Instruments and Mark-to-Market Accounting.”

Impairment of Long-Lived Assets—Energy Future Holdings Corp. evaluates long-lived assets for impairment whenever indications of impairment exist, in accordance with SFAS 144. The determination of the existence of indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets. See Note 6 for details of the impairment of the natural gas-fueled generation plants recorded in the second quarter of 2006.

Amortization of Nuclear Fuel—Amortization of nuclear fuel is calculated on the units-of-production method and is reported as fuel costs.

Major Maintenance—Major maintenance costs incurred during generation plant outages, as well as the costs of other maintenance activities, are charged to expense as incurred. This accounting is consistent with guidance issued by the FASB as discussed below under “Changes in Accounting Standards”.

Defined Benefit Pension Plans and Other Postretirement Employee Benefit Plans—Energy Future Holdings Corp. offers pension benefits through either a defined benefit pension plan or a cash balance plan and also offers certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from Energy Future Holdings Corp. Costs of pension and other postretirement

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employee benefits (OPEB) plans are determined in accordance with SFAS 87 and SFAS 106 and are dependent upon numerous factors, assumptions and estimates. Effective December 31, 2006, Energy Future Holdings Corp. adopted SFAS 158, as required. See Note 21 for details with respect to the adoption of this standard and other information regarding pension and OPEB plans.

Stock-Based Incentive Compensation—Energy Future Holdings Corp. has provided discretionary awards to qualified managerial employees payable in its common stock under its shareholder-approved long-term incentive plans. Energy Future Holdings Corp. accounts for these awards based on the provisions of SFAS 123R, which provides for the recognition of stock-based compensation expense over the vesting period based on the grant-date fair value of those awards. See Note 22 for information regarding stock-based incentive compensation.

Sales and Excise Taxes—Sales and excise taxes are accounted for as a “pass through” item on the balance sheet; i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction.

Franchise and Revenue-Based Taxes—Franchise and gross receipt taxes are not a “pass through” item such as sales and excise taxes. These taxes are assessed to Energy Future Holdings Corp. by state and local government bodies, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates charged to customers by Energy Future Holdings Corp. are intended to recover the taxes, but Energy Future Holdings Corp. is not acting as an agent to collect the taxes from customers.

Income Taxes—Energy Future Holdings Corp. files a consolidated federal income tax return, and federal income taxes are allocated to subsidiaries based on their respective taxable income or loss. Investment tax credits are amortized to income over the estimated lives of the properties. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Certain provisions of SFAS 109 provide that regulated enterprises are permitted to recognize deferred taxes as regulatory tax assets or tax liabilities if it is probable that such amounts will be recovered from, or returned to, customers in future rates.

Energy Future Holdings Corp. has generally accounted for uncertainty related to positions taken on tax returns based on the probable liability approach consistent with SFAS 5. FIN No. 48, as discussed below under “Changes in Accounting Standards”, provides clarification of the accounting for uncertain income tax positions.

Accounting for Contingencies—The financial results of Energy Future Holdings Corp. may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 16 for a discussion of contingencies.

Cash Equivalents—For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents.

Property, Plant and Equipment—Properties are stated at original cost. The cost of property additions includes materials and both direct and indirect labor and applicable overhead, including payroll-related costs.

Depreciation of Energy Future Holdings Corp.’s property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. As is common in the industry, Energy Future Holdings Corp. records depreciation expense using composite depreciation rates that reflect blended estimates of the lives of major asset components as compared to depreciation expense calculated on an asset-by-asset basis. Estimated depreciable lives are based on management’s estimates of the assets’ economic useful life. Depreciation also includes the effect of asset retirement obligations as prescribed by SFAS 143 and the impacts of FIN 47 (see Note 5), which was adopted by Energy Future Holdings Corp. in 2005.

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Effective January 1, 2005, the estimated depreciable lives of lignite/coal-fueled generation facilities were extended from fifty years to sixty years to better reflect their useful lives, resulting in a reduction of depreciation expense for the year ended December 31, 2005 of $13 million ($8 million after-tax) as compared to the 2004 year.

Capitalized Interest and Allowance For Funds Used During Construction (AFUDC)—Interest on Competitive Electric’s qualifying construction projects is capitalized in accordance with SFAS 34. Oncor Electric Delivery capitalizes AFUDC as a cost component of projects involving construction periods lasting greater than thirty days. AFUDC is a regulatory cost accounting procedure whereby both interest charges on borrowed funds and a return on equity capital used to finance construction are included in the recorded cost of utility plant and equipment being constructed. The equity portion of capitalized AFUDC is accounted for as other income. See Notes 12 and 25 for details of amounts.

Inventories—Inventories, including environmental energy credits and emission allowances, are carried at weighted average cost. All inventories are reported at the lower of cost or market unless expected to be used in the generation of electricity.

Regulatory Assets and Liabilities—The financial statements of Energy Future Holdings Corp.’s regulated electricity delivery operations reflect regulatory assets and liabilities under cost-based rate regulation in accordance with SFAS 71. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 25 for detail of the regulatory assets and liabilities.

See Note 4 for a discussion of the extraordinary gain recorded in 2004 related to the adjustment in the carrying value of Energy Future Holdings Corp.’s regulatory asset subject to securitization.

Investments—Deposits in a nuclear decommissioning trust fund are carried at fair value in the balance sheet. Investments in unconsolidated business entities over which Energy Future Holdings Corp. has significant influence but does not maintain effective control, generally representing ownership of at least 20% and not more than 50% of common equity, are accounted for under the equity method. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at market value. See Note 20 for details of investments.

Changes in Accounting Standards—In February 2007, the FASB issued SFAS 159, which permits an entity to choose to measure certain financial assets and liabilities at fair value. SFAS 159 also revises provisions of SFAS 115 that apply to available-for-sale and trading securities. This statement is effective for fiscal years beginning after November 15, 2007. Energy Future Holdings Corp. has not yet evaluated the potential impact of this standard.

In September 2006, the FASB issued SFAS 158, which was adopted by Energy Future Holdings Corp. effective December 31, 2006. See Note 21 for details related to the adoption of SFAS 158.

Also, in September 2006, the FASB issued SFAS 157, which establishes a framework for measuring fair value. This statement is effective for fiscal years beginning after November 15, 2007. Energy Future Holdings Corp. expects that the adoption of the statement will impact mark-to-market valuations of certain commodity contracts.

The FASB issued guidance in September 2006 regarding accounting for major maintenance activities (referred to as FASB Staff Position AUG AIR-1, “Accounting for Planned Major Maintenance Activities”). This guidance prohibits the use of the accrue-in-advance method of accounting. Energy Future Holdings Corp. expenses major maintenance costs as incurred.

In June 2006, the FASB issued FIN 48, which provides clarification of SFAS 109 with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. FIN 48 requires

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uncertain tax positions be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard. Benefits of positions taken on income tax returns that do not qualify for financial statement recognition are required to be disclosed in the financial statements. This interpretation will be adopted by Energy Future Holdings Corp. effective January 1, 2007, as required. Upon adoption, the cumulative effect of this change in accounting principle will be accounted for as an adjustment to retained earnings. The FASB is considering certain revisions to FIN 48, and Energy Future Holdings Corp. continues to evaluate the potential impact of this standard on its financial position.

2. EARNINGS PER SHARE

Basic earnings per share available to common shareholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share include the effect of all potential issuances of common shares under stock-based incentive compensation and certain debt arrangements.

Stock Split—All share and per share amounts reflect a two-for-one stock split completed in December 2005.

	For the Year Ended 2006					For the Year Ended 2005							For the Year Ended 2004
	Income		Shares	Per Share Amount		Income			Shares	Per Share Amount			Income			Shares	Per Share Amount
Income from continuing operations before extraordinary items and accounting changes	$	2,465	459.7	$	5.36	$	1,775		475.9	$	3.73		$	81		600.4	$	0.13
Exchangeable preferred membership interest buyback premium		—					—		—		—			(849	)	—		(1.41	)
Preference stock dividends		—	—		—		(10	)	—		(0.02	)		(22	)	—		(0.04	)
Income from continuing operations available for common stock—Basic	$	2,465	459.7	$	5.36	$	1,765		475.9	$	3.71		$	(790	)	600.4	$	(1.32	)
Dilutive securities/other adjustments:
Adjustment related to 2004 accelerated share repurchase program(a)		—	—				(498	)	—					12		—
Exchangeable preferred membership interests		—	—				—		—					17		36.5
Convertible senior notes(b)		1	1.5				1		1.5					1		1.4
Equity-linked debt securities		—	0.8				—		2.4					—		—
Stock-based incentive compensation plan		—	5.3				—		6.6					—		2.6
Income from continuing operationsavailable for common—Diluted(c)	$	2,466	467.3	$	5.27	$	1,268		486.4	$	2.61		$	(790	)	600.4	$	(1.32	)

(a) Adjustment to net income represents change in fair value of related settlement liability. See Note 17 for details of the accelerated share repurchase program.

(b) Adjustment to net income represents after-tax interest expense.

(c) For the 2004 year, diluted results per share equaled basic results per share because of the loss position and antidilution accounting rules.

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3. DISCONTINUED OPERATIONS

Results from discontinued operations in 2006 totaled $87 million in net income. This amount included a $62 million credit recorded in the first quarter representing a reversal of a TXU Gas income tax reserve, due to favorable resolution of an IRS audit matter relating to a business sold in 2000, and a total of $27 million ($42 million pretax) in credits recorded in the third quarter and fourth quarter representing insurance recoveries associated with the 2005 TXU Europe settlement agreement. (Also see discussion in Note 16 under “Income Tax Contingencies.”)

The table below reflects the results of the various businesses reported as discontinued operations in 2005 and 2004:

	TXU Gas		TXU Australia		Strategic Retail Services			Pedrick- town			Mexico		Europe			Total
2005
Operating revenues	$	—	$	—	$	—		$	12		$	—	$	—		$	12
Operating costs and expenses		—		—		—			14			—		—			14
Other deductions—net		—		—		3			—			—		—			3
Operating loss before income taxes		—		—		(3	)		(2	)		—		—			(5	)
Income tax benefit		—		—		(1	)		—			—		—			(1	)
Credits (charges) related to exit (after-tax)		3		10		—			(4	)		1		(1	)		9
Income (loss) from discontinued operations	$	3	$	10	$	(2	)	$	(6	)	$	1	$	(1	)	$	5

	TXU Gas			TXU Australia			Strategic Retail Services			Pedrick- town			Telecom			Mexico			Europe			Total
2004
Operating revenues	$	911		$	835		$	17		$	32		$	54		$	4		$	—		$	1,853
Operating costs and expenses		898			666			20			37			49			4			—			1,674
Other deductions—net		101			2			10			—			16			—			5			134
Interest income		(9	)		(2	)		(1	)		—			(5	)		—			—			(17	)
Interest expense and related charges		37			96			—			—			19			—			—			152
Operating income (loss) before income taxes		(116	)		73			(12	)		(5	)		(25	)		—			(5	)		(90	)
Income tax expense (benefit)		(27	)		25			(4	)		(2	)		(8	)		(1	)		(2	)		(19	)
Credits (charges) related to exit (after-tax)		(193	)		129			(6	)		(17	)		1			(2	)		(143	)		(231	)
Recognition of tax benefits		—			—			—			—			—			—			—			680
Income (loss) from discontinued operations	$	(282	)	$	177		$	(14	)	$	(20	)	$	(16	)	$	(1	)	$	(146	)	$	378

TXU Gas—In October 2004, Atmos Energy Corporation and TXU Gas completed a merger by division, which resulted in the disposition of the operations of TXU Gas for $1.9 billion in cash (the TXU Gas transaction). TXU Gas was largely a regulated business engaged in the purchase, transmission, distribution and retail sale of natural gas. TXU Gas’ results in 2004 included a loss of $99 million after-tax related to regulatory disallowances arising from a system-wide distribution rate case ruling and an income tax charge of $17 million due to an IRS ruling related to a prior year disputed deduction. A net credit of $3 million in 2005 includes a $7 million after-tax benefit from a favorable resolution of a working capital adjustment related to the disposition and a $9 million charge primarily representing an adjustment to the estimated tax effect of the disposition. As discussed above, an income tax benefit related to TXU Gas was recorded in 2006.

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TXU Australia—In July 2004, Energy Future Holdings Corp. completed the sale of TXU Australia to Singapore Power Ltd. for $1.9 billion in cash and $1.7 billion of assumed debt. TXU Australia’s operations consisted of a portfolio of competitive and regulated energy businesses, principally in Victoria and South Australia. The $10 million credit recorded in 2005 primarily represented an adjustment to the estimated income tax effect of the sale.

Strategic Retail Services—In December 2003, Texas Competitive Holdings finalized a formal plan to sell its strategic retail services business, which was engaged principally in providing energy management services. Results in 2004 include a $6 million after-tax charge to settle a contract dispute related to the business. Results in 2005 reflect an after-tax charge of $2 million related to a litigation settlement.

Pedricktown—In the second quarter of 2004, Texas Competitive Holdings initiated a plan to sell the Pedricktown, New Jersey 122 MW electricity generation business and exit the related power supply and gas transportation agreements resulting in a $17 million after-tax impairment charge in 2004. The business was sold in July 2005 for $8.7 million in cash. A $4 million after-tax charge in 2005 represents a working capital adjustment related to the sale transaction.

Mexico—In January 2004, Energy Future Holdings Corp. completed the sale of its majority-owned gas distribution operations in Mexico for $11 million in notes receivable which were settled for cash in January 2006.

TXU Europe—In January 2005, Energy Future Holdings Corp. executed a comprehensive settlement agreement resolving potential claims relating to TXU Europe. Results from discontinued operations in 2004 include an after-tax charge of $143 million for the expected payment under the terms of the agreement. The $222 million settlement was paid in full in October 2005. As discussed above, credits representing insurance recoveries related to the settlement were recorded in 2006.

Telecommunications—In April 2004, Energy Future Holdings Corp. sold its telecommunications business for $524 million in cash and $3 million of assumed debt. The business was formerly a joint venture and was consolidated from March 1, 2003 through the sale date.

Income tax benefits—Discontinued operations results in 2004 also reflected the recognition of $680 million in tax benefits associated with the 2002 write-off of the investment in TXU Europe. The tax benefit was based on a preliminary notice received from the IRS in June 2004 and primarily reflected the utilization of the worthlessness deduction against capital gains arising from the dispositions of TXU Australia, TXU Gas and the communications business as well as transactions completed in prior years. Also see Notes 11 and 16 for a discussion of TXU Europe income tax matters.

4. EXTRAORDINARY ITEMS

Purchase of Lease Trust Interest—In December 2005 a subsidiary of Energy Future Holdings Corp. entered into an agreement to purchase, for $69 million in cash, the owner participant interest in a trust established to lease combustion turbines to another subsidiary of Energy Future Holdings Corp. The trust is a variable interest entity, and in accordance with FIN 46R, the trust was consolidated at December 31, 2005, with the trust’s combustion turbine assets and related debt recorded at estimated fair values of $35 million and $96 million, respectively. The transaction was closed in March 2006. In the fourth quarter of 2005, Energy Future Holdings Corp. recorded an extraordinary loss of $50 million (net of a $28 million tax benefit) for the excess of the purchase price over the fair value of the trust’s net assets, net of the reversal of a previously established liability of $59 million related to the combustion turbine lease. Classification of the loss as extraordinary is in accordance with the provisions of FIN 46R.

Securitization (Transition) Bonds—A regulatory financing order finalized in January 2003 authorized the issuance of transition bonds with a principal amount of $1.3 billion to recover regulatory asset stranded costs and

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other qualified costs. A bankruptcy-remote financing subsidiary of Oncor Electric Delivery issued $500 million principal amount of transition bonds in August 2003 and the remaining $790 million in June 2004. An extraordinary gain of $16 million (net of tax of $9 million) recorded in the second quarter of 2004 represents an increase in the carrying value of the regulatory asset subject to securitization. The increase in the related regulatory asset is due to the effect of higher interest rates than previously estimated on the bonds and therefore increased amounts to be recovered from REPs through revenues as a transition charge to service the principal and interest of the bonds. Classification of the gain as extraordinary is reflective of the regulatory financing order having arisen from legislation to transition the Texas electricity market to competition.

5. CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES

FIN 47 was effective with reporting for the fourth quarter of 2005. This interpretation clarifies the term “conditional asset retirement” under SFAS 143 and requires entities to record the fair value of legally binding asset retirement obligations, the timing or method of settlement of which is conditional on a future event. For Energy Future Holdings Corp., such liability relates to generation assets asbestos removal and disposal costs. As the new accounting rule required retrospective application to the inception of the liability, the effects of the adoption reflect the accretion and depreciation from the liability inception date through December 31, 2005. The liability is accreted each period, representing the time value of money, and the capitalized cost is depreciated over the remaining useful life of the related asset.

The following table details the $8 million net charge in December 2005 arising from the adoption of FIN 47:

Increase in property, plant and equipment—net	$	5
Increase in other noncurrent liabilities and deferred credits		(17	)
Increase in accumulated deferred income taxes		4
Cumulative effect of change in accounting principle	$	(8	)

SFAS 123R, which addresses accounting for stock-based compensation costs, was issued in December 2004. Energy Future Holdings Corp. early adopted SFAS 123R effective October 1, 2004 and recorded a cumulative effect of change in accounting principle of $10 million after-tax (representing a net credit). See Note 22 for additional information.

6. IMPAIRMENT OF NATURAL GAS-FUELED GENERATION PLANTS

In the second quarter of 2006, Energy Future Holdings Corp. performed an evaluation of its natural gas-fueled generation plants for impairment in accordance with the requirements of SFAS 144, which provides that long-lived assets should be tested for recovery whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In consideration of the new lignite/coal-fueled generation plant development program, among other factors, Energy Future Holdings Corp. determined that it was more likely than not that its gas-fueled generation plants, which have generally been operated to meet peak demands for electricity, would be sold or otherwise disposed of before the end of their previously estimated useful lives and should be tested for impairment as an asset group. As a result, it was determined that an impairment existed, and a charge of $198 million ($129 million after-tax) was recorded in the second quarter of 2006 to write down the assets to fair value, which was determined based on discounted estimated future cash flows. Future cash flow expectations are subject to considerable estimation, including forecasts of future natural gas prices and market heat rates. Further, the form and timing of usage and ultimate disposition of the plants is uncertain. Because of the highly judgmental nature of key assumptions and potential volatility of market conditions, the adjusted carrying value of the plants does not necessarily represent the amount of proceeds from any transaction to sell the plants and future additional impairment is possible. The impairment was reported in other deductions in the Statements of Consolidated Income and included in the results of the Competitive Electric segment.

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7. CUSTOMER APPRECIATION BONUS

In the fourth quarter of 2006, Energy Future Holdings Corp. announced a special customer appreciation bonus program. Under the program, a $100 bonus will be provided to residential customers receiving service as of October 29, 2006 and living in areas where Energy Future Holdings Corp. offered its price-to-beat rate, which expired January 1, 2007 in accordance with the Texas deregulation provisions. Eligible customers are not required to continue to receive service from Energy Future Holdings Corp. to receive the bonus. The bonus is expected to be paid out in the form of credits on customer bills, with approximately $40 million paid out in the fourth quarter of 2006 and the balance expected to be fully settled in 2007. The bonus program resulted in a pretax charge of $162 million ($105 million after-tax) in the fourth quarter of 2006. The charge was recorded as a reduction to revenue in the Competitive Electric segment.

8. RESTRUCTURING ACTIONS IN 2004

During 2004, senior management reviewed Energy Future Holdings Corp.’s operations and implemented a restructuring plan to restore financial strength, drive performance improvement with a competitive industrial company perspective and allocate capital in a disciplined and efficient manner.

The restructuring actions included dispositions of businesses, repurchases of debt and other securities, rationalization of generation assets, termination of uneconomic contractual arrangements, headcount reductions, outsourcing of support activities and resolution of litigation, income tax and other contingencies.

The restructuring activities resulted in unusual charges and credits impacting 2004 income from continuing operations, summarized as follows and discussed below in more detail:

	Income Statement Classification	Charge/(Credit) to Earnings
		Pretax			After-tax
Competitive Electric segment:
Charges related to leased equipment	Other deductions	$	180		$	117
Software write-off	Other deductions		107			70
Employee severance costs	Other deductions		107			69
Power purchase contract termination charge	Other deductions		101			66
Spare parts inventory write-down	Other deductions		79			51
Outsourcing transition costs	Other deductions		10			6
Other asset impairments	Other deductions		6			4
Other charges	Operating costs/SG&A		8			6
Recognition of deferred gain on plant sales	Other income		(58	)		(38	)
Gain on sale of undeveloped properties	Other income		(19	)		(12	)
Regulated Delivery segment:
Employee severance costs	Other deductions		20			13
Cities rate settlement charge	Other deductions		21			14
Outsourcing transition costs	Other deductions		4			3
Software write-off and asset impairment	Other deductions		4			2
Other charges	Operating costs/SG&A		2			1
Corporate and other:
Debt extinguishment losses	Other deductions		416			382
Litigation accrual	Other deductions		86			56
Executive compensation	SG&A		52			52
Consulting and professional fees	SG&A		54			35
Employee severance costs	Other deductions		5			3
Transaction related fees	Other deductions		5			3
Recognition of income tax benefit	Income taxes		—			(75	)
Total		$	1,190		$	828

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In addition, income from discontinued operations in 2004 included recognition of $680 million in tax benefits related to the write-off of the investment in TXU Europe, a net charge of $193 million after-tax on the disposition of TXU Gas, a net charge of $143 million after-tax related to the settlement of potential claims related to TXU Europe, a net credit of $129 million after-tax related to the sale of TXU Australia and a net charge of $17 million after-tax related to the disposition of the Pedricktown, New Jersey generation business. See Note 3 for a discussion of these items.

Following is a discussion of major actions associated with the restructuring plan affecting income from continuing operations:

Sale of TXU Fuel—In June 2004, Energy Future Holdings Corp. completed the sale of the assets of TXU Fuel, the former intrastate gas transportation subsidiary of Texas Competitive Holdings, for $500 million in cash. As part of the transaction, Texas Competitive Holdings entered into a transportation agreement with the new owner, intended to be market-price based, to transport natural gas to Texas Competitive Holdings’ generation plants. Because of the continuing involvement in the business through the transportation agreement, the pretax gain related to the sale of $375 million is being recognized over the eight-year life of the transportation agreement, and the business was not accounted for as a discontinued operation. The sale of TXU Fuel assets resulted in a capital gain and allowed for recognition of a $75 million income tax benefit for utilization of a portion of the capital loss deduction arising from the write-off of the investment in TXU Europe.

Capgemini Outsourcing Agreement—In May 2004, Energy Future Holdings Corp. entered into a services agreement with Capgemini Energy LP (Capgemini). Under the ten-year agreement, over 2,500 employees transferred from subsidiaries of Energy Future Holdings Corp. to Capgemini effective July 1, 2004. Outsourced base support services performed by Capgemini for a fixed fee, subject to adjustment for volumes or other factors, include information technology, customer call center, billing, human resources, supply chain and certain accounting activities.

Energy Future Holdings Corp. agreed to indemnify Capgemini for severance costs incurred by Capgemini for former Energy Future Holdings Corp. employees terminated within 21 months of their transfer to Capgemini. Accordingly, Energy Future Holdings Corp. recorded a $40 million ($26 million after-tax) charge for severance expense in the second quarter of 2004. (See Note 25 for further details regarding severance liabilities.) In addition, Energy Future Holdings Corp. committed to pay up to $25 million for costs associated with transitioning the outsourced activities to Capgemini. Transition expenses of $14 million ($9 million after-tax) were recorded by Energy Future Holdings Corp. during 2004, and the remainder was expensed as incurred in 2005.

As part of the agreement, Capgemini was provided a royalty-free right, under an asset license arrangement, to use Energy Future Holdings Corp.’s information technology assets, consisting primarily of computer software. A portion of the software was in development and had not yet been placed in service. As a result of outsourcing its information technology activities, Energy Future Holdings Corp. no longer intended to develop the majority of these projects and from Energy Future Holdings Corp.’s perspective the software was abandoned. The agreements with Capgemini do not require that any software in development be completed and placed in service. Consequently, the carrying value of these software projects was written off, resulting in a charge of $109 million ($71 million after-tax).

Energy Future Holdings Corp. obtained a 2.9% limited partnership interest in Capgemini in exchange for the asset license described immediately above. See Note 20 for additional discussion of Energy Future Holdings Corp.’s investment in Capgemini and related terms of the agreement.

Actions Related to Generation Operations—In December 2004, Energy Future Holdings Corp. executed an agreement to terminate, for a payment of $172 million, a power purchase and tolling agreement expiring in 2006. The agreement had been entered into in connection with the sale of two generation plants to the counterparty in

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2001. As a result of the transaction, Energy Future Holdings Corp. recorded a charge of $101 million ($66 million after-tax). The charge represents the payment amount less the remaining out-of-the-money liability related to the agreement originally recorded at its inception. Energy Future Holdings Corp. also recorded a gain of $58 million ($38 million after-tax), representing the remaining deferred gain from the sale of the two plants.

Also in December 2004, Energy Future Holdings Corp. committed to immediately cease operating for its own benefit nine leased gas-fueled combustion turbines, and recorded a charge of $157 million ($102 million after-tax). The charge represented the present value of the future lease payments related to the turbines, net of estimated sublease proceeds. A $16 million credit was recorded in 2005 to adjust the liability recorded in 2004 for changes in estimated sublease proceeds.

Effective November 1, 2004, Energy Future Holdings Corp. entered into an agreement to terminate the operating lease for certain mining equipment for approximately $28 million in cash. The lease termination resulted in a charge of $21 million ($14 million after-tax).

As part of a review of its generation asset portfolio in the second quarter of 2004, Energy Future Holdings Corp. completed a review of its spare parts and equipment inventory to determine the appropriate level of such inventory. As a result of this review, Energy Future Holdings Corp. recorded a charge of $79 million ($51 million after-tax), to reflect excess inventory on hand and to write down carrying values to scrap values.

Energy Future Holdings Corp. recorded charges totaling $15 million ($10 million after-tax) in 2004 for employee severance costs and impairments ($1 million pretax) arising from a decision to take a number of gas-fueled generation units out of service.

Organization Realignment and Headcount Reductions—During 2004, management completed a comprehensive organizational review, including an analysis of staffing requirements. As a result, Energy Future Holdings Corp. completed a self-nomination severance program and certain involuntary severance actions and recorded severance charges totaling $77 million ($49 million after-tax).

Liability and Capital Management—Energy Future Holdings Corp. utilized cash proceeds from the sale of TXU Australia, TXU Gas and TXU Fuel and other assets sales as well as cash provided from operations and lower-cost debt issuances in 2004 to increase value and reduce risks through an ongoing liability management initiative. Largely under this initiative, in 2004 Energy Future Holdings Corp. repurchased or legally defeased $3.6 billion of debt securities (including equity-linked debt securities and debt held by subsidiary trusts). Debt extinguishment losses in 2004 totaled $416 million ($382 million after-tax). See Note 17 for a discussion of the repurchase of preferred membership interests.

Cities Rate Settlement—In the fourth quarter of 2004, Energy Future Holdings Corp. recorded a $21 million ($14 million after-tax) charge for estimated payments under a settlement, which was finalized in February 2005, with a number of municipalities initiating an inquiry regarding distribution rates charged by Oncor Electric Delivery.

Litigation—In the fourth quarter of 2004, management assessed the progress and status of matters in litigation, and in anticipation of resolution, recorded a charge of $86 million ($56 million after-tax) net of estimated insurance recoveries. This net charge relates almost entirely to the shareholders’ litigation settlement initially filed in October 2002. Energy Future Holdings Corp. reached a comprehensive settlement of the lawsuit in January 2005. The agreement included a one-time payment to the class members of $150 million, of which insurance carriers reimbursed Energy Future Holdings Corp. $101 million in 2005 and $15 million in 2006.

9. CITIES RATE SETTLEMENT IN 2006

In January 2006, Oncor Electric Delivery agreed with a steering committee representing 108 cities in Texas (Cities) to defer the filing of a system-wide rate case with the Commission to no later than June 30, 2008 (based

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on a test year ending December 31, 2007), unless the Cities and Oncor Electric Delivery mutually agree that such a filing is unnecessary. Oncor Electric Delivery has extended the benefits of the agreement to 292 nonlitigant cities. Based on the final agreements, including the participation of the nonlitigant cities, payments to the cities are estimated to total approximately $70 million, including incremental franchise taxes.

This amount is being recognized in earnings of the Regulated Delivery segment over the period from May 2006 through June 2008. Amounts recognized in 2006 totaled $18 million and have been reported in the other deductions (see Note 12) and franchise and revenue-based taxes in the Statements of Consolidated Income.

10. TEXAS MARGIN TAX

In May 2006, the Texas Legislature enacted reforms of the Texas franchise tax system and replaced it with a new tax system, referred to as the Texas margin tax. The Texas margin tax is a significant change in Texas tax law because it generally makes all legal entities subject to tax, including general and limited partnerships, while the current franchise tax system applies only to corporations and limited liability companies. Energy Future Holdings Corp. conducts significant operations through Texas limited partnerships that will become subject to the new Texas margin tax. The effective date of the Texas margin tax, which has been interpreted to be an income tax for accounting purposes, is January 1, 2008 for calendar year-end companies, and the computation of tax liability is expected to be based on 2007 revenues as reduced by certain deductions.

In accordance with the provisions of SFAS 109, which require that deferred tax assets and liabilities be adjusted for the effects of new income tax legislation in the period of enactment, Energy Future Holdings Corp. estimated and recorded a net charge to deferred tax expense of $41 million in the second quarter of 2006. An additional adjustment of $3 million was recorded in the fourth quarter of 2006. Essentially all of the effect of the Texas margin tax was reported in the Competitive Electric segment. The total estimate recorded in 2006 was based on the Texas margin tax law in its current form and the guidance issued by the Texas Comptroller of Public Accounts (Comptroller). Energy Future Holdings Corp. expects the law to be amended in the 2007 Texas legislative session and for the Comptroller to issue further guidance.

11. INCOME TAXES

The components of Energy Future Holdings Corp.’s income tax expense applicable to continuing operations are as follows:

	Year Ended December 31,
	2006			2005			2004
Current:
US Federal	$	500		$	145		$	25
State		5			6			26
Non-US		1			—			2
Total		506			151			53
Deferred:
US Federal		715			498			31
State		63			4			(19	)
Total		778			502			12
Amortization of investment tax credits		(21	)		(21	)		(23	)
Total	$	1,263		$	632		$	42

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Reconciliation of income taxes computed at the US federal statutory rate to income tax expense:

	Year Ended December 31,
	2006			2005			2004
Income from continuing operations before income taxes, extraordinary gain (loss) and cumulative effect of changes in accounting principles:
Domestic	$	3,728		$	2,408		$	123
Non-US		—			(1	)		—
Total	$	3,728		$	2,407		$	123
Income taxes at the US federal statutory rate of 35%	$	1,305		$	842		$	43
Losses on extinguishment of debt		—			—			107
Lignite depletion allowance		(51	)		(33	)		(25	)
Production activities deduction		(14	)		—			—
Recognition of benefits related to TXU Europe		—			(138	)		(75	)
Amortization of investment tax credits—net of deferred income tax effect		(15	)		(15	)		(17	)
Amortization (under regulatory accounting) of statutory rate changes		(7	)		(7	)		(8	)
Medicare subsidy—other postretirement employee benefits		(8	)		(9	)		(11	)
Nondeductible compensation expense		—			(5	)		18
State income taxes, net of federal tax benefit		6			7			5
Texas margin tax		44			—			—
Other, including audit settlements		3			(10	)		5
Income tax expense	$	1,263		$	632		$	42
Effective tax rate		33.9	%		26.3	%		34.1	%

TXU Europe—In the first quarter of 2005, Energy Future Holdings Corp. recognized a $138 million tax benefit related to the 2002 TXU Europe worthlessness deduction. The recognition of the tax benefit was based on the identification of tax planning strategies Energy Future Holdings Corp. would implement to ensure utilization of capital losses associated with the write-off of the investment in TXU Europe. Classification of this benefit in continuing operations is in accordance with SFAS 109.

In 2004, Energy Future Holdings Corp. recognized tax benefits related to TXU Europe totaling $755 million, of which $680 million was classified as discontinued operations. The recognition of benefits was based on a preliminary notice of proposed adjustment issued by the IRS in June 2004. The notice proposes, among other things, that the worthlessness deduction for the write-off of the investment in TXU Europe claimed on the 2002 tax return as an ordinary loss be instead treated as a capital loss (deductible only against capital gains). Energy Future Holdings Corp. had previously not recognized in net income any benefit related to the TXU Europe write-off due to a number of uncertainties regarding the income tax effects.

The benefit recognized includes the effect of the expected utilization of the TXU Europe worthlessness deduction against the capital gains arising from the dispositions of TXU Australia, TXU Gas, TXU Fuel and other 2004 and prior year transactions.

Benefits arising from the resolution of uncertainty regarding utilization of deductions in the year the TXU Europe investment was written-off or in a prior year have been reported in discontinued operations. Additional such benefits arising from subsequent sales of businesses classified as discontinued operations have also been reported in discontinued operations. The $75 million of tax benefit recognized in 2004 continuing operations relates to the capital gain arising from the sale of TXU Fuel, the operations of which have been classified as continuing operations.

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Deferred Income Tax Balances—Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2006 and 2005, balance sheet dates are as follows:

	December 31,
	2006							2005
	Total		Current			Noncurrent		Total		Current			Noncurrent
Deferred Income Tax Assets
Net operating loss (NOL) carryforwards	$	12	$	—		$	12	$	666	$	666		$	—
Alternative minimum tax credit carryforwards		768		209			559		651		—			651
Employee benefit liabilities		496		7			489		410		15			395
Unamortized investment tax credits		137		—			137		145		—			145
Capital loss carryforward		31		31			—		138		—			138
Deferred gain on sale of assets		121		—			121		136		—			136
Other		242		12			230		356		43			313
Total		1,807		259			1,548		2,502		724			1,778
Deferred Income Tax Liabilities
Book/tax depreciation differences		3,523		—			3,523		3,400		—			3,400
Mark-to-market net deductions		966		4			962		761		4			757
Deductions related to TXU Europe		465		—			465		592		—			592
Effects of amounts recorded as regulatory assets		484		—			484		538		—			538
Other		354		2			352		191		3			188
Total		5,792		6			5,786		5,482		7			5,475
Net Deferred Income Tax (Asset) Liability	$	3,985	$	(253	)	$	4,238	$	2,980	$	(717	)	$	3,697

At December 31, 2006, Energy Future Holdings Corp. had $768 million of alternative minimum tax credit carryforwards (AMT) available to offset future tax payments. The AMT credit carryforwards have no expiration date. At December 31, 2006, Energy Future Holdings Corp. had net operating loss (NOL) carryforwards for federal income tax purposes of $12 million that expire between 2022 and 2026. The NOL carryforwards can be used to offset future taxable income. Energy Future Holdings Corp. fully expects to utilize all of its NOL carryforwards prior to their expiration dates.

The income tax effects of the components included in accumulated other comprehensive income for the year ended December 31, 2006 total a net deferred tax liability of $321 million.

See Note 16 under “Income Tax Contingencies” for discussion of tax matters related to TXU Europe and the status of IRS audits.

See Note 1 for discussion regarding the implementation of FIN 48, which addresses accounting for uncertain tax positions.

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12. OTHER INCOME AND DEDUCTIONS

	Year Ended December 31,
	2006			2005			2004
Other income:
Gain on contract settlement(a)	$	26		$	—		$	—
Amortization of gain on sale of TXU Fuel (Note 8)		47			47			27
Net gain on sale of other properties and investments(b)		22			42			107
Insurance recovery of litigation settlement(c)		15			35			—
Insurance recoveries related to generation assets		2			8			—
Electricity sale agreement termination fee		—			4			—
Equity portion of allowance for funds used during construction		—			3			4
Other		9			12			10
Total other income	$	121		$	151		$	148
Other deductions:
Charge for impairment of natural gas-fueled generation plants (Note 6)	$	198		$	—		$	—
Asset writedown and generation-related lease termination charges (credit) (see Note 8 for 2005 and 2004 items)		4			(16	)		376
Equity losses of an unconsolidated affiliate engaged in broadband-over-powerline activities		14			—			—
Debt extinguishment losses (See Note 8 regarding 2004 charges)		1			—			416
Litigation settlements (See Note 8 regarding 2004 charges)		9			7			86
Employee severance charges (See Note 8 regarding 2004 charges)		—			1			132
Termination of electricity purchase contract (See Note 8 regarding 2004 charges)		—			—			101
Costs related to cities rate settlements (Notes 8 and 9)		13			1			21
Capgemini outsourcing transition costs (Note 8 regarding 2004 charges)		—			11			14
Restructuring transaction-related fees		—			—			5
Expenses related to canceled construction projects		—			—			6
Transition costs related to InfrastruX Energy Services joint venture		7			—			—
Employee retirement benefit costs related to discontinued business		23			15			—
Charge (credit) related to coal contract counterparty claim(d)		(12	)		12			—
Other		12			14			15
Total other deductions	$	269		$	45		$	1,172

(a) Represents a gain recorded in the second quarter of 2006 upon the settlement of a contract dispute related to antenna site rentals by a telecommunications company (reported in Corporate and Other nonsegment operations).

(b) Includes gains on land sales of $12 million in 2006, $33 million in 2005 and $19 million in 2004. (All reported in the Competitive Electric segment except $1 million in 2006 reported in the Regulated Delivery segment.) The 2006 period also includes a $10 million gain related to the sale of mineral interests (reported in Corporate and Other nonsegment operations). The 2005 period also includes a $7 million gain on the sale of an out-of-state electricity transmission project (reported in the Competitive Electric segment). The 2004 period also includes $30 million in amortization of a deferred gain related to the sale of generation plants in 2002. The remaining $58 million in 2004 represents the recognition of the remaining previously deferred gain (reported in the Competitive Electric segment). See Note 8.

(c) Represents additional insurance recoveries recorded in the third quarter of 2006 and second quarter of 2005 related to the 2005 settlement of the shareholders’ litigation (reported in Corporate and Other nonsegment operations).

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(d) In the first quarter of 2006, Energy Future Holdings Corp. recorded a credit of $12 million upon settlement of a claim against a counterparty for nonperformance under a coal contract. A charge in the same amount was recorded in the first quarter of 2005 for losses due to the nonperformance (reported in the Competitive Electric segment).

13. TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Sale of Receivables—Subsidiaries of Energy Future Holdings Corp. participate in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, subsidiaries of Energy Future Holdings Corp. (originators) sell trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of Energy Future Holdings Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities). The current program is subject to renewal in June 2008.

The maximum amount currently available under the program is $700 million, and the program funding was $627 million as of December 31, 2006. Under certain circumstances, the amount of customer deposits held by the originators can reduce the amount of undivided interests that can be sold, thus reducing funding available under the program. Funding availability for all originators is reduced by 100% of the originators’ customer deposits if Texas Competitive Holdings’ fixed charge coverage ratio is less than 2.5 times; 50% if Texas Competitive Holdings’ coverage ratio is less than 3.25 times, but at least 2.5 times; and zero % if Texas Competitive Holdings’ coverage ratio is 3.25 times or more. The originators’ customer deposits, which totaled $116 million, did not affect funding availability at that date as Texas Competitive Holdings’ coverage ratio was in excess of 3.25 times.

All new trade receivables under the program generated by the originators are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflect seasonal variations in the level of accounts receivable, changes in collection trends as well as other factors such as changes in sales prices and volumes. TXU Receivables Company has issued subordinated notes payable to the originators for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originators that was funded by the sale of the undivided interests. The balance of the subordinated notes payable, which is eliminated in consolidation, totaled $211 million and $201 million at December 31, 2006 and 2005, respectively.

The discount from face amount on the purchase of receivables principally funds program fees paid by TXU Receivables Company to the funding entities. The discount also funds a servicing fee paid by TXU Receivables Company to TXU Business Services Company, a direct subsidiary of Energy Future Holdings Corp. The program fees, also referred to as losses on sale of the receivables under SFAS 140, consist primarily of interest costs on the underlying financing and totaled $40 million, $23 million and $12 million in 2006, 2005 and 2004, respectively, and averaged 5.8%, 4.0% and 2.1% (on an annualized basis) of the funding under the program in 2006, 2005 and 2004, respectively. The servicing fee, which totaled approximately $4 million in both 2006 and 2005 and $7 million in 2004, compensates TXU Business Services Company for its services as collection agent, including maintaining the detailed accounts receivable collection records. The program fees represent essentially all the net incremental costs of the program on a consolidated basis and are reported in SG&A expenses.

The accounts receivable balance reported in the December 31, 2006 consolidated balance sheet includes $838 million face amount of trade accounts receivable of Texas Competitive Holdings and Oncor Electric Delivery sold to TXU Receivables Company, such amount having been reduced by $627 million of undivided interests sold by TXU Receivables Company. Funding under the program related to continuing operations decreased $44 million in 2006, increased $197 million in 2005 and decreased $73 million in 2004. Funding increases or decreases under the program are reflected as operating cash flow activity in the statement of cash

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flows. The carrying amount of the retained interests in the accounts receivable balance approximated fair value due to the short-term nature of the collection period.

Activities of TXU Receivables Company were as follows:

	Year Ended December 31,
	2006			2005		��	2004
Cash collections on accounts receivable	$	8,503		$	7,450		$	8,449
Face amount of new receivables purchased		(8,469	)		(7,511	)		(8,149	)
Discount from face amount of purchased receivables		44			27			19
Program fees paid		(40	)		(23	)		(12	)
Servicing fees paid		(4	)		(4	)		(7	)
Increase in subordinated notes payable		10			(136	)		(174	)
Operating cash flows used by (provided to) Energy Future Holdings Corp. under the program	$	44		$	(197	)	$	126
Cash flow related to disposed TXU Gas business		—			—			(53	)
Cash flows used by (provided to) continuing operations	$	44		$	(197	)	$	73

Upon termination of the program, cash flows would be delayed as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests from the funding entities instead of purchasing new receivables. The level of cash flows would normalize in approximately 16 to 30 days.

Contingencies Related to Sale of Receivables Program—Although TXU Receivables Company expects to be able to pay its subordinated notes from the collections of purchased receivables, these notes are subordinated to the undivided interests of the financial institutions in those receivables, and collections might not be sufficient to pay the subordinated notes. The program may be terminated if either of the following events occurs:

1) all of the originators cease to maintain their required fixed charge coverage ratio and debt to capital (leverage) ratio; or

2) the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds and the financial institutions do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables, not separately to the receivables of each originator.

Trade Accounts Receivable—

	December 31,
	2006			2005
Gross trade accounts receivable	$	1,599		$	2,035
Undivided interests in accounts receivable sold by TXU Receivables Company		(627	)		(671	)
Allowance for uncollectible accounts related to undivided interests in receivables retained		(13	)		(36	)
Trade accounts receivable—reported in balance sheet	$	959		$	1,328

Gross trade accounts receivable at December 31, 2006 and 2005 included unbilled revenues of $466 million and $494 million, respectively.

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Allowance for Uncollectible Accounts Receivable—

	2006			2005			2004
Allowance for uncollectible accounts receivable as of January 1	$	36		$	16		$	54
Increase for bad debt expense		68			56			90
Decrease for account write-offs		(80	)		(68	)		(121	)
Changes related to receivables sold		4			17			(7	)
Other(a)		(15	)		15			—
Allowance for uncollectible accounts receivable as of December 31	$	13		$	36		$	16

(a) Reflects an allowance established in 2005 for a coal contract dispute that was reversed upon settlement in 2006. See Note 12.

Allowances related to undivided interests in receivables sold are reported in current liabilities and totaled $26 million and $30 million at December 31, 2006 and December 31, 2005, respectively.

14. SHORT-TERM FINANCING

Short-term Borrowings—At December 31, 2006 and 2005, the outstanding short-term borrowings of Energy Future Holdings Corp. and its subsidiaries consisted of the following:

	At December 31, 2006				At December 31, 2005
	Outstanding Amount		Interest Rate(a)		Outstanding Amount		Interest Rate(a)
Commercial paper	$	1,296	5.53	%	$	358	4.49	%
Bank borrowings		195	5.97	%		440	4.86	%
Total	$	1,491			$	798

(a) Weighted average interest rate at the end of the period.

Under the commercial paper programs, Texas Competitive Holdings and Oncor Electric Delivery may issue up to $2.4 billion and $1.0 billion, respectively, of these securities. These programs are supported by existing credit facilities.

Credit Facilities—At December 31, 2006, subsidiaries of Energy Future Holdings Corp. had access to credit facilities with the following terms:

Authorized Borrowers	Maturity Date	At December 31, 2006
		Facility Limit		Letters of Credit		Cash Borrowings		Availability
Texas Competitive Holdings	May 2007	$	1,500	$	—	$	—	$	1,500
Texas Competitive Holdings, Oncor Electric Delivery	June 2008		1,400		489		—		911
Texas Competitive Holdings, Oncor Electric Delivery	August 2008		1,000		—		150		850
Texas Competitive Holdings, Oncor Electric Delivery	March 2010		1,600		3		—		1,597
Texas Competitive Holdings, Oncor Electric Delivery	June 2010		500		—		—		500
Texas Competitive Holdings	December 2009		500		455		45		—
Total		$	6,500	$	947	$	195	$	5,358

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The $1.5 billion facility in the above table with a May 2007 maturity date was entered into by Texas Competitive Holdings in May 2006 on terms comparable to its existing facilities.

The maximum amount Texas Competitive Holdings and Oncor Electric Delivery can directly access under the facilities is $6.5 billion and $3.6 billion, respectively. These facilities may be used for working capital and general corporate purposes, including providing support for issuances of commercial paper and for issuing letters of credit.

In addition, Texas Competitive Holdings and Oncor Electric Delivery have a $25 million joint uncommitted line of credit without an expiration date. The terms are generally consistent with existing credit facilities, except that funding remains at the discretion of the lender. As of December 31, 2006, there were no outstanding borrowings under this line of credit.

All letters of credit and cash borrowings under the credit facilities as of December 31, 2006 are the obligations of Texas Competitive Holdings. Outstanding commercial paper, which totaled $623 million for Texas Competitive Holdings and $673 million for Oncor Electric Delivery as of December 31, 2006, is supported by these facilities but does not limit the availability.

15. LONG-TERM DEBT

Long-term debt—At December 31, 2006 and 2005, the long-term debt of Energy Future Holdings Corp. consisted of the following:

	December 31,
	2006		2005
Texas Competitive Holdings
Pollution Control Revenue Bonds:
Brazos River Authority:
5.400% Fixed Series 1994A due May 1, 2029	$	39	$	39
5.400% Fixed Series 1994B due May 1, 2029, remarketing date May 1, 2006(a)(b)		—		39
5.400% Fixed Series 1995A due April 1, 2030, remarketing date May 1, 2006(a)(b)		—		50
5.050% Fixed Series 1995B due June 1, 2030, remarketing date June 19, 2006(a)(c)		—		114
7.700% Fixed Series 1999A due April 1, 2033		111		111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013(a)		16		16
7.700% Fixed Series 1999C due March 1, 2032		50		50
4.000% Floating Series 2001A due October 1, 2030(e)		71		71
4.750% Fixed Series 2001B due May 1, 2029, remarketing date November 1, 2006(a)(d)		—		19
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011(a)		217		217
3.960% Floating Series 2001D due May 1, 2033(e)		268		268
5.370% Floating Taxable Series 2001I due December 1, 2036(e)		62		62
4.000% Floating Series 2002A due May 1, 2037(e)		45		45
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)		44		44
6.300% Fixed Series 2003B due July 1, 2032		39		39
6.750% Fixed Series 2003C due October 1, 2038		52		52
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014(a)		31		31
5.000% Fixed Series 2006 due March 1, 2041		100		—
Sabine River Authority of Texas:
6.450% Fixed Series 2000A due June 1, 2021		51		51
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011(a)		91		91
6.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011(a)		107		107
5.200% Fixed Series 2001C due May 1, 2028		70		70

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	December 31,
	2006			2005
5.800% Fixed Series 2003A due July 1, 2022		12			12
6.150% Fixed Series 2003B due August 1, 2022		45			45
4.110% Floating Series 2006A due November 1, 2041, remarketing date May 9, 2007(g)(j)		47			—
4.110% Floating Series 2006B due November 1, 2041, remarketing date May 9, 2007(g)(j)		46			—
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028		14			14
5.000% Fixed Series 2001A due May 1, 2027, remarketing date November 1, 2006(a)(d)		—			37
4.110% Floating Series 2006 due November 1, 2041, remarketing date May 9, 2007(g)(j)		50			—
Other:
6.125% Fixed Senior Notes due March 15, 2008 (swapped to variable)(f)		250			250
7.000% Fixed Senior Notes due March 15, 2013		1,000			1,000
4.920% Floating Rate Senior Notes due January 17, 2006 (interest rate in effect at December 31, 2005)		—			400
Capital lease obligations		98			103
Fair value adjustments related to interest rate swaps		10			9
Total Texas Competitive Holdings	$	3,036		$	3,456
Oncor Electric Delivery
6.375% Fixed Senior Notes due May 1, 2012	$	700		$	700
7.000% Fixed Senior Notes due May 1, 2032		500			500
6.375% Fixed Senior Notes due January 15, 2015 (swapped to variable)(f)		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
5.000% Fixed Debentures due September 1, 2007 (swapped to variable)(f)		200			200
7.000% Fixed Debentures due September 1, 2022		800			800
Unamortized discount		(16	)		(17	)
Sub-total		3,034			3,033
Oncor Electric Delivery Transition Bond Company LLC(h)
2.260% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2007		8			44
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		122			122
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		130			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		145			145
3.520% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2009		158			215
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		221			221
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		290			290
Total Oncor Electric Delivery Transition Bond Company LLC		1,074			1,167
Total Oncor Electric Delivery		4,108			4,200

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	December 31,
	2006			2005
Energy Future Competitive Holdings Company
7.170% Fixed Senior Debentures due August 1, 2007		10			10
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		85			91
9.580% Fixed Notes due in semiannual installments through December 4, 2019		62			65
8.254% Fixed Notes due in quarterly installments through December 31, 2021		59			62
6.171% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037(g)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized premium		5			5
Total Energy Future Competitive Holdings Company		230			242
Energy Future Holdings Corp.
6.375% Fixed Senior Notes Series C due January 1, 2008 (swapped to variable)(f)		200			200
6.375% Fixed Senior Notes Series J due June 15, 2006		—			683
4.446% Fixed Senior Notes Series K due November 16, 2006		—			50
5.800% Fixed Senior Notes Series M due May 16, 2008(i)		—			179
4.800% Fixed Senior Notes Series O due November 15, 2009 ($450 swapped to variable)(f)		1,000			1,000
5.550% Fixed Senior Notes Series P due November 15, 2014 ($500 swapped to variable)(f)		1,000			1,000
6.500% Fixed Senior Notes Series Q due November 15, 2024 ($400 swapped to variable)(f)		750			750
6.550% Fixed Senior Notes Series R due November 15, 2034		750			750
8.820% Building Financing due semiannually through February 11, 2022		99			109
6.874% Floating Convertible Senior Notes due July 15, 2033(g)		25			25
Fair value adjustments related to interest rate swaps		(73	)		(53	)
Unamortized discount		(9	)		(9	)
Total Energy Future Holdings Corp.		3,742			4,684
Total Energy Future Holdings Corp. consolidated		11,116			12,582
Less amount due currently		(485	)		(1,250	)
Total long-term debt	$	10,631		$	11,332

(a) These series are in the multiannual interest rate 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.

(b) Repurchased on May 1, 2006 for remarketing at a later date.

(c) Repurchased on June 19, 2006 for remarketing at a later date.

(d) Repurchased on November 1, 2006 for remarketing at a later date.

(e) Interest rates in effect at December 31, 2006. These series are in a weekly interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(f) Interest rates swapped to variable on a net $2.5 billion of $3.9 billion aggregate principal amount at December 31, 2006.

(g) Interest rates in effect at December 31, 2006.

(h) These bonds are nonrecourse to Oncor Electric Delivery and were issued to recover a regulatory asset.

(i) Equity-linked.

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

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Debt-related Activity in 2006—In November 2006, Texas Competitive Holdings issued the Sabine River Authority of Texas Series 2006A and 2006B pollution control revenue bonds with aggregate principal amounts of $47 million and $46 million, respectively. Also in November 2006, Texas Competitive Holdings issued the Trinity River Authority of Texas Series 2006 pollution control revenue bonds with an aggregate principal amount of $50 million. All three bond series were issued in conjunction with the generation facility development program and have weekly reset floating interest rates, mature in November 2041 and are expected to be repurchased by May 9, 2007. All three bond series are classified as long-term debt due currently. Net proceeds of $141 million ($143 million principal amount less issuance expenses) from the issuance are held in a trust and, along with related earned interest, are classified as restricted cash. Such proceeds will be released to Texas Competitive Holdings by the trust at such time documentation of qualified expenditures are presented and approved by the trustee.

In November 2006, upon the scheduled mandatory tender date, Texas Competitive Holdings repurchased all of the Trinity River Authority of Texas Series 2001A and Brazos River Authority Series 2001B pollution control revenue bonds with aggregate principal amounts of $37 million and $19 million, respectively, at a price of 100% of the principal amount thereof. Texas Competitive Holdings currently plans to remarket these bonds.

In June 2006, upon the scheduled mandatory tender date, Texas Competitive Holdings repurchased all of the Brazos River Authority Pollution Control Revenue (Refunding) Bonds Series 1995B with an aggregate principal amount of $114 million at a price of 100% of the principal amount thereof. Texas Competitive Holdings currently plans to remarket these bonds.

In May 2006, upon the scheduled mandatory tender date, Texas Competitive Holdings repurchased all of the Brazos River Authority Pollution Control Revenue (Refunding) Bonds Series 1994B and 1995A with aggregate principal amounts of $39 million and $50 million, respectively, at a price of 100% of the principal amounts thereof. Texas Competitive Holdings currently plans to remarket these bonds.

In May 2006, the equity-linked Series M Senior Notes with an aggregate principal amount of $179 million were remarketed to fund the settlement of the associated common stock purchase contracts. Energy Future Holdings Corp. participated in the remarketing and purchased all of the outstanding Series M Senior Notes at a price of 100.5% of par and immediately retired the notes resulting in a loss on retirement of $1 million.

In March 2006, Texas Competitive Holdings issued the Brazos River Authority Series 2006 Pollution Control Revenue Bonds with an aggregate principal amount of $100 million. The bonds have a fixed interest rate of 5.0% and mature in March 2041. Net proceeds of $100 million (principal amount less issuance expenses) from the issuance are held in a trust and, along with related earned interest, are classified as restricted cash. Such proceeds will be released to Texas Competitive Holdings by the trust at such time as documentation of qualified expenditures are presented and approved by the trustee.

Other retirements of long-term debt in 2006 totaling $1.3 billion represented payments at scheduled maturity dates and included $733 million of Energy Future Holdings Corp. senior notes and $400 million of Texas Competitive Holdings senior notes.

Debt-related Activity in 2005—In December 2005, in connection with the consolidation of the combustion turbine lease trust, Energy Future Holdings Corp. assumed $91 million principal amount of 7.460% fixed secured bonds with amortizing principal payments through 2015. See Note 4 for additional discussion.

In November 2005, Texas Competitive Holdings remarketed the Sabine River Authority Series 2001C and the Brazos River Authority Series 1994A pollution control revenue bonds with aggregate principal amounts of $70 million and $39 million, respectively. The bonds were purchased upon mandatory tender in November 2003 and May 2005, respectively.

In July 2005, the remaining publicly outstanding $92 million principal amount of Oncor Electric Delivery’s Fixed First Mortgage Bonds matured and was paid. In a related action, in October 2005 Oncor Electric Delivery

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released the liens associated with its 2002 Secured Indenture resulting in its Senior Secured Notes becoming unsecured obligations of Oncor Electric Delivery ranking equally with all of its other unsecured obligations. Because the First Mortgage Bonds that served as collateral for the 2002 Secured Indenture were returned to Oncor Electric Delivery in connection with that release and Oncor Electric Delivery no longer had any publicly outstanding First Mortgage Bonds, Oncor Electric Delivery discharged its 1983 Mortgage in October 2005. As a result of these actions, Oncor Electric Delivery no longer has any secured debt outstanding.

In January 2005, Texas Competitive Holdings remarketed and converted to floating rate mode the Brazos River Authority Series 2001A pollution control revenue bonds with an aggregate principal amount of $71 million. The bonds were purchased upon mandatory tender in April 2004.

Other retirements of long-term debt in 2005 totaling $138 million represent payments at scheduled maturity dates.

Fair Value Hedges—Energy Future Holdings Corp. uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At December 31, 2006, $2.5 billion of fixed rate debt had been effectively converted to variable rates through interest rate swap transactions, expiring through 2024. These swaps qualified for and were designated as fair value hedges in accordance with SFAS 133 (under the short-cut method as the conditions for assuming no ineffectiveness are met). In December 2006, interest rate swaps related to $300 million principal amount of debt were dedesignated as fair value hedges. Offsetting swap positions were entered into and both the original swaps and offsetting positions are subsequently being marked-to-market in net income.

Long-term debt fair value adjustments—

	At December 31,
	2006			2005
Long-term debt fair value adjustments related to interest rate swaps at beginning of period—net (reduction) increase in debt carrying value	$	(44	)	$	15
Fair value adjustments during the period		(13	)		(49	)
Recognition of net gains on settled fair value hedges(a)		(6	)		(10	)
Long-term debt fair value adjustments at end of period—net reduction in debt carrying value (net out-of-the-money value of swaps)	$	(63	)	$	(44	)

(a) Net value of settled in-the-money fixed-to-variable swaps recognized in net income when the hedged transactions are recognized. Amounts are pretax.

Any changes in unsettled swap fair values reported as fair value adjustments to debt amounts are offset by changes in derivative assets and liabilities.

Securitization (Transition) Bonds—Under a regulatory financing order authorizing the issuance of $1.3 billion principal amount of transition bonds to recover regulatory assets, a bankruptcy-remote financing subsidiary of Oncor Electric Delivery issued $500 million principal amount of transition bonds in August 2003 and the remaining $790 million principal amount in June 2004. Amounts to service the principal and interest on the bonds are recovered from REPs by Oncor Electric Delivery through a distribution fee surcharge. Also see Note 4.

Convertible Senior Notes—At December 31, 2006 and 2005, Energy Future Holdings Corp. had $25 million principal amount outstanding of its Floating Rate Convertible Senior Notes due 2033. The notes bear regular interest at an annual floating rate equal to 3-month LIBOR, determined quarterly, plus 150 basis points, and are payable in arrears quarterly commencing October 15, 2003. The notes will bear additional contingent interest during periods after July 15, 2008 if the average trading price of the notes for a specified period exceeds 120% of the principal amount of

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the notes. The notes conversion rate at December 31, 2006 is 60.2958 shares of Energy Future Holdings Corp. common stock per $1,000 principal amount of notes, which equates to 1,523,916 shares. Should the holders elect to convert the notes, Energy Future Holdings Corp. has the option to settle the conversion in cash, common stock or a combination of both. At December 31, 2006, Energy Future Holdings Corp. intended to settle any future conversion of the remaining $25 million principal amount of outstanding notes in common stock.

Maturities—Transition bond sinking fund requirements and other long-term debt maturities at December 31, 2006, were as follows:

Year
2007	$	474
2008		576
2009		1,129
2010		135
2011		143
Thereafter		8,644
Unamortized premium and discount and fair value adjustments		(83	)
Capital lease obligations		98
Total	$	11,116

16. COMMITMENTS AND CONTINGENCIES

Commitments

Generation Development Program—In April 2006, Energy Future Holdings Corp. announced a plan to develop and construct up to 11 lignite/coal-fueled generation facilities in Texas, the development of eight of which were suspended in February 2007. Subsidiaries of Energy Future Holdings Corp. have executed engineering, procurement and construction (EPC) agreements for the three units now expected to be completed. Energy Future Holdings Corp. or the EPC contractors had placed orders for critical long lead-time equipment, including boilers, turbine generators and air quality control systems for all 11 units. Capital expenditures under these arrangements totaled $1.0 billion as of December 31, 2006. If the agreements had been canceled as of that date, an additional estimated obligation of up to $430 million would have arisen. This estimated gross cancellation exposure of $1.4 billion at December 31, 2006 excluded any recovery values related to the assets acquired and for owned assets that are intended to be utilized in the program.

Other Contractual Commitments—At December 31, 2006, Energy Future Holdings Corp. had noncancelable commitments under energy-related contracts, leases and other agreements as follows:

	Coal purchase agreements and coal transportation agreements		Pipeline transportation and storage reservation fees		Capacity payments under power purchase agreements(a)		Nuclear Fuel Contracts		Water Rights Contracts
2007	$	151	$	62	$	107	$	82	$	6
2008		98		42		54		134		7
2009		102		38		—		111		7
2010		—		37		—		36		7
2011		—		38		—		26		7
Thereafter		—		16		—		121		53
Total	$	351	$	233	$	161	$	510	$	87

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(a) On the basis of Energy Future Holdings Corp.’s current expectations of demand from its electricity customers as compared with its capacity and take-or-pay payments, management does not consider it likely that any material payments will become due for electricity not taken beyond capacity payments.

Future minimum lease payments under both capital leases and operating leases are as follows:

	Capital Leases		Operating Leases(a)
2007	$	17	$	52
2008		16		47
2009		15		47
2010		14		45
2011		10		41
Thereafter		47		285
Total future minimum lease payments		119	$	517
Less amounts representing interest		21
Present value of future minimum lease payments		98
Less current portion		11
Long-term capital lease obligation	$	87

(a) Includes operating leases with initial or remaining noncancelable lease terms in excess of one year. Excludes Texas Competitive Holdings’ future minimum lease payments for combustion turbines owned by a lease trust of $17 million in 2007, $17 million in 2008, $17 million in 2009, $17 million in 2010, $17 million in 2011 and $51 million in periods thereafter.

Texas Competitive Holdings has commitments in place to replace the four steam generators and reactor vessel head in Unit 1 of the Comanche Peak nuclear plant in order to maintain the operating efficiency of the unit. An agreement for the manufacture and delivery of the equipment was completed in October 2003 and equipment delivery occurred in late 2006. Estimated future project capital spending to complete the installation, expected in 2007, totals $87 million.

Contingencies

Litigation—On February 28, 2007, a lawsuit was filed in the 160^th District Court, Dallas County, Texas seeking compensatory damages and injunctive relief arising out of the Merger Agreement. The suit, filed by putative Energy Future Holdings Corp. shareholder, International Brotherhood of Electrical Workers Local 98 Pension Fund, individually, and as a class action for similarly situated shareholders, alleges that directors of Energy Future Holdings Corp. breached fiduciary duties owed Energy Future Holdings Corp. shareholders by approving the Merger Agreement. Named as defendants are Energy Future Holdings Corp. and directors of its Board, as well as private equity firms and investors involved in the transaction. Energy Future Holdings Corp. believes the claims made in this litigation are without merit and, therefore, intends to vigorously defend this litigation, including demonstrating to the court that the Merger Agreement contains a “go-shop” provision pursuant to which Energy Future Holdings Corp. has the right to solicit and engage in discussions and negotiations with respect to competing proposals through April 16, 2007 and that the transaction is subject to the approval of Energy Future Holdings Corp.’s shareholders. Further, the suit purports to assert claims by shareholders directly against the Board of Directors when Energy Future Holdings Corp. believes that Texas law does not recognize such a cause of action.

On February 27, 2007, a lawsuit was filed in the 68^th District Court, Dallas County, Texas arising out of the Merger Agreement. The suit, filed by putative Energy Future Holdings Corp. shareholders Gary and Lon Grady, alleges that directors of Energy Future Holdings Corp., named as defendants, breached fiduciary duties owed

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Energy Future Holdings Corp. by approving the Merger Agreement. The petition includes claims that directors and/or officers failed to ensure that the transaction was in the best interest of Energy Future Holdings Corp.; that the directors participated in a transaction where their loyalties were divided and where they were to receive a personal financial benefit; and that such alleged conduct constituted a breach of their duties of care, loyalty, good faith, candor and independence owed to Energy Future Holdings Corp. Energy Future Holdings Corp. believes the claims made in this litigation are without merit and, therefore, intends to vigorously defend this litigation, including demonstrating to the court that the Merger Agreement allows Energy Future Holdings Corp. to solicit other proposals from third parties through April 16, 2007 and that the transaction is subject to the approval of Energy Future Holdings Corp.’s shareholders. Further, Energy Future Holdings Corp. believes that the plaintiffs failed to comply with provisions of the Texas Business Organizations Code applicable to filing a derivative proceeding.

On February 27, 2007, a lawsuit was filed in the 162^nd District Court, Dallas County, Texas by putative Energy Future Holdings Corp. common stock shareholder, J&B Charitable Remainder Trust, asserting claims individually and as a class action on behalf of allegedly similarly situated shareholders. The suit named the directors of Energy Future Holdings Corp. as defendants as well as two private equity firms. The lawsuit contends that the directors violated various fiduciary duties in connection with the February 25, 2007 execution of the Merger Agreement. Plaintiff seeks to enjoin defendants from consummating the Merger Agreement until such time as a procedure or process is adopted to obtain the highest possible price for Energy Future Holdings Corp. shareholders, as well as a request that the court order the directors of Energy Future Holdings Corp. to exercise their fiduciary duties in order to obtain a transaction in the best interest of Energy Future Holdings Corp. shareholders. The Merger Agreement allows Energy Future Holdings Corp. to solicit other proposals from third parties through April 16, 2007 and is subject to the approval of Energy Future Holdings Corp.’s shareholders. Further, the suit purports to assert claims by shareholders directly against the Board of Directors when Energy Future Holdings Corp. believes that Texas law does not recognize such a cause of action. Energy Future Holdings Corp. believes the claims made in this litigation are without merit and, therefore, intends to vigorously defend this litigation.

On February 26, 2007, a lawsuit was filed in the 101^st District Court, Dallas County, Texas by putative Energy Future Holdings Corp. shareholder, Samuel T. Cohen, asserting claims individually and as a class action on behalf of allegedly similarly situated shareholders. The suit named the directors of Energy Future Holdings Corp. as defendants as well as two private equity firms. The lawsuit contends that the directors violated various fiduciary duties in connection with the February 25, 2007 execution of the Merger Agreement. Plaintiff seeks to enjoin defendants from consummating the transactions contemplated by the Merger Agreement until such time as a procedure or process is adopted to obtain the highest possible price for Energy Future Holdings Corp. shareholders, as well as a request that the court direct the officers and directors of Energy Future Holdings Corp. to exercise their fiduciary duties in order to obtain a transaction in the best interest of Energy Future Holdings Corp. shareholders. The Merger Agreement allows Energy Future Holdings Corp. to solicit other proposals from third parties through April 16, 2007 and is subject to the approval of Energy Future Holdings Corp.’s shareholders. Further, the suit purports to assert claims by shareholders directly against the Board of Directors when Energy Future Holdings Corp. believes that Texas law does not recognize such a cause of action. Energy Future Holdings Corp. believes the claims made in this litigation are without merit and, therefore, intends to vigorously defend this litigation.

On February 26, 2007, a lawsuit was filed in the 192^nd District Court, Dallas County, Texas seeking temporary and permanent injunctive relief arising out of the Merger Agreement. The suit, filed by putative Energy Future Holdings Corp. shareholder Brian Gottlieb, individually, and as a class action for similarly situated shareholders, alleges that directors of Energy Future Holdings Corp., named as defendants, breached fiduciary duties owed Energy Future Holdings Corp. shareholders by approving the Merger Agreement. The petition includes claims that directors failed to take steps to properly value or maximize the value of the company and breached their duties of loyalty, good faith, candor and independence owed to Energy Future Holdings Corp. shareholders. Energy Future Holdings Corp. believes the claims made in this litigation are without merit and,

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therefore, intends to vigorously defend this litigation, including demonstrating to the court that the Merger Agreement allows Energy Future Holdings Corp. to solicit other proposals from third parties through April 16, 2007 and that the transaction is subject to the approval of Energy Future Holdings Corp.’s shareholders. Further, the suit purports to assert claims by shareholders directly against the Energy Future Holdings Corp. Board of Directors when Energy Future Holdings Corp. believes that Texas law does not recognize such a cause of action.

On February 26, 2007, a lawsuit was filed in the 192^nd District Court, Dallas County, Texas seeking compensatory damages and injunctive relief arising out of the Merger Agreement. The suit, filed by Energy Future Holdings Corp. shareholder Henry Schipper, individually, and as a class action for similarly situated shareholders, alleges that directors of Energy Future Holdings Corp., named as defendants, breached their fiduciary duty owed Energy Future Holdings Corp. shareholders by approving the Merger Agreement and failing to take all reasonable steps to assure maximization of shareholder value. The petition further claims that directors failed to fully inform themselves about whether greater value could be achieved through the sale of the company to a third party. Energy Future Holdings Corp. believes the claims made in this litigation are without merit and, therefore, intends to vigorously defend this litigation, including demonstrating to the court that the Merger Agreement allows Energy Future Holdings Corp. to solicit other proposals from third parties through April 16, 2007 and that the transaction is subject to the approval of Energy Future Holdings Corp.’s shareholders. Further, the suit purports to assert claims directly against directors when Energy Future Holdings Corp. believes that Texas law does not recognize such a cause of action.

On February 25, 2007, a lawsuit was filed in District Court, Dallas County, Texas by a pension fund against the directors of Energy Future Holdings Corp., asserting claims on behalf of an owner of shares of Energy Future Holdings Corp. common stock as well as seeking to certify a class action on behalf of allegedly similarly situated shareholders. The lawsuit contends that directors of Energy Future Holdings Corp. violated various fiduciary duties owed plaintiff and other shareholders in connection with the February 25, 2007 execution of the Merger Agreement. Plaintiff seeks to enjoin defendants from consummating the Merger Agreement until such time as a procedure or process is adopted to obtain the highest possible price for shareholders, as well as a request that the court direct the officers and directors of Energy Future Holdings Corp. to exercise their fiduciary duties in order to obtain a transaction in the best interest of Energy Future Holdings Corp. shareholders. The Merger Agreement allows Energy Future Holdings Corp. to solicit other proposals from third parties through April 16, 2007 and is subject to the approval of Energy Future Holdings Corp.’s shareholders. Further, the suit purports to assert claims directly against directors when Energy Future Holdings Corp. believes that Texas law does not recognize such a cause of action. Accordingly, Energy Future Holdings Corp. believes the claims made in this litigation are without merit and, therefore, intends to vigorously defend this litigation.

On December 1, 2006, a lawsuit was filed in the United States District Court for the Western District of Texas against TXU Generation Company, LP, Oak Grove Management Company LLC, and Energy Future Holdings Corp. The complaint seeks declaratory and injunctive relief, as well as the assessment of civil penalties, with respect to the permit application for the construction and operation of the Oak Grove generation plant in Robertson County, Texas. The plaintiffs allege violations of the Federal Clean Air Act, Texas Health and Safety Code and Texas Administrative Code and seek to temporarily and permanently enjoin the construction and operation of the Oak Grove generation plant. The complaint also asserts that the permit application was deficient in failing to comply with various modeling and analyses requirements relative to the impact of emissions on the environment. Plaintiffs further request that the District Court enter an order requiring the defendants to take other appropriate actions to remedy, mitigate and offset alleged harm to the public health and environment. Energy Future Holdings Corp. believes the Oak Grove air permit, if granted by the TCEQ, will be protective of the environment and that the application for and the processing of the air permit by Oak Grove Management Company LLC with the TCEQ has been in accordance with law. Energy Future Holdings Corp. further believes that the plaintiffs’ complaint should be dismissed in response to the Motion to Dismiss, which has been filed in the litigation, and that the claims made in this litigation are without merit and, accordingly, intends to vigorously defend this litigation.

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On September 6, 2005 a lawsuit was filed in the US District Court for the Northern District of Texas, Dallas Division against Energy Future Holdings Corp. and C. John Wilder. The plaintiffs’ amended complaint asserts claims on behalf of the plaintiffs and a putative class of owners of certain Energy Future Holdings Corp. securities who tendered such securities in connection with a tender offer conducted by Energy Future Holdings Corp. in 2004. The amended complaint alleges violations of the provisions of Sections 14(e), 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 thereunder. The allegations relate to a tender offer conducted in September and October 2004 for certain equity-linked securities in which it was expressly disclosed that Energy Future Holdings Corp. management was evaluating whether it should recommend to the board of directors that the board reevaluate Energy Future Holdings Corp.’s dividend policy. After the tender offer was closed, and consistent with the disclosure, management did make a recommendation to the board to reevaluate the dividend policy and the board elected to increase the quarterly dividend. The plaintiffs contend that such disclosure in connection with the tender offer was inadequate. Energy Future Holdings Corp. maintains that the disclosure provided in connection with the tender offer regarding the evaluation of the dividend policy was complete and accurate at the time the tender offer was initiated as well as when it was closed. A Motion to Dismiss was filed by the defendants, and the District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice on August 30, 2006. The plaintiff filed a timely notice of appeal and the matter is now before the Fifth Circuit Court of Appeals with briefing of the appeal completed. While Energy Future Holdings Corp. is unable to estimate any possible loss or predict the outcome of this litigation in the event the Fifth Circuit Court of Appeals reverses the District Court, Energy Future Holdings Corp. believes the claims made in this litigation are without merit and, accordingly, intends to vigorously defend this litigation, including the appeal of the District Court’s order dismissing the complaint.

Between October 19, 2004 and October 31, 2005, twelve lawsuits were filed in various California Superior Courts by purported customers against Energy Future Holdings Corp., TXU Energy Trading Company and TXU Energy Services and other marketers, traders, transporters and sellers of natural gas in California. Plaintiffs alleged that beginning at least by the summer of 2000, defendants manipulated and fixed at artificially high levels natural gas prices in California in violation of the Cartwright Act and other California state laws. These lawsuits were coordinated in the San Diego Superior Court with numerous other natural gas actions as “In re Natural Gas Anti-Trust Cases I, II, III, IV and V.” On December 28, 2006, an agreement in principle to settle this matter was reached between the Energy Future Holdings Corp. and TXU defendants and the plaintiffs in the twelve pending lawsuits. Formal settlement documents were signed in February 2007. Notices of Dismissal were filed in the San Diego Superior Court and the case was dismissed with prejudice on February 14, 2007.

In November 2002, February 2003 and March 2003, three lawsuits were filed in the US District Court for the Northern District of Texas, Dallas Division, asserting claims under ERISA on behalf of a putative class of participants in and beneficiaries of various employee benefit plans of Energy Future Holdings Corp. These ERISA lawsuits were consolidated, and a consolidated complaint was filed in February 2004 against Energy Future Holdings Corp., the directors of Energy Future Holdings Corp. serving during the putative class period as well as certain officers of Energy Future Holdings Corp. who were the members of the TXU Thrift Plan Committee. The plaintiffs seek to represent a class of participants in such employee benefit plans during the period between April 26, 2001 and October 11, 2002. The plaintiffs filed an initial motion for class certification and, after class certification discovery was completed, the District Court denied plaintiffs’ initial class certification motion without prejudice and granted plaintiffs’ leave to amend their complaint. Plaintiffs’ second class certification motion, filed on the basis of their amended complaint, was denied and the case was ordered dismissed without prejudice on September 29, 2005. The plaintiffs filed an appeal of the dismissal to the Fifth Circuit Court of Appeals. While on appeal, the matter was referred to the Fifth Circuit’s alternative dispute resolution program and subsequently to mediation. While mediation was unsuccessful, further discussions led to an agreement in principle to settle this litigation on December 24, 2006 for $7.25 million, before attorney’s fees, to be paid by Energy Future Holdings Corp. to the thrift plan pursuant a Court approved allocation. A Memorandum of Understanding confirming the agreement in principle was signed on January 24, 2007 and the settlement is in the process of being confirmed with final settlement documents after which the settlement will be submitted to the District Court for approval. Energy Future Holdings Corp. believes the claims are without merit

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and, in the event the settlement is not approved, intends to vigorously defend the lawsuit, including the appeal. Energy Future Holdings Corp. is, however, unable to estimate any possible loss or predict the outcome of this action in the event the District Circuit rejects the settlement, the Fifth Circuit reverses the dismissal and remands the case to the District Court or the suit is refiled by the plaintiffs or others seeking to assert similar claims.

In October, November and December 2002 and January 2003, a number of lawsuits were filed in, removed to or transferred to the US District Court for the Northern District of Texas, Dallas Division, against Energy Future Holdings Corp. and certain of its officers and directors. These lawsuits were consolidated and lead plaintiffs were appointed by the Court. The consolidated complaint alleged violations of the Securities Exchange Act of 1934, as amended, Rule 10b-5 thereunder and the Securities Act of 1933, as amended. On January 20, 2005, Energy Future Holdings Corp. executed a memorandum of understanding settling this litigation for $150 million. After preliminary certification of a settlement class and notice to such class, the District Court conducted a hearing and thereafter on November 8, 2005 granted final approval of the settlement. Certain members of the settlement class who objected to the plan of allocation, the plaintiffs’ attorneys’ fees and other matters related to the approval of the settlement have appealed the orders approving the settlement to the Fifth Circuit Court of Appeals and the appeal remains pending. Energy Future Holdings Corp. believes that the issues raised on appeal are without merit but cannot predict whether the appeal might result in a remand to the District Court for reconsideration of the notice to the settlement class, the plaintiffs’ attorneys’ fees or other matters, and while Energy Future Holdings Corp. cannot predict the effect of the appeal being sustained, it does not believe that the appeal will result in reversal of the approval of the settlement.

In addition to the above, Energy Future Holdings Corp. is involved in various other legal and administrative proceedings in the normal course of business the ultimate resolution of which, in the opinion of management, should not have a material effect on its financial position, results of operations or cash flows.

Regulatory Investigations—In October 2006, TXU Portfolio Management Company (TXU Portfolio Management) was notified that the Commission had begun an investigation of its 2005 activities in the ERCOT wholesale electricity market as a result of observations noted in the2005 State of the Market Report for the ERCOT Wholesale Electricity Markets performed by Potomac Economics, an economic consulting firm. TXU Portfolio Management believes that the investigation will focus on activities involving bids to sell balancing energy and generation unit commitments. Balancing energy represents approximately five to ten percent of the total energy sold in the ERCOT wholesale market. TXU Portfolio Management is cooperating fully with the Commission in its informal investigation.

On March 18, 2005, Energy Future Holdings Corp. received a subpoena from the SEC. The subpoena required Energy Future Holdings Corp. to produce documents and other information for the period from January 1, 2001 to March 31, 2003 relating to, among other things, the financial distress at TXU Europe during 2002 and the resulting financial condition of Energy Future Holdings Corp. including reduction of Energy Future Holdings Corp.’s quarterly dividend in October 2002. Energy Future Holdings Corp. cooperated with the SEC and completed the production of the documents requested by the subpoena as well as other information requested by the SEC. Energy Future Holdings Corp. received a letter dated February 15, 2007 which stated that the investigation had been terminated and that no enforcement action had been recommended to the Commission. Accordingly, Energy Future Holdings Corp. does not expect any action by the SEC against the company related to the matters which were the subject of the investigation.

Income Tax Contingencies—Energy Future Holdings Corp. and certain of its subsidiaries are currently under audit by the IRS with respect to tax returns for various tax periods as discussed below, and are subject to audit by other taxing authorities and by the IRS for subsequent tax periods. The amount and timing of any tax assessments resulting from these audits are uncertain, and could have a material effect on Energy Future Holdings Corp.’s liquidity and results of operations. Certain audit matters as to which management believes there is a reasonable possibility of a material future tax assessment are discussed below.

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Energy Future Holdings Corp. 1997-2002 Audit—The IRS is currently examining Energy Future Holdings Corp.’s federal income tax returns for 1997-2002. A tax basis step-up of assets that occurred at ENSERCH Corporation prior to its 1997 acquisition by Energy Future Holdings Corp. resulted in a Energy Future Holdings Corp. audit issue as a result of the 2000 sale of the assets. The issue was resolved with the IRS in the first quarter of 2006, and a reserve of $62 million was released (see Note 3). In addition to proposed adjustments with respect to the worthlessness of Energy Future Holdings Corp.’s investment in TXU Europe (discussed separately below), the IRS has issued notices of proposed adjustment with respect to several other items. The IRS is expected to complete its examination in the second quarter of 2007. Energy Future Holdings Corp. expects to protest a number of adjustments and further expects that the protested issues will not be resolved until after 2007. Management believes that tax reserves recorded for potential adjustments to Energy Future Holdings Corp.’s 1997-2002 tax returns are adequate to provide for the expected outcome of the IRS’s proposed adjustments.

Energy Future Holdings Corp. 2003-2005 Audit—Energy Future Holdings Corp. expects that the IRS will commence an examination of its 2003 through 2005 tax returns during 2007. Consistent with its experience in prior audits, Energy Future Holdings Corp. expects that the IRS will propose adjustments to the tax returns and that Energy Future Holdings Corp. will incur some liability to resolve those proposed adjustments with the IRS. The precise nature and amount of any such proposed adjustments is uncertain but the likelihood of occurrence is probable. Energy Future Holdings Corp. has recorded reserves related to potential audit adjustments, representing the estimated tax expense to be incurred as a result of such audit adjustments.

TXU Gas (formerly ENSERCH Corporation) Audits—The IRS audits of the 1993 and 1994-1997 ENSERCH tax returns were closed in 2005. As part of the close of the audit, the IRS filed a notice of deficiency for tax. Although Energy Future Holdings Corp. does not believe that the notice of deficiency is supportable under existing facts and law, Energy Future Holdings Corp. paid this tax and related interest totaling $30 million in 2005, but in 2006 filed a refund claim for these and additional amounts. The IRS and Energy Future Holdings Corp. have extended the time to file suit for refund so the government may review the claim.

TXU Europe—On its US federal income tax return for calendar year 2002, Energy Future Holdings Corp. claimed an ordinary loss deduction related to the worthlessness of Energy Future Holdings Corp.’s investment in TXU Europe, the tax benefit of which is estimated to be $983 million (assuming the deduction is sustained on audit). Due to a number of uncertainties regarding the proper tax treatment of the worthlessness loss, no portion of the tax benefit related to Energy Future Holdings Corp.’s 2002 write-off of its investment in TXU Europe was recognized in income prior to the second quarter of 2004.

In June 2004, the IRS issued a preliminary notice of proposed adjustment (subsequently amended in September 2004) proposing to disallow the 2002 worthlessness deduction and treat the worthlessness as a capital loss (deductible only against capital gains). In addition, in 2004 Energy Future Holdings Corp. revised the estimates of capital losses and ordinary deductions expected from the worthlessness deduction utilization. Accordingly, in 2004 Energy Future Holdings Corp. recorded a tax benefit of $755 million ($680 million classified as discontinued operations) related to the TXU Europe worthlessness deduction, which reflects expected utilization of the capital loss deduction against capital gains realized in 2004 and prior periods. The benefit recognized also included $220 million for deductions related to the write-off of the investment in TXU Europe expected to be sustained as ordinary as a result of the preliminary notice.

The tax benefits recognized are based on the notice of proposed adjustment, adjusted to exclude the effects of elements of the IRS notice that Energy Future Holdings Corp. believes are without merit and unlikely to be sustained. While the notice of proposed adjustment is not binding on the IRS and therefore it is uncertain what positions the IRS might ultimately assert or what, if any, tax liability might result, Energy Future Holdings Corp. believes that the possibility of the IRS adopting a more adverse position is remote.

If Energy Future Holdings Corp.’s ordinary loss deduction claimed on the 2002 tax return is not sustained, Energy Future Holdings Corp. would be required to repay approximately $665 million in tax refunds previously

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received, inclusive of related interest, based on the assumptions used to determine the tax benefits recognized after receipt of the notice of proposed adjustments, and before taking into account other potential IRS adjustments to Energy Future Holdings Corp.’s 1997-2002 tax returns. These amounts are reported as noncurrent liabilities on the December 31, 2006 balance sheet. No material earnings charge is expected with respect to any such repayment. Energy Future Holdings Corp. is unable to predict the timing of any such repayment.

Energy Future Holdings Corp. believes that its original tax reporting of the worthlessness of its investment in TXU Europe as an ordinary deduction was proper and intends to protest the IRS’s proposed adjustments. If Energy Future Holdings Corp.’s position is sustained, a credit of approximately $79 million would be recognized in earnings.

Labor Contracts—Certain personnel engaged in Texas Competitive Holdings and Oncor Electric Delivery activities are represented by labor unions and covered by collective bargaining agreements with varying expiration dates. New one-year labor agreements were reached in 2006 covering bargaining unit personnel engaged in Texas Competitive Holdings’ lignite mining and nuclear generation operations. In January 2007, new one-year labor agreements were reached covering bargaining unit personnel engaged in the natural gas-fueled generation operations. Negotiations are currently underway with respect to the collective bargaining agreement covering bargaining unit personnel engaged in Texas Competitive Holdings’ lignite/coal-fueled generation operations. The existing Oncor Electric Delivery bargaining agreement will expire in 2007 and wages and benefits are currently being negotiated. A new bargaining unit, representing approximately 500 employees, was certified in Oncor Electric Delivery in December 2006, and negotiations will begin on an initial labor agreement in early 2007. Management expects that any changes in collective bargaining agreements will not have a material effect on Energy Future Holdings Corp.’s financial position, results of operations or cash flows; however, Energy Future Holdings Corp. is unable to predict the ultimate outcome of these labor negotiations.

Environmental Contingencies—The federal Clean Air Act, as amended (Clean Air Act) includes provisions which, among other things, place limits on sulfur dioxide and nitrogen oxide emissions produced by electricity generation plants. The capital requirements of Energy Future Holdings Corp. and its subsidiaries have not been significantly affected by the requirements of the Clean Air Act. In addition, all air pollution control provisions of the 1999 Restructuring Legislation have been satisfied.

Energy Future Holdings Corp. and its subsidiaries must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. Energy Future Holdings Corp. and its subsidiaries are in compliance with all current laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulation is not determinable.

The costs to comply with environmental regulations can be significantly affected by the following external events or conditions:

• enactment of state or federal regulations regarding CO₂ emissions;

• other changes to existing state or federal regulation regarding air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters; and

• the identification of sites requiring clean-up or the filing of other complaints in which Energy Future Holdings Corp. or its subsidiaries may be asserted to be potential responsible parties.

Guarantees—As discussed below, Energy Future Holdings Corp. and its subsidiaries have entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions. Guarantees issued or modified after December 31, 2002 are subject to the recognition and initial measurement provisions of FIN 45, which requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.

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Disposed TXU Gas operations—In connection with the TXU Gas transaction in October 2004, Energy Future Holdings Corp. agreed, for a period of three years from the disposition date, to indemnify Atmos Energy Corporation for certain qualified environmental claims that may arise in relation to the assets acquired by Atmos Energy Corporation. Energy Future Holdings Corp. is not required to indemnify Atmos Energy Corporation until the aggregate of all such qualified claims exceeds $10 million, and Energy Future Holdings Corp. is only required to indemnify Atmos Energy Corporation for 50% of qualified claims between $10 million and $20 million. The maximum amount that Energy Future Holdings Corp. would be required to pay Atmos Energy Corporation pursuant to this environmental indemnity is $192.5 million. In addition, Energy Future Holdings Corp. agreed to indemnify Atmos Energy Corporation for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos Energy Corporation, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. In each case, Energy Future Holdings Corp.’s indemnification is limited to 10 years from the disposition date. The maximum aggregate amount that Energy Future Holdings Corp. may be required to pay is $1.9 billion. The estimated fair value of the indemnification recorded upon completion of the TXU Gas transaction was $2.5 million. To date, Energy Future Holdings Corp. has not been required to make any payments to Atmos Energy Corporation under this indemnity obligation, and no such payments are currently anticipated.

In 1992, a discontinued engineering and construction business of TXU Gas completed construction of a plant, the performance of which is guaranteed by TXU Gas through 2008. The maximum contingent liability under the guarantee is approximately $114 million. No claims have been asserted under the guarantee and none are currently anticipated. Energy Future Holdings Corp. retains this contingent liability under the terms of the TXU Gas transaction agreement.

Residual value guarantees in operating leases—Energy Future Holdings Corp. or a subsidiary is the lessee under various operating leases that guarantee the residual values of the leased facilities. At December 31, 2006, the aggregate maximum amount of residual values guaranteed was approximately $128 million with an estimated residual recovery of approximately $125 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the lease portfolio is approximately six years. A significant portion of the maximum guarantee amount relates to leases entered into prior to December 31, 2002.

Indebtedness guarantee—In 1990, Energy Future Competitive Holdings Company repurchased an electric co-op’s minority ownership interest in the Comanche Peak nuclear generation plant and assumed the co-op’s indebtedness to the US government for the facilities. The indebtedness is included in long-term debt reported in the consolidated balance sheet. Energy Future Competitive Holdings Company is making principal and interest payments to the co-op in an amount sufficient for the co-op to make payments on its indebtedness. Energy Future Competitive Holdings Company guaranteed the co-op’s payments, and in the event that the co-op fails to make its payments on the indebtedness, the US government would assume the co-op’s rights under the agreement, and such payments would then be owed directly by Energy Future Competitive Holdings Company. At December 31, 2006, the balance of the indebtedness was $121 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities.

Letters of Credit—At December 31, 2006, Texas Competitive Holdings had outstanding letters of credit under its revolving credit facilities in the amount of $455 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions, and for miscellaneous credit support requirements. As of December 31, 2006, approximately 28% of the obligations supported by these letters of credit mature within one year, and substantially all of the remainder mature in the next four years.

Further, Texas Competitive Holdings has outstanding letters of credit under its revolving credit facilities totaling $455 million at December 31, 2006 to support existing floating rate pollution control revenue bond debt of $446 million principal amount. The letters of credit are available to fund the payment of such debt obligations and expire in 2009.

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Security Interest—A first-lien security interest has been placed on the two lignite/coal-fueled generation units at Texas Competitive Holdings’ Big Brown plant to support commodity hedging transactions.

Nuclear Insurance—Nuclear insurance includes liability coverage, property damage, decontamination and premature decommissioning coverage and accidental outage and/or extra expense coverage. The liability coverage is governed by the Price-Anderson Act (Act), while the property damage, decontamination and premature decommissioning coverage is promulgated by the rules and regulations of the NRC. Energy Future Holdings Corp. intends to maintain insurance against nuclear risks as long as such insurance is available. Energy Future Holdings Corp. is self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Such losses could have a material adverse effect on Energy Future Holdings Corp.’s financial condition and its results of operations and cash flows.

With regard to liability coverage, the Act provides financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $10.8 billion and requires nuclear generation plant operators to provide financial protection for this amount. The US Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $10.8 billion limit for a single incident mandated by the Act. As required, Energy Future Holdings Corp. provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodily injury and property damage through a combination of private insurance and industry-wide retrospective payment plans. As the first layer of financial protection, Energy Future Holdings Corp. has $300 million of liability insurance from American Nuclear Insurers (ANI), which provides such insurance on behalf of a major stock insurance company pool, Nuclear Energy Liability Insurance Association. The second layer of financial protection is provided under an industry-wide retrospective payment program called Secondary Financial Protection (SFP).

Under the SFP, in the event of an incident at any nuclear generation plant in the US, each operating licensed reactor in the US is subject to an assessment of up to $100.6 million plus a 3% insurance premium tax, subject to increases for inflation every five years. Assessments are limited to $15 million per operating licensed reactor per year per incident. Energy Future Holdings Corp.’s maximum potential assessment under the industry retrospective plan would be $201.2 million (excluding taxes) per incident but no more than $30 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $300 million per accident at any nuclear facility. The SFP and liability coverage are not subject to any deductibles.

With respect to nuclear decontamination and property damage insurance, the NRC requires that nuclear generation plant license-holders maintain at least $1.1 billion of such insurance and require the proceeds thereof to be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds can be used for plant repair or restoration or to provide for premature decommissioning. Energy Future Holdings Corp. maintains nuclear decontamination and property damage insurance for Comanche Peak in the amount of $3.5 billion (subject to $1 million deductible per accident), above which Energy Future Holdings Corp. is self-insured. The $3.5 billion consists of a primary layer of coverage of $500 million provided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurance company, $2.25 billion of premature decommissioning coverage provided by NEIL and $737 million of other property damage coverage from other insurance markets and foreign nuclear insurance pools.

Energy Future Holdings Corp. maintains Accidental Outage Insurance through NEIL to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at Comanche Peak are out of service for more than twelve weeks as a result of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-two weeks and $2.8 million for the next 110 weeks for each outage, respectively, after the initial twelve-week waiting period. The total maximum coverage is $490 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.

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If NEIL’s losses exceeded its reserves for the applicable coverages, potential assessments total $14.5 million for primary property, $14.1 million for excess property and $8.3 million for accidental outage.

Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL would make available one industry aggregate limit of $3.2 billion plus any amounts it recovers from other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply. Under the ANI liability policy, the liability arising out of terrorist acts will be subject to one industry aggregate limit of $300 million that could be reinstated at ANI’s option depending on prevailing risk circumstances and the balance in the Industry Credit Rating Plan reserve fund. Under the US Terrorism Risk Insurance Extension Act of 2005, the US government provides reinsurance with respect to acts of terrorism in the US for losses caused by an individual or individuals acting on behalf of foreign parties. In such circumstances, the NEIL and ANI terrorism aggregates would not apply.

17. SHAREHOLDERS’ EQUITY

Declaration of Dividend—At its February 2007 meeting, the Board of Directors of Energy Future Holdings Corp. declared a quarterly dividend of $0.4325 a share, payable April 2, 2007 to shareholders of record on March 2, 2007.

Stock Split—In 2005, Energy Future Holdings Corp.’s board of directors declared a two-for-one stock split effected in the form of a 100 percent stock dividend. The stock split entitled each shareholder of record at the close of business on November 18, 2005, to receive one additional share for every outstanding share of common stock they held on that date. The additional shares resulting from the stock split were distributed on December 8, 2005.

Common Stock Repurchase—In November 2005, the Energy Future Holdings Corp. board of directors authorized the repurchase of up to 34 million shares of common stock through the end of 2006. This authorization has been extended to year end 2007. Additionally, in November 2006, the Energy Future Holdings Corp. board of directors authorized the repurchase of an additional 20 million shares of common stock through year end 2007. Under these authorities, Energy Future Holdings Corp. has repurchased and retired approximately 31 million shares, including 12 million shares in November 2005 and 19 million shares during the twelve months ended December 31, 2006 at an average price of $49.51 and $51.77 per share, respectively, (including related fees and expenses).

Common Stock Issuance—In May 2006, Energy Future Holdings Corp. settled the purchase contracts associated with its remaining equity-linked debt securities. In connection with the settlement, Energy Future Holdings Corp. issued 5.7 million shares of common stock, resulting in an increase in additional paid-in capital of $180 million.

Accelerated Share Repurchase Program—In November 2004, Energy Future Holdings Corp. entered into an agreement with a broker-dealer counterparty under which Energy Future Holdings Corp. repurchased and retired 105 million shares of its outstanding common stock at an initial price of $32.29 per share for a total of $3.4 billion. Under the agreement, the counterparty immediately borrowed shares that were sold to and canceled by Energy Future Holdings Corp. and in turn purchased shares in the open market over a subsequent time period; the agreement was subject to a future contingent purchase price adjustment based on the actual price of the shares purchased by the counterparty. In May 2005, Energy Future Holdings Corp. paid $523 million (including related fees and expenses) in cash to the counterparty in full settlement of the transaction. The counterparty had repurchased the shares under the agreement at an average price per share of $36.91.

Thrift Plan—The Thrift Plan is an employee savings plan under which Energy Future Holdings Corp. matches a portion of employees’ contributions of their earnings with a contribution in shares of common stock. Contributions to the Thrift Plan are held by an unconsolidated trust. At December 31, 2006, the Thrift Plan had

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an obligation of $210 million outstanding in the form of a note payable to Energy Future Holdings Corp. (LESOP note). Proceeds from the issuance of the note, which Energy Future Holdings Corp. purchased from a third-party lender in 1990, were used by the Thrift Plan trustee to purchase Energy Future Holdings Corp. common stock on the open market for the purpose of satisfying future matching requirements. These shares (LESOP shares) are held by the Thrift Plan trustee under the leveraged employee stock ownership provision of the Thrift Plan. The note receivable has been classified as a reduction of common stock equity, and the principal and related interest is being amortized as a component of LESOP-related expense.

At December 31, 2006, the Thrift Plan trustee held 6,177,171 shares of Energy Future Holdings Corp. common stock. The Thrift Plan uses dividends received on the LESOP shares held and contributions from Energy Future Holdings Corp., if required, to repay interest and principal on the LESOP note; such contributions totaled $17 million in 2006 and $19 million in 2005. The net expense associated with the Thrift Plan totaled $24 million in 2004, which included $14 million representing the cost of additional matching contributions; the amounts in 2006 and 2005 were not significant.

Direct Stock Purchase and Dividend Reinvestment Plan—Issuances of new shares to satisfy purchases by participants in this plan (including reinvestment of dividends) increased common stock by $4 million in 2004. Since April 2004, share purchases by participants have been satisfied through purchases in the open market by Energy Future Holdings Corp.

At December 31, 2006, authorized but unissued common shares of Energy Future Holdings Corp. were registered with the SEC for new issuance pursuant to provisions of the following:

	Number of Shares
DRIP Plan	3,710,195
Thrift Plan	8,849,200
Long-Term Incentive Compensation Plan	5,426,007
Omnibus Incentive Compensation Plan	17,976,140
Convertible senior notes	1,523,916
Other	1,345,494
Total	38,830,952

Energy Future Holdings Corp. Preference Stock—In June 2005, Energy Future Holdings Corp. redeemed for cash all 3,000 shares of its Series B preference stock outstanding (liquidation preference of $100,000 per share) at the aggregate principal amount of $300 million. The preference stock had a dividend rate of 7.24%.

Energy Future Competitive Holding Company’s Preferred Stock—In August 2005, Energy Future Competitive Holdings Company redeemed all 379,231 shares of its outstanding preferred stock with a stated value of $38 million for approximately $40 million in cash, including principal, premium and accrued dividends. The preferred stock had dividend rates ranging from $4.00 to $5.08 per share. In December 2005, Energy Future Competitive Holdings Company reissued 788 shares of its $4.56 Series preferred stock in private placement transactions.

Exchangeable Preferred Membership Interests of Texas Competitive Holdings—In April 2004, Energy Future Holdings Corp. repurchased Texas Competitive Holdings’ exchangeable preferred membership interests with a liquidation amount of $750 million for $1.85 billion (including transaction costs). The excess of the purchase price over the carrying value of the securities, net of $384 million in income tax benefits recorded as a deferred tax asset, was recorded as a charge to additional paid-in capital in the amount of $849 million. The carrying value of the securities was $617 million, which is the liquidation amount of $750 million net of $102 million in unamortized discount and $31 million in unamortized debt issuance costs, both recorded at the time of issuance of the securities in November 2002. The charge to additional paid-in capital was accounted for in a manner similar to Energy Future Holdings Corp.’s preference share dividends, resulting in a reduction in net income available to common shareholders.

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Dividend Restrictions—At December 31, 2006, there were no restrictions on the payment of common stock dividends or redemption of outstanding shares of Energy Future Holdings Corp. common stock.

The table below reflects the changes in the number of Energy Future Holdings Corp. common stock shares outstanding:

	2006		2005		2004
Balance at beginning of year	470,845,978		479,705,760		647,766,184
Issuances under equity-linked debt securities	5,683,791		2,708,250		3,634,742
Issuances under Direct Stock Purchase and Dividend Reinvestment Plan	—		—		220,028
Issuances under stock-based incentive compensation plans (Note 22)	2,200,766		1,093,480		1,187,028
Issued on conversion of convertible senior notes	—		9,716		—
Repurchases	(18,165,403	)	(12,476,228	)	(168,514,888	)
Forfeitures and cancellations under stock-based incentive compensation plan	(1,320,609	)	(195,000	)	(4,587,334	)
Balance at end of year	459,244,523		470,845,978		479,705,760

18. COMMODITY CONTRACT ASSETS AND LIABILITIES

Commodity contract assets and liabilities primarily represent mark-to-market values of natural gas and electricity derivative instruments that have not been designated as cash flow hedges or “normal” purchases or sales under SFAS 133.

Current and noncurrent commodity contract assets totaling $438 million and $1.9 billion at December 31, 2006 and 2005, respectively, are stated net of applicable credit (collection) and performance reserves totaling $9 million and $12 million, respectively. Performance reserves are provided for direct, incremental costs to settle the contracts.

Current and noncurrent commodity contract liabilities totaled $461 million and $2.0 billion at December 31, 2006 and 2005, respectively. The balance at December 31, 2006 includes a $109 million “day one” loss recorded in the second quarter of 2006 associated with a related series of hedging contracts entered into at below market prices. The contracts, the value of which are based on natural gas prices, are intended to hedge exposure to future changes in electricity prices. The loss was recorded as a reduction of revenues, consistent with other mark-to-market gains and losses, and is included in the results of the Competitive Electric segment. Future changes in fair value of the contracts, to the extent effective, are expected to be largely reflected in other comprehensive income due to designation as cash flow hedges.

19. CASH FLOW HEDGE AND OTHER DERIVATIVE ASSETS AND LIABILITIES

Cash flow hedge and other derivative assets and liabilities represent mark-to-market values of derivative contracts, the substantial majority of which have been designated as cash flow or fair value hedges under SFAS 133. Cash flow hedges consist primarily of natural gas derivative financial instruments. The change in fair value of these derivative assets and liabilities are recorded as other comprehensive income or loss to the extent the hedges are effective; the ineffective portion of the change in fair value is included in net income. (See Note 1 under “Derivative Instruments and Mark-to-Market Accounting”). Fair value hedges consist of fixed-to-variable interest rate swaps, and the change in fair value of the derivative assets and liabilities are recorded as an increase or decrease in the carrying value of the debt.

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A summary of cash flow hedge and other derivative assets and liabilities follows:

	December 31,
	2006		2005
Current and noncurrent assets:
Commodity-related cash flow hedges	$	933	$	131
Debt-related fair value hedges		4		—
Other		9		9
Total	$	946	$	140
Current and noncurrent liabilities:
Commodity-related cash flow hedges	$	23	$	295
Debt-related fair value hedges		89		71
Total	$	112	$	366

Other Cash Flow Hedge Information

Energy Future Holdings Corp. experienced cash flow hedge ineffectiveness related to positions held at the end of the period of $218 million in net gains in 2006, $38 million in net losses in 2005 and $21 million in net losses in 2004. These amounts are pretax and are reported in revenues.

The net effect of recording unrealized mark-to-market gains and losses arising from hedge ineffectiveness (versus recording gains and losses upon settlement) includes the above amounts as well as the effect of reversing unrealized ineffectiveness gains and losses recorded in previous periods to offset realized gains and losses in the current period. Such net unrealized effect totaled $239 million in net gains in 2006, $27 million in net losses in 2005 and $19 million in net losses in 2004.

As of December 31, 2006, commodity positions accounted for as cash flow hedges reduce exposure to variability of future cash flows from future revenues or purchases through 2011.

Cash flow hedge amounts reported in accumulated other comprehensive income will be recognized in earnings as the related forecasted transactions are settled or become probable of not occurring. No amounts were reclassified into earnings in 2006, 2005 or 2004 as a result of the discontinuance of cash flow hedge accounting because a hedged forecasted transaction became probable of not occurring.

Cash flow hedge amounts reported in the Statements of Consolidated Comprehensive Income exclude net gains and losses associated with cash flow hedges entered into and settled within the periods presented. These amounts totaled $31 million in after-tax net gains in 2006, $53 million in after-tax net losses in 2005 and $1 million in after-tax net gains in 2004.

Energy Future Holdings Corp. expects that $132 million of after-tax net gains related to cash flow hedges included in accumulated other comprehensive income will be reclassified into net income during the next twelve months as the related hedged transactions are settled and affect net income. Of this amount, $139 million in gains relate to commodity hedges and $7 million in losses relate to debt-related hedges. The following table summarizes after-tax balances currently recognized in accumulated other comprehensive income:

	Accumulated Other Comprehensive Income at December 31, 2006 Gain (Loss)
	Commodity- related		Debt- Related			Total
Dedesignated hedges—amounts fixed	$	131	$	(57	)	$	74
Hedges subject to fair value adjustments		337		—			337
Total	$	468	$	(57	)	$	411

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20. INVESTMENTS

The balance of investments consists of the following:

	December 31,
	2006		2005
Nuclear decommissioning trust	$	447	$	389
Assets related to employee benefit plans		197		187
Land		36		35
Note receivable from Capgemini		25		25
Investment in unconsolidated affiliates		3		3
Miscellaneous other		4		4
Total investments	$	712	$	643

Nuclear Decommissioning Trust—Deposits in a trust fund for costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor Electric Delivery’s customers as a delivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trust fund are offset by a corresponding adjustment to a regulatory asset/liability. A summary of investments in the fund follows:

	December 31, 2006
	Cost(a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities	$	169	$	5	$	(1	)	$	173
Equity securities		162		117		(5	)		274
Total	$	331	$	122	$	(6	)	$	447
	December 31, 2005
	Cost(a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities	$	151	$	5	$	(1	)	$	155
Equity securities		156		90		(12	)		234
Total	$	307	$	95	$	(13	)	$	389

(a) Includes realized gains and losses of securities sold.

Debt securities held at December 31, 2006 mature as follows: $54 million in one to five years, $60 million in five to ten years and $59 million after ten years.

Assets Related to Employee Benefit Plans—The majority of these assets represent cash surrender values of life insurance policies that are purchased to fund liabilities under deferred compensation plans. Energy Future Holdings Corp. pays the premiums and is the beneficiary of these life insurance policies. As of December 31, 2006 and 2005, the face amount of these policies totaled $501 million and $521 million, and the net cash surrender values totaled $167 million and $151 million, respectively. Changes in cash surrender value are netted against premiums paid. Other investment assets held to satisfy deferred compensation liabilities are recorded at market value.

Capgemini Agreement—In May 2004, Energy Future Holdings Corp. entered into a services agreement with Capgemini to outsource certain support activities. As part of the agreement, Capgemini was provided a royalty-free right, under an asset license arrangement, to use Energy Future Holdings Corp.’s information technology assets, consisting primarily of computer software. Energy Future Holdings Corp. obtained a 2.9% limited partnership interest in Capgemini in exchange for the asset license. Energy Future Holdings Corp. has the right to sell (the put option) its interest and the licensed software to Cap Gemini North America Inc. for $200

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million, plus its share of Capgemini’s undistributed earnings, upon expiration of the services agreement or earlier upon the occurrence of certain unexpected events. Cap Gemini North America Inc. has the right to purchase these interests under the same terms and conditions. The partnership interest has been recorded at an initial value of $2.9 million and is being accounted for on the cost method.

Energy Future Holdings Corp. recorded the estimated fair value of the put option of $177 million in 2004, reported in the balance sheet in other noncurrent assets. Of this amount, $169 million was recorded as a reduction to the carrying value of the licensed software, and the balance, which represents the fair value of the assumed cash distributions and gains while holding the partnership interest, was recorded as a noncurrent deferred credit. This accounting is in accordance with AICPA Statement of Position 98-1, “Accounting for the Costs of Computer Software Developed or Obtained for Internal Use.”

In July 2004, Energy Future Holdings Corp. loaned Capgemini $25 million for working capital purposes pursuant to a promissory note that bears interest at an annual rate of 4% and matures in July 2019.

Subject to certain terms and conditions, Cap Gemini North America, Inc. and its parent, Cap Gemini S.A., have guaranteed the performance and payment obligations of Capgemini under the services agreement, as well as payments under the put option.

21. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS

Adoption of SFAS 158—In September 2006, the FASB issued SFAS 158, which was adopted by Energy Future Holdings Corp. effective December 31, 2006, as required. SFAS 158 requires reporting in the balance sheet of the funded status of defined benefit pension and other postretirement employee benefit (OPEB) plans. Periodic pension and OPEB costs continue to be determined in accordance with SFAS 87 and SFAS 106. Under these standards, the accrued benefit obligation recognized in the balance sheet represented the cumulative difference between the net periodic benefit costs and cash funding of the plans. SFAS 87 also required the recording of a minimum pension liability representing the excess of the accumulated benefit obligation over the fair value of the plans’ assets and the accrued benefit obligation already recorded under SFAS 87. The recording of the minimum pension liability resulted in adjustments to other comprehensive income or balance sheet accounts, principally regulatory assets.

SFAS 158 requires that both the pension and OPEB accrued benefit obligation reported in the balance sheet represent the funded status of the plans based on the projected benefit obligation, which for the pension plan takes into account future compensation increases. For Energy Future Holdings Corp., the initial recognition of the funded status on the financial statements is largely reflected as an increase in the accrued benefit obligation and an increase in regulatory assets. The recording of a regulatory asset, instead of a reduction in the accumulated other comprehensive income component of shareholders’ equity as set forth in SFAS 158, is based on the regulatory recovery of retirement benefits under the June 2005 amendment to PURA. See discussion below under “Regulatory Recovery of Pension and Other Postretirement Employee Benefit Costs”.

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The following summarizes the impact on the consolidated balance sheet of adopting SFAS 158:

	December 31, 2006
	Balances Prior to Application of SFAS 158		Increase (Decrease) to Balances			Balances After Application of SFAS 158
Pension assets	$	16	$	(7	)	$	9
Noncurrent assets:
Accumulated deferred income taxes	$	176	$	14		$	190
Regulatory assets	$	61	$	343		$	404
Current liabilities:
Defined benefit pension and OPEB obligations	$	—	$	2		$	2
Noncurrent liabilities:
Defined benefit pension and OPEB obligations	$	708	$	361		$	1,069
Shareholders’ equity:
Accumulated other comprehensive income—net	$	11	$	(13	)	$	(2	)

The amounts recorded in the fourth quarter of 2006 upon adoption of SFAS 158 were based on the measurements of Energy Future Holdings Corp.’s pension and OPEB plans at the December 31, 2006 year-end date, which has been Energy Future Holdings Corp.’s practice but is now required under SFAS 158.

The recording of the total liability did not affect any financial covenants in credit agreements.

Pension Plan—Energy Future Holdings Corp. is the plan sponsor of the TXU Retirement Plan (Retirement Plan), which provides benefits to eligible employees of consolidated subsidiaries (participating employers) based on years of service and average earnings. The Retirement Plan is a defined benefit pension plan intended to qualify under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code) and is subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). Employees are eligible to participate in the Retirement Plan upon their completion of one year of service and the attainment of age 21. The Retirement Plan provides benefits to participants under one of two formulas: (i) a cash balance formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits, or (ii) a traditional defined benefit formula based on years of service and the average earnings of the three years of highest earnings. The cash balance interest component of the cash balance plan is variable and is determined using the yield on 30-year Treasury bonds.

All eligible employees hired after January 1, 2001 participate under the cash balance formula. Certain employees who, prior to January 1, 2002, participated under the traditional defined benefit formula, continue their participation under that formula. Under the cash balance formula, future increases in earnings will not apply to prior service costs. It is Energy Future Holdings Corp.’s policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.

Energy Future Holdings Corp. also has supplemental unfunded retirement plans for management employees, the information for which is included in the data below.

Minimum Pension Liability Adjustment Prior to SFAS 158—As discussed above, Energy Future Holdings Corp. recorded a minimum pension liability prior to the adoption of SFAS 158. The minimum pension liability recorded for the year ended December 31, 2005 totaled $112 million after-tax, of which a loss of $46 million after-tax was recorded as a charge to other comprehensive income and $66 million, net of deferred tax liability, was recorded as a regulatory asset. The minimum pension liability recorded for the year ended December 31, 2004 totaled $24 million after-tax and was recorded as a charge to other comprehensive income.

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Detailed Information Regarding Pension Benefits—The following information is based on December 31 measurement dates:

	Year Ended December 31,
	2006			2005			2004
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate		5.75	%		6.00	%		6.00% - 6.50	%
Expected return on plan assets		8.75	%		8.75	%		8.50	%
Rate of compensation increase		3.32	%		3.31	%		3.57	%
Components of Net Pension Cost:
Service cost	$	42		$	37		$	46
Interest cost		136			130			130
Expected return on assets		(147	)		(145	)		(142	)
Amortization of prior service cost		3			3			4
Amortization of net loss		32			20			13
Recognized curtailment loss		—			1			7
Net periodic pension cost	$	66		$	46		$	58
Assumptions used to determine benefit obligations at December 31:
Discount rate		5.90	%		5.75	%		6.00	%
Rate of compensation increase		3.44	%		3.32	%		3.57	%
Change in Pension Obligation:
Projected benefit obligation at beginning of year	$	2,440		$	2,218
Service cost		42			37
Interest cost		136			130
Plan amendments		2			—
Actuarial (gain) loss		(47	)		195
Benefits paid		(116	)		(128	)
Settlements		—			(12	)
Projected benefit obligation at end of year	$	2,457		$	2,440
Accumulated benefit obligation at end of year	$	2,297		$	2,277
Change in Plan Assets:
Fair value of assets at beginning of year	$	1,982		$	1,995
Actual return on assets		220			121
Employer contributions		4			3
Benefits paid		(116	)		(128	)
Settlements		—			(9	)
Fair value of assets at end of year	$	2,090		$	1,982
Funded Status:
Projected pension benefit obligation	$	(2,457	)	$	(2,440	)
Fair value of assets		2,090			1,982
Funded status at end of year	$	(367	)	$	(458	)
Unrecognized prior service cost		—			8
Unrecognized net loss		—			357
Accrued pension cost	$	(367	)	$	(93	)

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	December 31,
	2006			2005
Amounts Recognized in the Balance Sheet Consist of:
Other noncurrent assets(a)	$	9		$	8
Intangible asset		—			9
Regulatory asset		—			66
Other current liabilities		(2	)		—
Other noncurrent liabilities		(374	)		(304	)
Accumulated other comprehensive income		—			60
Accumulated deferred income tax assets		—			68
Net amount recognized	$	(367	)	$	(93	)
Amounts Recognized in Other Comprehensive Income and Accumulated Other Comprehensive
Income under SFAS 158 Consist of:
Net loss	$	2
Prior service cost		5
Net amount recognized	$	7
Amounts Recognized as Regulatory Assets under SFAS 158 Consist of:
Net loss	$	203
Prior service cost		3
Net amount recognized	$	206

(a) Amounts represent overfunded plans.

The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.

	Year Ended December 31,
	2006		2005
Pension Plans with PBO and ABO in Excess of Plan Assets:
Projected benefit obligation	$	2,452	$	2,435
Accumulated benefit obligation		2,291		2,271
Plan assets		2,076		1,967

Asset Allocations—The weighted-average asset allocations of pension plans by asset category are as follows:

	Allocation of Plan Assets				Target Allocation Ranges	Expected Long-term Returns
Asset Type	2006		2005
US equities	46.1	%	49.9	%	30% - 65%	9.5	%
International equities	18.6	%	16.0	%	5% - 20%	10.0	%
Fixed income	31.9	%	29.4	%	15% - 50%	6.8	%
Real estate	3.4	%	4.7	%	0% - 10%	8.2	%
	100.0	%	100.0	%		8.75	%

Expected Long-Term Rate of Return on Assets Assumption—Energy Future Holdings Corp. considered both historical returns and future expectations for returns of various asset classes in its determination of the expected long-term rate of return assumption. A key expectation is that current interest rates will move towards an equilibrium interest rate that produces a 6% yield on intermediate government bonds. Expected returns for other asset classes are based on incremental returns over such expected government bond yield. The expected return for each asset class is then weighted based on the target asset allocation to develop the expected long-term rate of return assumption for the portfolio.

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Investment Strategy—The investment objective is to provide a competitive return on the assets in each plan, while at the same time preserving the value of those assets. The strategy is to invest a third of the assets in fixed income and two thirds in equity, while maintaining sufficient cash to pay benefits and expenses.

The fixed income assets are diversified by sector and security, are intermediate in duration, and maintain an average quality rating of at least “A” (as determined by a major ratings agency such as Moody’s). The allocation to fixed income assets also includes an allocation to income producing real estate through private, unlevered real estate investment trusts. The equity assets are diversified by size, style and location with a conservative bias toward value securities.

Postretirement Employee Benefits Other Than Pensions—Energy Future Holdings Corp. offers health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service.

The following information regarding postretirement employee benefits other than pensions is based on December 31 measurement dates:

	Year Ended December 31,
	2006			2005			2004
Assumptions used to determine net periodic benefit cost:
Discount rate		5.75	%		6.00	%		6.00% - 6.50	%
Expected return on plan assets		8.67	%		8.67	%		8.66	%
Components of Net Postretirement Benefit Cost:
Service cost	$	13		$	13		$	15
Interest cost		60			56			60
Expected return on assets		(21	)		(20	)		(18	)
Amortization of net transition obligation		1			1			2
Amortization of prior service cost/(credit)		(3	)		(3	)		(2	)
Amortization of net loss		31			24			25
Recognized curtailment gain		—			—			(2	)
Net postretirement benefit cost	$	81		$	71		$	80
Assumptions used to determine benefit obligations at December 31:
Discount rate		5.90	%		5.75	%		6.00% - 6.50	%
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year	$	1,065		$	987
Service cost		13			13
Interest cost		60			56
Participant contributions		14			16
Medicare Part D reimbursement		5			—
Actuarial (gain)/loss		(150	)		62
Benefits paid		(59	)		(69	)
Benefit obligation at end of year	$	948		$	1,065
Change in Plan Assets:
Fair value of assets at beginning of year	$	245		$	229
Actual return on assets		23			12
Employer contributions		23			52
Participant contributions		14			14
Medicare Part D reimbursement		5			—
Benefits paid		(59	)		(62	)
Fair value of assets at end of year	$	251		$	245

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	Year Ended December 31,
	2006			2005
Funded Status:
Benefit obligation	$	(948	)	$	(1,065	)
Fair value of assets		251			245
Funded status at end of year		(697	)		(820	)
Unrecognized net transition obligation		—			10
Unrecognized prior service credit		—			(14	)
Unrecognized net loss		—			387
Accrued postretirement benefit obligation	$	(697	)	$	(437	)
Amounts Recognized in Other Comprehensive Income and Accumulated OtherComprehensive Income under SFAS 158 Consist of:
Net loss	$	15
Prior service cost credit		(13	)
Net transition obligation		1
Net amount recognized	$	3
Amounts Recognized as Regulatory Assets under SFAS 158 Consist of:
Net loss	$	202
Prior service cost credit		(12	)
Net transition obligation		8
Net amount recognized	$	198

The following tables provide information regarding the assumed health care cost trend rates.

	Not Medicare Eligible December 31,				Medicare Eligible December 31,
	2006		2005		2006		2005
Assumed Health Care Cost Trend Rates:
Health care cost trend rate assumed for next year	6.5	%	8	%	8	%	9	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	5.0	%	5	%	5	%	5	%
Year that the rate reaches the ultimate trend rate	2010		2010		2012		2012

	1-Percentage Point Increase		1-Percentage Point Decrease
Sensitivity Analysis of Assumed Health Care Cost Trend Rates:
Effect on accumulated postretirement obligation	$	112		$(92	)
Effect on postretirement benefits cost		8		(7	)

Asset Allocations—

The weighted average asset allocations of the OPEB plan by asset category are as follows:

	Allocation of Plan Assets December 31,
Asset Type	2006		2005
US equities	56.8	%	57.3	%
International equities	9.3	%	7.7	%
Fixed income	32.2	%	32.8	%
Real estate	1.7	%	2.2	%
	100.0	%	100.0	%

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Plan Type	Expected Long-term Returns
401(h) accounts	8.75	%
Life Insurance VEBA	8.75	%
Union VEBA	8.75	%
Non-Union VEBA	4.80	%
Insurance Continuation Reserve	7.24	%
	8.67	%

Investment strategy and the basis used to determine the expected long-term return on assets for postretirement benefit plans is similar to that discussed above for the pension plans.

Regulatory Recovery of Pension and OPEB Costs—In June 2005, an amendment to PURA relating to pension and OPEB costs was enacted by the Legislature of the State of Texas. This amendment provides for the recovery by Oncor Electric Delivery of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to its own employees consists largely of active and retired personnel engaged in Texas Competitive Holdings’ activities, related to service of those additional personnel prior to the deregulation and disaggregation of Energy Future Holdings Corp.’s business effective January 1, 2002. The amendment additionally authorizes Oncor Electric Delivery to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Accordingly, in the second quarter of 2005, Oncor Electric Delivery began deferring (principally as a regulatory asset or property) additional pension and OPEB costs for the effect of the amendment, which was retroactively effective January 1, 2005. Amounts deferred are ultimately subject to regulatory approval. Amounts recorded as a regulatory asset in 2006 totaled $34 million.

Information regarding net pension and other postretirement employee benefit costs recognized as expense follows:

	Year Ended December 31,
	2006			2005			2004
Pension costs under SFAS 87	$	66		$	46		$	58
OPEB costs under SFAS 106		81			71			80
Total benefit costs		147			117			138
Less amounts deferred principally as a regulatory asset or property		(84	)		(58	)		(27	)
Net amounts recognized as expense	$	63		$	59		$	111

Assumed Discount Rate—The discount rates reflected in net pension and other postretirement employee benefit costs are 5.75% and 6.0% in 2006 and 2005, respectively. During 2004, the discount rate assumption for the pension and other postretirement employee benefit plans was revised as a result of remeasurements required by the Capgemini and TXU Gas transactions and changing interest rates. For the first half of 2004, the discount rate was 6.25%. The rate used for the third quarter was 6.5%, and the rate used in the fourth quarter was 6.0%. In selecting the assumed discount rate, Energy Future Holdings Corp. considered fixed income security yields for an Aa rated portfolio of bonds as reported by Moody’s.

Amortization in 2007—The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized as from accumulated other comprehensive income into net periodic pension cost in 2007 total $18 million and $2 million, respectively. The estimated net loss, prior service credit and net transition obligation for the OPEB plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2007 total $14 million, a $3 million credit and $1 million, respectively.

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Contributions in 2007—Estimated funding in 2007 of the pension plan and OPEB plan total $126 million and $27 million, respectively.

Future Benefit Payments—Estimated future benefit payments to beneficiaries are as follows:

	2007			2008			2009			2010			2011			2012 - 16
Pension benefits	$	109		$	115		$	121		$	128		$	136		$	834
OPEBs	$	54		$	57		$	60		$	62		$	65		$	364
Medicare Part D subsidies received	$	(6	)	$	(7	)	$	(8	)	$	(8	)	$	(9	)	$	(55	)

Thrift Plan—Employees of Energy Future Holdings Corp. and its consolidated subsidiaries may participate in a qualified savings plan, the Thrift Plan. This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. The Thrift Plan includes an employee stock ownership component. Under the terms of the Thrift Plan, as amended effective in 2002, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the cash balance formula of the Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the traditional defined benefit formula of the Retirement Plan. Prior to January 1, 2006, employer matching contributions were invested in Energy Future Holdings Corp. common stock. Effective January 1, 2006, employees may reallocate or transfer all or part of their accumulated or future employer matching contributions to any of the plan’s other investment options. See Note 17 for additional information related to the Thrift Plan.

22. STOCK-BASED COMPENSATION PLANS

Under its shareholder-approved long-term incentive plans, Energy Future Holdings Corp. has provided discretionary awards to qualified management employees payable in its common stock. As presented below, the awards generally vest over a three-year period and the number of shares ultimately earned is based on the performance of Energy Future Holdings Corp.’s stock over the vesting period. Awards were issued in 2005 and 2006 under the current Omnibus Incentive Compensation Plan (OICP), which was approved by shareholders in May 2005. The OICP replaced the Long-Term Incentive Plan (LTIP) under which the last awards vest in 2007.

	OICP	LTIP
Vesting period	Three years	Two or three years
Potential share pay-out as a percent of initial number of awards granted	0% to 175%(a)	0% to 200%
Basis for pay-out percentage—actual Energy Future Holdings Corp. three-year share return compared to:	•     50% of award—threshold Energy Future Holdings Corp. share returns •     50% of award—share returns of companies comprising the S&P 500 Electric Utilities Index for 2005 awards and the S&P 500 Electric Utilities Index and S&P 500 Multi-Utilities Index for 2006 awards(a)	Share returns of companies comprising the S&P 500 Electric Utilities Index
Award type	Performance units payable in Energy Future Holdings Corp. stock upon vesting	Restricted stock and performance units payable in Energy Future Holdings Corp. stock upon vesting

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(a) For a small number of employees under employment agreements, potential share pay-out as a percent of initial number of awards granted is 0% to 200%, and the number of OICP shares distributed is based 100% on Energy Future Holdings Corp.’s total share return over the vesting period compared to the total returns of companies comprising the Standard & Poor’s 500 Electric Utilities Index.

In addition, Energy Future Holdings Corp. has established restrictions that limit certain employees’ opportunities to liquidate vested LTIP and OICP awards. For both restricted stock and performance unit awards, dividends over the vesting periods are converted to equivalent shares of Energy Future Holdings Corp. common stock to be distributed upon vesting.

The determination of the fair value of stock-based compensation awards at grant date is based on a Monte Carlo simulation. The more significant assumptions used in this valuation process are as follows:

• Expected volatility of the stock price of Energy Future Holdings Corp. and peer group companies—expected volatility is determined based on historical stock price volatilities using daily stock price returns for the three years prior to the grant date.

• The dividend rate for Energy Future Holdings Corp. and peer group companies based on the observed dividend payments over the twelve months prior to grant date.

• Risk-free rate (three-year U.S. Treasury securities) during the three year vesting period.

• Discount for liquidation restrictions—this factor estimates the discount for lack of marketability of vested awards due to the anticipated time for the approval and issuance of the awards, the black-out period immediately after the grant and additional holding requirements imposed on senior executives. This discount is determined based on an estimation of the cost of a protective put at the award date and is calculated using the Black-Scholes option pricing model using expected volatility assumptions based on historical and implied volatility as discussed above and a risk-free rate of return over the option period.

Assumptions	2006	2005	2004
Expected volatility	29%	25% - 30%	25% - 35%
Expected annual dividend	$1.65	$1.125	$1.50 - $2.50
Risk-free rate	4.83%	5.75%	2.54% - 3.54%
Discount for post vesting restriction	6.4% - 11.1%	6.5% - 12.5%	20% - 25%

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The following table presents information about these stock-based compensation plans:

	LTIP and OICP Awards			TXU Gas Stock Option Plan
Number of awards:
Balance—December 31, 2003		5,761,666		47,348
Granted in 2004		3,940,530		—
Forfeited/expired		(3,420,300	)	(8,610	)
Vested/exercised		(7,334	)	(33,466	)
Balance—December 31, 2004		6,274,562		5,272
Granted in 2005		1,231,392		—
Forfeited/expired		(687,940	)	(1,520	)
Vested/exercised		(1,532,032	)	(2,232	)
Balance—December 31, 2005		5,285,982		1,520
Granted in 2006		1,052,222		—
Forfeited/expired		(523,946	)	(1,520	)
Vested/exercised		(1,563,918	)	—
Balance—December 31, 2006		4,250,340		—
To vest/exercisable in—2007		2,159,509		—
To vest/exercisable in—2008		1,084,568		—
To vest/exercisable in—2009		1,006,263		—
Weighted average fair value—2006
Outstanding—Beginning of year	$	19.26
Granted	$	42.35
Forfeited	$	17.63
Vested	$	26.05
Outstanding—End of year	$	23.60
Weighted average fair value of awards granted in
2004	$	3.49
2005	$	20.68
2006	$	42.35

The above table reflects the weighted average fair value of the awards on the grant date. Principally because the 2004 awards were converted to cash-settled awards during part of 2004 as discussed below, the weighted average fair value of the 2004 awards outstanding at December 31, 2004 was $12.89.

Energy Future Holdings Corp. adopted SFAS 123R in 2004. This accounting rule eliminates the alternative of applying the intrinsic value measurement provisions of APB 25 to stock compensation awards and requires the measurement of the cost of such awards over the vesting period based on the grant-date fair value of the award. Energy Future Holdings Corp. adopted SFAS 123R using the modified retrospective method, which allows for application to only prior interim periods in the year of initial adoption and resulted in the recognition of a credit of $15 million ($10 million after-tax) cumulative effect of a change in accounting principle. For a portion of the 2004 period, the restricted stock awards were payable in cash, but the restricted stock awards were modified in December of 2004 to be payable in Energy Future Holdings Corp. common stock.

Reported expense related to the awards totaled $27 million, $32 million and $56 million ($18 million, $21 million and $36 million after-tax) in 2006, 2005 and 2004, respectively. As of December 31, 2006, unrecognized expense related to nonvested OICP and LTIP awards totaled $42 million, which is expected to be recognized over a weighted average period of two years.

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The fair value of awards that vested in 2006, 2005 and 2004 totaled $210 million, $120 million and less than $1 million, respectively, based on the vesting date share prices. The aggregate fair value of outstanding awards expected to vest totaled $321 million based on the share price and performance of Energy Future Holdings Corp. stock as of December 31, 2006.

The maximum number of shares of stock for which OICP awards may be granted under the plan is 18,000,000, of which 16,551,413 shares remain authorized and available for future issuance. The maximum number of shares of common stock for which LTIP awards may be granted under the plan is 20,000,000, of which 2,595,761 shares remain authorized and available.

Effective with the merger of ENSERCH Corporation (subsequently TXU Gas) and Energy Future Holdings Corp., in 1997 outstanding options for ENSERCH Corporation common stock were exchanged for 1,065,826 options for Energy Future Holdings Corp. common stock (TXU Gas Stock Option Plan). The weighted average exercise price for outstanding options at the beginning of 2006 was $11.95 and the weighted average exercise price for forfeited/expired options was $11.95. All options were granted on or before August 5, 1997 and expired on or before February 16, 2006. No further options may be granted under this plan.

23. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments were as follows:

	December 31, 2006						December 31, 2005
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
On balance sheet assets (liabilities):
Long-term debt (including current maturities)(a)(b)	$	(11,018	)	$	(11,308	)	$	(12,479	)	$	(12,891	)
LESOP note receivable (see Note 17)	$	210		$	242		$	220		$	259
Off balance sheet assets (liabilities):
Financial guarantees	$	—		$	(6	)	$	—		$	(8	)

(a) Excludes capital leases.

(b) 2005 amounts include stock purchase contracts related to equity-linked debt.

See Note 19 for discussion of accounting for financial instruments that are derivatives.

The fair values of on-balance sheet instruments are estimated at the lesser of either the call price or the market value as determined by quoted market prices, where available, or, where not available, at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risk.

The fair value of each financial guarantee is based on the difference between the credit spread of the entity responsible for the underlying obligation and a financial counterparty applied, on a net present value basis, to the notional amount of the guarantee.

The carrying amounts for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value due to the short maturity of such instruments. The fair values of other financial instruments, including the Capgemini put option, for which carrying amounts and fair values have not been presented are not materially different than their related carrying amounts.

F-110

24. SEGMENT INFORMATION

Energy Future Holdings Corp.’s operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, retail electricity sales to residential and business customers, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. These activities are conducted principally by subsidiaries of Texas Competitive Holdings. The results of this segment also include the activities of TXU DevCo and its subsidiaries, which are engaged in the development of new lignite/coal-fueled generation facilities, and the activities of a lease trust holding certain combustion turbines.

Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. The segment includes the activities of Oncor Electric Delivery’s wholly owned bankruptcy-remote financing subsidiary.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses, interest on debt at the Energy Future Holdings Corp. level and activities involving mineral interest holdings.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies. Energy Future Holdings Corp. evaluates performance based on income from continuing operations. Energy Future Holdings Corp. accounts for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.

F-111

	Competitive Electric			TXU Electric Delivery			Corp. and Other			Eliminations			Consolidated
Operating Revenues
2006	$	9,549		$	2,449		$	49		$	(1,191	)	$	10,856
2005		9,552			2,394			30			(1,314	)		10,662
2004		8,402			2,226			31			(1,443	)		9,216
Regulated Revenues—Included in Operating Revenues
2006		—			2,449			—			(1,139	)		1,310
2005		—			2,394			—			(1,278	)		1,116
2004		—			2,226			—			(1,420	)		806
Affiliated Revenues—Included in Operating Revenues
2006		8			1,139			44			(1,191	)		—
2005		9			1,278			27			(1,314	)		—
2004		2			1,420			21			(1,443	)		—
Depreciation and Amortization
2006		334			476			20			—			830
2005		313			446			17			—			776
2004		350			389			21			—			760
Equity in Earnings (Losses) of Unconsolidated Subsidiaries
2006		(10	)		(4	)		(19	)		19			(14	)
2005		(7	)		(3	)		(1	)		11			—
2004		(5	)		(2	)		1			7			1
Interest Income
2006		202			58			91			(305	)		46
2005		70			59			99			(180	)		48
2004		31			56			77			(136	)		28
Interest Expense and Related Charges
2006		388			286			461			(305	)		830
2005		393			269			320			(180	)		802
2004		353			280			198			(136	)		695
Income Tax Expense (Benefit)
2006		1,239			170			(146	)		—			1,263
2005		687			174			(229	)		—			632
2004		162			116			(236	)		—			42
Income from Continuing Operations Before Extraordinary Items and Cumulative Effect of Changes in Accounting Principles
2006		2,363			344			(242	)		—			2,465
2005		1,429			351			(5	)		—			1,775
2004		408			255			(582	)		—			81
Investment in Equity Investees
2006		—			—			1			—			1
2005		—			—			—			—			—
Total Assets(a)
2006		18,995			10,709			1,676			(5,458	)		25,922
2005		17,885			9,911			1,717			(3,974	)		25,539
Capital Expenditures
2006		1,330			840			10			—			2,180
2005		309			733			5			—			1,047
2004		281			600			31			—			912

(a) Assets by segment exclude investments in affiliates.

F-112

25. SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations—

		Year Ended December 31,
		2006			2005			2004
Operating revenues
Regulated		$	2,449		$	2,394		$	2,226
Unregulated			9,598			9,582			8,434
Intercompany sales eliminations—regulated			(1,139	)		(1,278	)		(1,420	)
Intercompany sales eliminations—unregulated			(52	)		(36	)		(24	)
Total operating revenues			10,856			10,662			9,216
Costs and operating expenses
Fuel, purchased power and delivery fees—unregulated(a)			2,784			4,261			3,755
Operating costs—regulated			770			758			730
Operating costs—unregulated			603			667			699
Depreciation and amortization—regulated			476			446			389
Depreciation and amortization—unregulated			354			330			371
Selling, general and administrative expenses—regulated			172			198			219
Selling, general and administrative expenses—unregulated			647			583			872
Franchise and revenue-based taxes—regulated			262			247			248
Franchise and revenue-based taxes—unregulated	��		128			117			119
Other income			(121	)		(151	)		(148	)
Other deductions			269			45			1,172
Interest income			(46	)		(48	)		(28	)
Interest expense and other charges			830			802			695
Total costs and expenses			7,128			8,255			9,093
Income from continuing operations before income taxes, extraordinary gain (loss) and cumulative effect of changes in accounting principles		$	3,728		$	2,407		$	123

(a) Includes unregulated cost of fuel consumed of $927 million in 2006, $968 million in 2005 and $971 million in 2004. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

The operations of the Competitive Electric segment are included above as unregulated, as the Texas market is open to competition. However, retail pricing to residential customers in the historical service territory was subject to certain price controls until December 31, 2006.

Interest Expense and Related Charges—

	Year Ended December 31,
	2006			2005			2004
Interest	$	861		$	798		$	637
Distributions on exchangeable preferred membership interests of Texas Competitive Holdings(a)		—			—			22
Interest on long-term debt held by subsidiary trust		—			—			19
Preferred stock dividends of subsidiaries		—			3			2
Amortization of debt discounts, premiums and issuance cost		16			18			27
Capitalized interest including debt portion of allowance for borrowed funds used during construction		(47	)		(17	)		(12	)
Total interest expense and related charges	$	830		$	802		$	695

F-113

(a) In April 2004, Energy Future Holdings Corp. purchased from unaffiliated holders Texas Competitive Holdings’ preferred membership interests.

Restricted Cash—

	Balance Sheet Classification
	At December 31, 2006				At December 31, 2005
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Pollution control revenue bond funds held by trustee (See Note 15)	$	—	$	241	$	—	$	—
Amounts related to securitization (transition) bonds		55		17		46		13
All other		3		—		8		3
Total restricted cash	$	58	$	258	$	54	$	16

Inventories by Major Category—

	December 31,
	2006		2005
Materials and supplies	$	189	$	163
Fuel stock		94		81
Natural gas in storage		75		99
Environmental energy credits and emission allowances		25		21
Total inventories	$	383	$	364

Property, Plant and Equipment—

	December 31,
	2006		2005
Competitive Electric:
Generation	$	15,926	$	15,887
Nuclear fuel (net of accumulated amortization of $1,123 and $1,058)		159		115
Other assets		402		389
Regulated Delivery:
Transmission		3,179		2,829
Distribution		7,788		7,384
Other assets		415		401
Corporate and Other		466		465
Total		28,335		27,470
Less accumulated depreciation		11,319		10,804
Net of accumulated depreciation		17,016		16,666
Construction work in progress:
Competitive Electric (includes $1,070 related to DevCo)		1,607		401
Regulated Delivery		123		106
Corporate and Other		10		19
Total construction work in progress		1,740		526
Property, plant and equipment—net	$	18,756	$	17,192

F-114

Assets related to capitalized leases included above totaled $96 million at December 31, 2006 and $100 million at December 31, 2005, net of accumulated depreciation.

Consolidated depreciation expense as a percent of average depreciable property approximated 2.3% for 2006, 2005 and 2004. Texas Competitive Holdings’ depreciation expense as a percent of average depreciable property approximated 2.0% for 2006, 1.9% for 2005 and 2.0% for 2004. Oncor Electric Delivery’s depreciation expense as a percent of average depreciable property approximated 2.8% for 2006, 2005 and 2004.

Asset Retirement Obligations—These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of Oncor Electric Delivery’s rate setting.

The following table summarizes the changes to the asset retirement liability, reported in other noncurrent liabilities and deferred credits in the consolidated balance sheet, during the year ended December 31, 2006:

Asset retirement liability at December 31, 2005	$	558
Additions:
Accretion		36
Incremental mining reclamation costs		21
Reductions:
Net change in mining land reclamation estimated liability		(4	)
Mining reclamation payments		(26	)
Asset retirement liability at December 31, 2006	$	585

Intangible Assets—Intangible assets other than goodwill are comprised of the following:

	As of December 31, 2006						As of December 31, 2005
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Intangible assets subject to amortization included in property, plant and equipment:
Capitalized software placed in service	$	423	$	339	$	84	$	386	$	314	$	72
Land easements		180		65		115		178		63		115
Mineral rights and other		31		25		6		31		24		7
Total	$	634	$	429	$	205	$	595	$	401	$	194

Aggregate Energy Future Holdings Corp. amortization expense for intangible assets for the years ended December 31, 2006, 2005 and 2004 totaled $38 million, $23 million and $46 million, respectively. At December 31, 2006, the weighted average remaining useful lives of capitalized software, land easements and mineral rights and other assets were 6 years, 69 years and 40 years, respectively. The estimated aggregate amortization expense for each of the five succeeding fiscal years from December 31, 2006 is as follows:

Year
2007	$	29
2008		27
2009		21
2010		11
2011		7

F-115

Goodwill (net of accumulated amortization) as of December 31, 2006 and 2005 totaled $542 million with $517 million at Texas Competitive Holdings and $25 million at Oncor Electric Delivery.

Energy Future Holdings Corp. evaluates goodwill for impairment at least annually (as of October 1) in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). The impairment tests performed are based on discounted cash flow analyses. No goodwill impairment has been recognized for consolidated reporting units reflected in results from continuing operations.

Regulatory Assets and Liabilities—

	December 31,
	2006		2005
Regulatory Assets
Generation-related regulatory assets securitized by transition bonds	$	1,316	$	1,461
Securities reacquisition costs		112		119
Recoverable deferred income taxes—net		90		107
Storm-related service recovery costs		138		110
Employee retirement costs		461		89
Nuclear decommissioning cost under-recovery		—		8
Employee severance costs		44		33
Total regulatory assets		2,161		1,927
Regulatory Liabilities
Investment tax credit and protected excess deferred taxes		63		71
Over-collection of securitization (transition) bond revenues		34		28
Nuclear decommissioning cost over-recovery		17		—
Other regulatory liabilities		19		2
Total regulatory liabilities		133		101
Net regulatory assets	$	2,028	$	1,826

Regulatory assets totaling $121 million have been reviewed and approved by the Commission and are earning a return. The unamortized amounts of these regulatory assets reflected in the above table totaled $100 million and $105 million at December 31, 2006 and 2005, respectively. The assets that have been approved by the Commission and are not earning a return total $1.3 billion at December 31, 2006 and $1.5 billion at December 31, 2005 and have a remaining recovery period of 10 to 44 years, including the regulatory assets securitized by transition bonds that have a remaining recovery period of 10 years.

Severance Liability Related to Strategic Initiatives—

	TXU Energy Holdings			TXU Electric Delivery			Corp. & Other			Total
Liability for severance costs as of January 1, 2005	$	42		$	12		$	1		$	55
Additions to liability		4			—			1			5
Payments charged against liability		(22	)		(8	)		(2	)		(32	)
Other adjustments to the liability		(6	)		—			—			(6	)
Liability for severance costs as of December 31, 2005		18			4			—			22
Additions to liability(a)		8			8			—			16
Payments charged against liability		(24	)		(10	)		—			(34	)
Other adjustments to the liability		(1	)		(1	)		—			(2	)
Liability for severance costs as of December 31, 2006	$	1		$	1		$	—		$	2

F-116

(a) Texas Competitive Holdings and Oncor Electric Delivery additions to liability are both related to services agreements entered into with certain providers. Oncor Electric Delivery amount was recorded with an offset to a regulatory asset.

(b) The table above excludes severance capitalized as a regulatory asset or included in discontinued operations.

Supplemental Cash Flow Information—

	Year Ended December 31,
	2006		2005		2004
Cash payments (receipts) related to continuing operations:
Interest (net of amounts capitalized)	$	823	$	774	$	695
Income taxes	$	220	$	89	$	15
Cash payments (receipts) related to discontinued operations:
Interest (net of amounts capitalized)	$	—	$	—	$	106
Income taxes	$	—	$	30	$	69
Noncash investing and financing activities:
Noncash construction expenditures(a)	$	228	$	61	$	76
Generation plant rail spur capital lease	$	—	$	95	$	—
Consolidation of lease trust:
Increase in assets	$	—	$	35	$	—
Increase in debt	$	—	$	96	$	—

(a) Represents end-of-year accruals.

See Note 5 for the effects of adopting FIN 47 which were noncash in nature.

F-117

Quarterly Information (unaudited)—Results of operations by quarter are summarized below.

In the opinion of Energy Future Holdings Corp., all other adjustments (consisting of normal recurring accruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily indicative of a full year’s operations because of seasonal and other factors.

	Quarter Ended
	March 31			June 30			Sept. 30			Dec. 31
2006:
Operating revenues	$	2,304		$	2,667		$	3,510		$	2,375
Net income from continuing operations available for common stock		516			497			984			469
Income from discontinued operations, net of tax effect		60			—			20			6
Net income available for common stock	$	576		$	497		$	1,004		$	475
Per share of common stock—Basic:
Net income from continuing operations available for common stock	$	1.11		$	1.08		$	2.15		$	1.03
Discontinued operations, net of tax effect		0.13			—			0.04			0.01
Net income available for common stock	$	1.24		$	1.08		$	2.19		$	1.04
Per share of common stock—Diluted:
Net income from continuing operations available for common stock	$	1.09		$	1.07		$	2.11		$	1.02
Discontinued operations, net of tax effect		0.13			—			0.04			0.01
Net income available for common stock	$	1.22		$	1.07		$	2.15		$	1.03
2005:
Operating revenues	$	2,058		$	2,535		$	3,314		$	2,755
Income from continuing operations before extraordinary loss and cumulative effect of change in accounting principle		405			383			571			414
Preference stock dividends		5			4			—			—
Net income available to common stock from continuing operations		400			379			571			414
Income (loss) from discontinued operations, net of tax effect		16			(4	)		(6	)		—
Extraordinary loss, net of tax effect		—			—			—			(50	)
Cumulative effect of change in accounting principle, net of tax effect		—			—			—			(8	)
Net income available for common stock	$	416		$	375		$	565		$	356
Per share of common stock—Basic:
Net income available to common stock from continuing operations	$	0.85		$	0.80		$	1.19		$	0.87
Income (loss) from discontinued operations, net of tax effect		0.03			(0.01	)		(0.01	)		—
Extraordinary loss, net of tax effect		—			—			—			(0.10	)
Cumulative effect of change in accounting principle, net of tax effect		—			—			—			(0.02	)
Net income available for common stock	$	0.88		$	0.79		$	1.18		$	0.75
Per share of common stock—Diluted:
Net income (loss) available to common stock from continuing operations	$	(0.13	)	$	0.71		$	1.17		$	0.86
Income (loss) from discontinued operations, net of tax effect		0.03			(0.01	)		(0.01	)		—
Extraordinary loss, net of tax effect		—			—			—			(0.10	)
Cumulative effect of change in accounting principle, net of tax effect		—			—			—			(0.02	)
Net income (loss) available for common stock	$	(0.10	)	$	0.70		$	1.16		$	0.74

F-118

In the fourth quarter of 2005, Energy Future Holdings Corp. recorded an extraordinary loss of $50 million (net of tax benefit of $28 million) related to the consolidation of a lease trust in December 2005. Energy Future Holdings Corp. also recorded an $8 million (net of tax benefit of $4 million) cumulative effect of a change in accounting principle related to the adoption of FIN 47. The 2005 diluted per share results reflected the unfavorable impact associated with the accelerated share repurchase program, which was settled in May 2005. See Notes 4, 5 and 17.

26. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

On October 10, 2007, Energy Future Holdings Corp., a Texas corporation formerly known as TXU Corp., completed its Merger with Merger Sub, a wholly-owned subsidiary of Texas Energy Future Holdings Limited Partnership (Parent). As a result of the Merger, Energy Future Holdings Corp. became a wholly-owned subsidiary of Parent.

The Merger is being accounted for under the purchase method of accounting whereby the total cost of the transaction is being allocated to Energy Future Holdings Corp.’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values, and the excess of the purchase price over the fair value of net assets acquired is recorded as goodwill.

Energy Future Holdings Corp. expects to refinance $2.0 billion of its Senior Unsecured Bridge Facility obtained to finance the merger with senior unsecured notes (the “Notes”). The Notes will be unconditionally guaranteed by Energy Future Competitive Holdings Company and Energy Future Intermediate Holding Company LLC, 100% owned subsidiaries of Energy Future Holdings Corp. (collectively the “Guarantors”) on an unsecured basis. The guarantees issued by the Guarantors will be full and unconditional, joint and several guarantees of the Notes. The guarantees will rank equally with any unsecured senior indebtedness of the Guarantors and will be effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of Energy Future Holdings Corp., either direct or indirect, will not guarantee the senior unsecured notes (collectively the “Non-Guarantors”). The debt agreements will restrict Energy Future Holdings Corp.’s ability to pay dividends or make investments.

The following tables present the condensed consolidating statements of income and cash flows of Energy Future Holdings Corp. (the “Parent/Issuer”), the Guarantors and the Non-Guarantors for the years ended December 31, 2006, 2005 and 2004 and the condensed consolidating balance sheets as of December 31, 2006 and 2005 of the Parent/Issuer, the Guarantors and the Non-Guarantors.

F-119

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Year ended December 31, 2006

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	12,075		$	(1,219	)	$	10,856
Costs and expenses
Fuel, purchased power costs and delivery fees		—			—			3,929			(1,145	)		2,784
Operating costs		—			—			1,386			(13	)		1,373
Depreciation and amortization		—			—			830			—			830
Selling, general and administrative expenses		70			—			809			(60	)		819
Franchise and revenue-based taxes		1			—			390			(1	)		390
Other income		(15	)		—			(106	)		—			(121	)
Other deductions		7			—			262			—			269
Interest income		(74	)		(206	)		(367	)		601			(46	)
Interest expense and related charges		609			136			703			(618	)		830
Total costs and expenses		598			(70	)		7,836			(1,236	)		7,128
Income (loss) from continuing operations before income taxes and equity in earnings of subsidiaries		(598	)		70			4,239			17			3,728
Income tax expense (benefit)		(214	)		17			1,460			—			1,263
Equity in earnings of subsidiaries		2,936			2,483			920			(6,339	)		—
Income from continuing operations before discontinued operations		2,552			2,536			3,699			(6,322	)		2,465
Income from discontinued operations, net of tax effect		—			—			87			—			87
Net income	$	2,552		$	2,536		$	3,786		$	(6,322	)	$	2,552

F-120

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Year ended December 31, 2005

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	11,987		$	(1,325	)	$	10,662
Costs and expenses
Fuel, purchased power costs and delivery fees		—			—			5,546			(1,285	)		4,261
Operating costs		—			—			1,426			(1	)		1,425
Depreciation and amortization		—			—			776			—			776
Selling, general and administrative expenses		71			—			749			(39	)		781
Franchise and revenue-based taxes		—			—			364			—			364
Other income		(1	)		—			(151	)		1			(151	)
Other deductions		(26	)		—			71			—			45
Interest income		(117	)		(78	)		(220	)		367			(48	)
Interest expense and related charges		412			82			694			(386	)		802
Total costs and expenses		339			4			9,255			(1,343	)		8,255
Income (loss) from continuing operations before income taxes, equity in earnings of subsidiaries, extraordinary loss and cumulative effect of changes in accounting principles		(339	)		(4	)		2,732			18			2,407
Income tax expense (benefit)		(120	)		(2	)		754			—			632
Equity in earnings of subsidiaries		1,931			1,802			563			(4,296	)		—
Income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		1,712			1,800			2,541			(4,278	)		1,775
Income (loss) from discontinued operations, net of tax effect		10			—			(5	)		—			5
Extraordinary loss, net of tax effect		—			(50	)		—			—			(50	)
Cumulative effect of changes in accounting principles, net of tax effect		—			—			(8	)		—			(8	)
Net income		1,722			1,750			2,528			(4,278	)		1,722
Preference stock dividends		10			3			—			(3	)		10
Net income available for common stock	$	1,712		$	1,747		$	2,528		$	(4,275	)	$	1,712

F-121

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Year ended December 31, 2004

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	10,673		$	(1,457	)	$	9,216
Costs and expenses
Fuel, purchased power costs and delivery fees		—			—			5,172			(1,417	)		3,755
Operating costs		—			—			1,436			(7	)		1,429
Depreciation and amortization		—			—			760						760
Selling, general and administrative expenses		191			2			931			(33	)		1,091
Franchise and revenue-based taxes		1			—			366			—			367
Other income		(365	)		—			216			1			(148	)
Other deductions		531			—			642			(1	)		1,172
Interest income		(123	)		(35	)		(148	)		278			(28	)
Interest expense and related charges		274			53			658			(290	)		695
Total costs and expenses		509			20			10,033			(1,469	)		9,093
Income (loss) from continuing operations before income taxes, equity in earnings of subsidiaries, extraordinary gain and cumulative effect of changes in accounting principles		(509	)		(20	)		640			12			123
Income tax expense (benefit)		(49	)		(7	)		98			—			42
Equity in earnings of subsidiaries		1,053			674			146			(1,873	)		—
Income from continuing operations before extraordinary gain and cumulative effect of changes in accounting principles		593			661			688			(1,861	)		81
Income (loss) from discontinued operations, net of tax effect		(112	)		—			490			—			378
Extraordinary gain, net of tax effect		—			—			16			—			16
Cumulative effect of changes in accounting principles, net of tax effect		4			—			6			—			10
Net income		485			661			1,200			(1,861	)		485
Exchangeable preferred membership interest buyback premium		849			—			—			—			849
Preference stock dividends		22			2			—			(2	)		22
Net income (loss) available for common stock	$	(386	)	$	659		$	1,200		$	(1,859	)	$	(386	)

F-122

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2006

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net income	$	2,552		$	2,536		$	3,786		$	(6,322	)	$	2,552
Income from discontinued operations, net of tax		—			—			(87	)		—			(87	)
Income from continuing operations		2,552			2,536			3,699			(6,322	)		2,465
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Equity in earnings of subsidiaries		(2,936	)		(2,483	)		(920	)		6,339			—
Depreciation and amortization		—			—			893			—			893
Deferred income tax expense (benefit)—net		116			(9	)		649			—			756
Impairment and other asset writedown charges		—			—			204			—			204
Net gains from unrealized mark-to-market valuations		—			—			(272	)		—			(272	)
Other, net		6			—			162			—			168
Net change in operating assets and liabilities:		482			1,188			1,456			(2,386	)		740
Cash provided by operating activities		220			1,232			5,871			(2,369	)		4,954
Cash flows—financing activities:
Issuances of securities:
Long-term debt		—			—			243			—			243
Common stock		180			—			—			—			180

F-123

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows—Continued

Year Ended December 31, 2006

	Millions of Dollars
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Retirements/repurchases of securities:
Long-term debt		(911	)		(6	)		(774	)		—			(1,691	)
Common stock		(960	)		—			—			—			(960	)
Change in short term borrowings		—			—			694			—			694
Cash dividends paid		(764	)		(858	)		(1,484	)		2,342			(764	)
Change in advances—affiliates		1,724			—			981			(2,705	)		—
Other, net		(12	)		—			(22	)		—			(34	)
Cash used in financing activities		(743	)		(864	)		(362	)		(363	)		(2,332	)
Cash flows—investing activities:
Capital expenditures and nuclear fuel		(12	)		—			(2,285	)		—			(2,297	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			207			—			207
Investments in nuclear decommissioning trust fund securities		—			—			(223	)		—			(223	)
Change in advances—affiliates		—			(299	)		(2,433	)		2,732			—
Investments in collateral trust		533			—			(533	)		—			—
Other, net		2			(69	)		(284	)		—			(351	)
Cash provided by (used in) investing activities		523			(368	)		(5,551	)		2,732			(2,664	)
Cash flows—discontinued operations:
Operating activities		—			—			30			—			30
Financing activities		—			—			—			—			—
Investing activities		—			—			—			—			—
Cash provided by discontinued operations		—			—			30			—			30
Net change in cash and cash equivalents		—			—			(12	)		—			(12	)
Cash and cash equivalents—beginning balance		—			—			37			—			37
Cash and cash equivalents—ending balance	$	—		$	—		$	25		$	—		$	25

F-124

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Year Ended December 31, 2005

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net income	$	1,722		$	1,750		$	2,528		$	(4,278	)	$	1,722
Loss (income) from discontinued operations, net of tax		(10	)		—			5			—			(5	)
Extraordinary loss, net of tax		—			50			—			—			50
Cumulative effect of changes in accounting principles, net of tax		—			—			8			—			8
Income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		1,712			1,800			2,541			(4,278	)		1,775
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Equity in earnings of subsidiaries		(1,931	)		(1,802	)		(563	)		4,296			—
Depreciation and amortization		—			—			836			—			836
Deferred income tax expense (benefit) —net		17			1			463			—			481
Impairment and other asset writedown charges		—			—			11			—			11
Net losses from unrealized mark-to-market valuations		—			—			18			—			18
Other, net		12			—			(69	)		(19	)		(76	)
Changes in operating assets and liabilities:		322			689			(26	)		(1,237	)		(252	)
Cash provided by operating activities		132			688			3,211			(1,238	)		2,793
Cash flows—financing activities:
Issuances of securities:
Long-term debt		—			—			180			—			180
Common stock		84			—			(1	)		—			83

F-125

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows—Continued

Year Ended December 31, 2005

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Retirements/repurchases of securities:
Long-term debt		(106	)		(5	)		(264	)		—			(375	)
Preference stock		(300	)		(38	)		—			—			(338	)
Common stock		(1,137	)		—			—			38			(1,099	)
Change in short term borrowings		—			—			588			—			588
Cash dividends paid		(555	)		(528	)		(697	)		1,225			(555	)
Change in advances—affiliates		1,883			—			(1,441	)		(442	)		—
Other, net		(26	)		—			(21	)		—			(47	)
Cash used in financing activities		(157	)		(571	)		(1,656	)		821			(1,563	)
Cash flows—investing activities:
Capital expenditures and nuclear fuel		—			—			(1,104	)		—			(1,104	)
Dispositions of businesses		—			—			77			—			77
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			191			—			191
Investments in nuclear decommissioning trust fund securities		—			—			(206	)		—			(206	)
Change in advances—affiliates		—			(117	)		(300	)		417			—
Other, net		16			—			(12	)		—			4
Cash provided by (used in) in investing activities		16			(117	)		(1,354	)		417			(1,038	)
Cash flows—discontinued operations:
Operating activities		(3	)		—			(262	)		—			(265	)
Financing activities		—			—			—			—			—
Investing activities		—			—			4			—			4
Cash used in discontinued operations		(3	)		—			(258	)		—			(261	)
Net change in cash and cash equivalents		(12	)		—			(57	)		—			(69	)
Cash and cash equivalents—beginning balance		12			—			94			—			106
Cash and cash equivalents—ending balance	$	—		$	—		$	37		$	—		$	37

F-126

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Year Ended December 31, 2004

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net income	$	485		$	661		$	1,200		$	(1,861	)	$	485
Loss (income) from discontinued operations, net of tax		112			—			(490	)		—			(378	)
Extraordinary gain, net of tax		—			—			(16	)		—			(16	)
Cumulative effect of changes in accounting principles, net of tax		(4	)		—			(6	)		—			(10	)
Income from continuing operations before extraordinary gain and cumulative effect of changes in accounting principles		(593	)		(661	)		688			(1,861	)		81
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Equity in earnings of subsidiaries		(1,053	)		(674	)		(146	)		1,873			—
Depreciation and amortization		—			—			826			—			826
Loss on early extinguishment of debt		415			—			1			—			416
Deferred income tax expense (benefit)—net		124			(1	)		(134	)		—			(11	)
Impairment and other asset writedown charges		—			—			196			—			196
Net losses from unrealized mark-to-market valuations		—			—			109			—			109
Other, net		92			—			135			(12	)		215
Changes in operating assets and liabilities		1,528			505			(263	)		(1,844	)		(74	)

F-127

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows—Continued

Year Ended December 31, 2004

	Millions of Dollars
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash provided by operating activities		1,699			491			1,412			(1,844	)		1,758
Cash flows—financing activities:
Issuances of securities:
Long-term debt		3,500			—			1,590			—			5,090
Common stock		112			—			—			—			112
Retirements/repurchases of securities:														—
Long-term debt		(3,132	)		(5	)		(2,352	)		—			(5,489	)
Preference stock		—			—			(75	)		—			(75	)
Common stock		(4,687	)		—			(450	)		450			(4,687	)
Change in short term borrowings		—			—			210			—			210
Cash dividends paid		(172	)		(775	)		(700	)		1,475			(172	)
Change in advances—affiliates		2,252			(535	)		(2,715	)		998			—
Premium paid for redemption of exchangeable preferred membership interests		(1,102	)		—			—			—			(1,102	)
Other, net		(346	)		(2	)		(58	)		—			(406	)
Cash used in financing activities		(3,575	)		(1,317	)		(4,550	)		2,923			(6,519	)
Cash flows—investing activities:
Capital expenditures and nuclear fuel		(19	)		—			(980	)		—			(999	)
Dispositions of businesses		1,886			—			2,928			—			4,814
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			88			—			88
Investments in nuclear decommissioning trust fund securities		—			—			(103	)		—			(103	)
Change in advances—affiliates		—			(168	)		797			(629	)		—
Other, net		24			450			456			(450	)		480
Cash provided by (used in) in investing activities		1,891			282			3,186			(1,079	)		4,280
Cash flows—discontinued operations:
Operating activities		(3	)		—			(76	)		—			(79	)
Financing activities		—			—			(10	)		—			(10	)
Investing activities		—			—			(153	)		—			(153	)
Cash used in discontinued operations		(3	)		—			(239	)		—			(242	)
Net change in cash and cash equivalents		12			(544	)		(191	)		—			(723	)
Cash and cash equivalents — beginning balance		—			544			285			—			829
Cash and cash equivalents — ending balance	$	12		$	—		$	94		$	—		$	106

F-128

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets at December 31, 2006

	Millions of Dollars
	Parent/ Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—	$	25	$	—		$	25
Restricted cash		—		—		58		—			58
Advances to parent		—		584		1,821		(2,405	)		—
Trade accounts receivable—net		5		1		1,165		(212	)		959
Income taxes receivable		165		—		—		(165	)		—
Accounts receivable from affiliates		—		146		—		(146	)		—
Notes receivable from affiliates		—		—		1,533		(1,533	)		—
Inventories		—		—		383		—			383
Commodity and other derivative contractual assets		2		—		972		—			974
Accumulated deferred income taxes		—		5		253		(5	)		253
Margin deposits related to commodity positions		—		—		7		—			7
Other current assets		8		—		177		(7	)		178
Total current assets		180		736		6,394		(4,473	)		2,837
Restricted cash		—		—		258		—			258
Investments		12,457		6,902		1,682		(20,329	)		712
Property, plant and equipment—net		33		—		18,723		—			18,756
Notes receivable from affiliates		12		700		3,073		(3,785	)		—
Goodwill		—		—		542		—			542
Regulatory assets—net		—		—		2,028		—			2,028
Commodity and other derivative contractual assets		11		—		399		—			410
Accumulated deferred income taxes		118		391		—		(509	)		—
Other noncurrent assets		150		—		244		(15	)		379
Total assets	$	12,961	$	8,729	$	33,343	$	(29,111	)	$	25,922
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	—	$	—	$	1,491	$	—		$	1,491
Advances from affiliates		2,402		—		—		(2,402	)		—
Long-term debt due currently		—		17		468		—			485
Trade accounts payable—nonaffiliates		18		—		1,286		(211	)		1,093
Accounts payable to affiliates		102		—		47		(149	)		—
Notes payable to affiliates		1,500		—		33		(1,533	)		—
Commodity and other derivative contractual liabilities		21		—		296		—			317
Margin deposits related to commodity positions		—		—		681		—			681
Accumulated deferred income taxes		5		—		—		(5	)		—
Other current liabilities		236		21		955		(172	)		1,040
Total current liabilities		4,284		38		5,257		(4,472	)		5,107
Accumulated deferred income taxes		—		—		4,747		(509	)		4,238
Investment tax credits		—		—		363		—			363
Commodity and other derivative contractual liabilities		63		—		193		—			256
Notes or other liabilities due affiliates		2,714		700		371		(3,785	)		—
Long-term debt, less amounts due currently		3,643		124		6,864		—			10,631
Other noncurrent liabilities and deferred credits		117		—		3,086		(16	)		3,187
Total liabilities		10,821		862		20,881		(8,782	)		23,782
Shareholders’ equity		2,140		7,867		12,462		(20,329	)		2,140
Total liabilities and shareholders’ equity	$	12,961	$	8,729	$	33,343	$	(29,111	)	$	25,922

F-129

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets at December 31, 2005

	Millions of Dollars
	Parent/ Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents . .	$	—	$	—	$	37	$	—		$	37
Restricted cash . .		—		—		54		—			54
Advances to parent. . . . . . . . . . . .		—		300		1,131		(1,431	)		—
Trade accounts receivable—net . . . . .		8		1		1,520		(201	)		1,328
Income taxes receivable. . . . . . . . . . . . . . . .		—		—		49		(35	)		14
Accounts receivable from affiliates		—		138		398		(536	)		—
Notes receivable from affiliates . . . . . . . .		—		—		1,905		(1,905	)		—
Inventories . . .		—		—		364		—			364
Commodity contract assets . . . .		—		—		1,603		—			1,603
Cash flow hedge and other derivative assets		1		—		63		1			65
Accumulated deferred income taxes . . . . .		—		6		725		(14	)		717
Margin deposits related to commodity positions		—		—		247		—			247
Other current assets . . .		5		—		130		(6	)		129
Total current assets		14		445		8,226		(4,127	)		4,558
Restricted cash . .		3		—		13		—			16
Investments		10,644		5,014		1,002		(16,017	)		643
Property, plant and equipment—net . . . . . .		—		35		17,157					17,192
Notes receivable from affiliates		11		44		1,973		(2,028	)		—
Goodwill . . . . . .		—		—		542		—			542
Regulatory assets—net . . . . .		—		—		1,826		—			1,826
Commodity contract assets . . . .		—		—		338		—			338
Cash flow hedge and other derivative assets .		7		—		68		—			75
Accumulated deferred income taxes . . . . . . .		147		428		—		(575	)		—
Other noncurrent assets . . . . .		145		—		252		(48	)		349
Total assets	$	10,971	$	5,966	$	31,397	$	(22,795	)	$	25,539
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	—	$	—	$	798	$	—		$	798
Advances from affiliates		1,431		—		—		(1,431	)		—
Long-term debt due currently . .		732		13		505		—			1,250
Trade accounts payable—nonaffiliates . . .		5		—		1,222		(201	)		1,026
Accounts payable to affiliates .		537		—		—		(537	)		—
Notes payable to affiliates . . . . . . . . . . . . .		1,873		—		32		(1,905	)		—
Commodity contract liabilities . . . . . . .		—		—		1,481		—			1,481
Cash flow hedge and other derivative liabilities		15		—		260		—			275
Margin deposits related to commodity positions		—		—		357		—			357
Accumulated deferred income taxes .		14		—		—		(14	)		—
Other current liabilities . . . . . . .		265		83		854		(39	)		1,163
Total current liabilities .		4,872		96		5,509		(4,127	)		6,350
Accumulated deferred income taxes . . . . . .		—		—		4,272		(575	)		3,697
Investment tax credits. . . . . . . .		—		—		384		—			384
Commodity contract liabilities . . . . . . .		—		—		516		—			516
Cash flow hedge and other derivative liabilities		47		—		44		—			91
Regulatory liabilities . . . . . . . . . . . . . . . . . . . .		—		—		—		—			—
Notes or other liabilities due affiliates		1,611		—		417		(2,028	)		—
Long-term debt, less amounts due currently . . .		3,842		230		7,260		—			11,332
Other noncurrent liabilities and deferred credits		124		—		2,594		(24	)		2,694
Total liabilities .		10,496		326		20,996		(6,754	)		25,064
Preferred securities of subsidiaries		—		—		528		(528	)		—
Shareholders’ equity . . . .		475		5,640		9,873		(15,513	)		475
Total liabilities and shareholders’ equity	$	10,971	$	5,966	$	31,397	$	(22,795	)	$	25,539

F-130

27. MERGER RELATED TRANSACTIONS (UNAUDITED)

Overview

On October 10, 2007, Energy Future Holdings Corp., a Texas corporation formerly known as TXU Corp., completed its Merger with Merger Sub, a wholly-owned subsidiary of Texas Energy Future Holdings Limited Partnership (Parent). As a result of the Merger, Energy Future Holdings Corp. became a wholly-owned subsidiary of Parent. Parent is controlled by investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners (collectively, the Sponsor Group).

The aggregate purchase price paid for all of the equity securities of TXU Corp. (on a fully-diluted basis) was approximately $32.4 billion, which purchase price was funded by the equity financing from the Sponsor Group and certain other investors and by the new credit facilities described below. These new credit facilities also funded the repayment of existing credit facilities as discussed below. The purchase amount is exclusive of costs directly associated with the Merger, including legal, consulting and other professional service fees and certain effects of the regulatory settlement discussed below.

The Merger is being accounted for under the purchase method of accounting whereby the total cost of the transaction is being allocated to Energy Future Holdings Corp.’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values, and the excess of the purchase price over the fair value of net assets acquired is recorded as goodwill. The allocation of the purchase price to the net assets of Energy Future Holdings Corp. and the resulting goodwill determination are not yet final. The allocation is expected to result in a significant amount of goodwill, an increase in the carrying value of property, plant and equipment and deferred income tax liabilities as well as new identifiable intangible assets and liabilities. Reported earnings in the future will reflect increases in interest, depreciation and amortization expenses.

TCEH Senior Secured Facilities

Overview—In connection with the Merger, TCEH, as borrower, and US Holdings, have entered into a credit agreement, and related security and other agreements, with a group of lenders led by Citibank, N.A. that provides senior secured financing of up to $24.5 billion plus the amount of the TCEH Commodity Collateral Posting Facility (as defined below) (the TCEH Senior Secured Facilities), consisting of:

• a senior secured initial term loan facility (the TCEH Initial Term Loan Facility) in an aggregate principal amount of up to $16.45 billion;

• a senior secured delayed draw term loan facility in an aggregate principal amount of up to $4.1 billion (the TCEH Delayed Draw Term Loan Facility), of which $2.15 billion was drawn at the closing of the Merger;

• a senior secured letter of credit facility in an aggregate principal amount of up to $1.25 billion (the TCEH Letter of Credit Facility);

• a senior secured revolving credit facility in an aggregate principal amount of up to $2.7 billion (the TCEH Revolving Facility), which includes borrowing capacity available for letters of credit and for borrowings on same-day notice; and

• a senior secured cash posting credit facility (the TCEH Commodity Collateral Posting Facility) that is expected to fund the cash posting requirements for a significant portion of TCEH’s long-term hedging program that is not otherwise secured by means of a first lien under the security arrangements described below. The amount drawn on this Facility on October 10, 2007 was $378 million as of October 10, 2007.

Interest Rates and Fees—Loans under the TCEH Senior Secured Facilities (other than the TCEH Commodity Collateral Posting Facility) bear interest at per annum rates equal to, at TCEH’s option, (i) adjusted

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LIBOR plus 3.50% or (ii) a base rate (the higher of (1) the prime rate of Citibank, N.A. and (2) the federal funds effective rate plus 0.50%) plus 2.50%. There is a margin adjustment mechanism in relation to term loans, revolving loans and letters of credit commencing after delivery of the financial statements for the first full fiscal quarter ending after October 10, 2007, under which the applicable margins may be reduced based on leverage ratio targets to be determined.

A commitment fee is payable quarterly in arrears and upon termination at a rate per annum equal to 0.50% of the average daily unused portion of the TCEH Revolving Facility. The commitment fee will be subject to reduction, commencing after delivery of the financial statements for the first full fiscal quarter ending after October 10, 2007, based on leverage ratio targets to be determined.

A commitment fee is payable quarterly in arrears and upon termination on the undrawn portion of the commitments in respect of the TCEH Delayed Draw Term Loan Facility at a rate per annum equal to, prior to the first anniversary of October 10, 2007, 1.25% per annum, and thereafter, 1.50% per annum.

Letter of credit fees under the TCEH Revolving Facility are payable quarterly in arrears and upon termination at a rate per annum equal to the spread over adjusted LIBOR under the TCEH Revolving Facility, less the issuing bank’s fronting fee.

TCEH will pay a fixed quarterly maintenance fee through maturity for having procured the TCEH Commodity Collateral Posting Facility regardless of actual borrowings under the facility. In addition, TCEH will pay interest at LIBOR on actual borrowed amounts under the TCEH Commodity Collateral Posting Facility which will be offset by interest earned on collateral deposits to counterparties, thereby making this facility largely a fixed cost facility regardless of utilization.

Guarantees and Security—Guarantee. The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis, by US Holdings, TCEH and each existing and subsequently acquired or organized direct or indirect wholly-owned U.S. restricted subsidiary of TCEH (other than certain immaterial subsidiaries and other subsidiaries to be agreed upon), subject to certain other exceptions.

Security—The TCEH Senior Secured Facilities, including the guarantees thereof and certain commodity and other hedging and trading transactions, are secured by (a) substantially all of the assets of US Holdings, TCEH and TCEH’s subsidiaries who are guarantors of such facilities as described above, and (b) pledges of the capital stock of TCEH and each material wholly-owned restricted subsidiary of TCEH directly owned by TCEH or any guarantor (limited in the case of pledges of capital stock of any foreign subsidiaries, to 65% of the capital stock of any first-tier material foreign subsidiary).

Covenants—The TCEH Senior Secured Facilities contain customary negative covenants, restricting, subject to certain exceptions, US Holdings, TCEH and TCEH’s restricted subsidiaries from, among other things:

• incurring additional debt;

• incurring additional liens;

• entering into mergers and consolidations;

• sales of assets;

• dividends, redemptions or other distributions in respect of capital stock;

• acquisitions, investments, loans and advances; and

• payments and modifications of certain subordinated and other material debt.

In addition, the TCEH Senior Secured Facilities require that US Holdings, TCEH and their restricted subsidiaries maintain a maximum secured leverage ratio beginning on September 30, 2008 of 7.25 to 1.00 and observe certain customary reporting requirements and other affirmative covenants.

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Maturity and Amortization—The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments beginning December 31, 2007 in an aggregate annual amount equal to 1% of the original principal amount of such facility, with the balance payable on October 10, 2014. The TCEH Delayed Draw Term Facility is required to be repaid in equal quarterly installments beginning on the last day of the first fiscal quarter to occur after October 10, 2009 in an aggregate annual amount equal to 1% of the actual principal outstanding under the TCEH Delayed Draw Term Loan Facility as of such date, with the balance payable on October 10, 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time from and after the closing date until October 10, 2013. The TCEH Letter of Credit Facility will mature on October 10, 2014. The TCEH Commodity Collateral Posting Facility will mature on December 31, 2012.

Events of Default —The TCEH Senior Secured Facilities contain certain customary events of default for senior leveraged acquisition financings the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments.

Senior Unsecured Bridge Facility – TCEH

Overview—On October 10, 2007, US Holdings, TCEH and TCEH Finance, Inc, a Delaware corporation and wholly-owned subsidiary of TCEH (TCEH Finance and, together with TCEH, the Co-Borrowers), entered into senior unsecured credit facilities (TCEH Unsecured Bridge Facilities).

The TCEH Unsecured Bridge Facilities provide senior unsecured financing of $6.75 billion, consisting of a:

• $5.0 billion senior unsecured cash-pay term loan facility with a term of eight years (the TCEH Initial Cash-Pay Loans); and

• $1.75 billion senior unsecured toggle term loan facility with a term of nine years (the TCEH Initial Toggle Loans and, together with the TCEH Initial Cash-Pay Loans, the TCEH Initial Loans).

If any borrowings under the TCEH Unsecured Bridge Facilities remain outstanding on October 10, 2008, the lenders will have the option to exchange such TCEH Initial Loans for senior cash-pay notes (the TCEH Senior Cash-Pay Exchange Notes) or senior toggle notes (the TCEH Senior Toggle Exchange Notes and, together with the TCEH Senior Cash-Pay Exchange Notes, the TCEH Senior Exchange Notes), respectively, which the Co-Borrowers will issue under a senior indenture. The maturity date of any TCEH Initial Loans that are not exchanged for TCEH Senior Exchange Notes will automatically be extended to the October 10, 2015, in the case of the TCEH Initial Cash-Pay Loans and October 10, 2016 in the case of the TCEH Initial Toggle Loans. The TCEH Senior Cash-Pay Exchange Notes will mature on October 10, 2015, and the TCEH Senior Toggle Exchange Notes will mature on October 10, 2016. Holders of the TCEH Senior Exchange Notes will have registration rights.

Interest Rate—Subject to specified caps, borrowings under the TCEH Unsecured Bridge Facilities for the first six-month period from the closing of the TCEH Unsecured Bridge Facilities will bear interest at a rate equal to LIBOR plus (i) 325 basis points, in the case of the TCEH Initial Cash-Pay Loans and (ii) 350 basis points, in the case of the TCEH Initial Toggle Loans (in each case, the TCEH Initial Margin). Interest for the three-month period commencing at the end of the initial six-month period, subject to specified caps, shall be payable at prevailing LIBOR for the interest period plus the TCEH Initial Margin plus 50 basis points. Thereafter, subject to specified caps, interest will be increased by an additional 25 basis points at the beginning of each three-month period subsequent to the initial nine-month period, for so long as the TCEH Initial Loans are outstanding. If issued, the interest rate on the TCEH Senior Exchange Notes will be the same as the interest rate borne by the TCEH Initial Loans; provided, that if any TCEH Senior Exchange Notes are transferred by the lender to a third-party purchaser, the interest rate on those notes will be fixed at the interest rate in effect on the transfer date.

Prepayments and Redemptions—The Co-Borrowers will be required to make an offer to repay loans under the TCEH Unsecured Bridge Facilities and, following October 10, 2008, repurchase TCEH Senior Exchange

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Notes with net proceeds from specified asset sales. In addition, after any payments required to be made to repay the TCEH Unsecured Bridge Facilities, the Co-Borrowers will be required to offer to repay loans and, if issued, to repurchase the TCEH Senior Exchange Notes upon the occurrence of a change of control. Prior to October 10, 2008, the Co-Borrowers will also be required to prepay outstanding TCEH Initial Loans with the net proceeds of any refinancing debt.

The Co-Borrowers may voluntarily repay outstanding TCEH Initial Loans, in whole or in part, at their option at any time upon three business days’ prior notice, at par plus accrued and unpaid interest and subject to, in the case of TCEH Initial Loans based on LIBOR, customary “breakage” costs with respect to such LIBOR loans, other than customary “breakage” costs with respect to LIBOR loans. The Co-Borrowers may optionally redeem the TCEH Senior Exchange Notes other than fixed-rate exchange notes, if issued, in whole or in part, at any time at par plus accrued and unpaid interest to the redemption date, provided that it also optionally prepays any outstanding TCEH Initial Loans on a pro rata basis.

If any TCEH Senior Exchange Note is sold by a lender to a third-party purchaser, and the interest rate on such TCEH Senior Exchange Note becomes fixed, such TCEH Senior Exchange Note will be non-callable until October 10, 2011, in the case of the TCEH Senior Cash-Pay Exchange Notes, and until October 10, 2012, in the case of the TCEH Senior Toggle Exchange Notes, subject to equity clawback and make-whole provisions consistent with those applicable to the notes offered hereby, and will be callable thereafter at a specified premium. The premium will decline ratably on each yearly anniversary of the date of such sale to zero two years prior to the final maturity date, in the case of the TCEH Senior Cash-Pay Exchange Notes, and one year, in the case of the TCEH Senior Toggle Exchange Notes.

Guarantee—All obligations under the TCEH Unsecured Bridge Facilities and, if the TCEH Senior Exchange Notes are issued, the senior indenture, are jointly and severally guaranteed on a senior basis by US Holdings and each of TCEH’s domestic subsidiaries that guarantees obligations under the TCEH Senior Secured Facilities.

Certain Covenants and Events of Default—The TCEH Unsecured Bridge Facilities and the senior indenture contain a number of covenants that, among other things, restrict, subject to certain exceptions, the Co-Borrowers’ ability to:

• incur additional indebtedness;

• create liens;

• engage in mergers or consolidations;

• sell or transfer assets and subsidiary stock;

• pay dividends and distributions or repurchase their capital stock;

• make certain investments, loans or advances;

• prepay certain indebtedness;

• enter into agreements that restrict the payment of dividends by subsidiaries or the repayment of intercompany loans and advances; and

• engage in certain transactions with affiliates.

In addition, the TCEH Unsecured Bridge Facilities and the senior indenture impose certain requirements as to future subsidiary guarantors. The TCEH Unsecured Bridge Facilities and the senior indenture also contain certain customary affirmative covenants consistent with those in the TCEH Senior Secured Facilities, to the extent applicable, and certain customary events of default.

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Senior Unsecured Bridge Facility – Energy Future Holdings Corp.

Overview—On October 10, 2007, in connection with the Merger and the repayment of certain existing indebtedness, Energy Future Holdings Corp. entered into senior unsecured credit facilities (Energy Future Holdings Corp. Unsecured Bridge Facilities).

Energy Future Holdings Corp.’s Unsecured Bridge Facilities provide senior unsecured financing of $4.5 billion, consisting of a:

• $2.0 billion senior unsecured cash-pay term loan facility with a term of ten years (Energy Future Holdings Corp. Initial Cash-Pay Loans); and

• $2.5 billion senior unsecured toggle term loan facility with a term of ten years (Energy Future Holdings Corp. Initial Toggle Loans and, together with Energy Future Holdings Corp. Initial Cash-Pay Loans, Energy Future Holdings Corp. Initial Loans).

If any borrowings under Energy Future Holdings Corp. Unsecured Bridge Facilities remain outstanding on October 10, 2008, the lenders will have the option at any time or from time to time to exchange such Energy Future Holdings Corp. Initial Loans for senior cash-pay notes (Energy Future Holdings Corp. Senior Cash-Pay Exchange Notes) or senior toggle notes (Energy Future Holdings Corp. Senior Toggle Exchange Notes and, together with Energy Future Holdings Corp. Senior Cash-Pay Exchange Notes, Energy Future Holdings Corp. Senior Exchange Notes) that Energy Future Holdings Corp. will issue under a senior indenture. The maturity date of any Energy Future Holdings Corp. Initial Loans that are not exchanged for Energy Future Holdings Corp. Senior Exchange Notes will automatically be extended to October 10, 2017. Energy Future Holdings Corp. Senior Exchange Notes will also mature on October 10, 2017. Holders of Energy Future Holdings Corp. Senior Exchange Notes will have registration rights.

Interest Rate—Subject to specified caps, borrowings under Energy Future Holdings Corp. Unsecured Bridge Facilities for the first six-month period from the closing of the TCEH Senior Secured Facilities will bear interest at a rate equal to LIBOR plus (i) 400 basis points, in the case of Energy Future Holdings Corp. Initial Cash-Pay Loans and (ii) 425 basis points, in the case of Energy Future Holdings Corp. Initial Toggle Loans (in each case, Energy Future Holdings Corp. Initial Margin). Interest for the three-month period commencing at the end of the initial six-month period, subject to specified caps, shall be payable at prevailing LIBOR for the interest period plus (A) Energy Future Holdings Corp. Initial Margin plus (B) 50 basis points. Thereafter, subject to specified caps, interest will be increased by an additional 25 basis points at the beginning of each three-month period subsequent to the initial nine-month period, for so long as Energy Future Holdings Corp. Initial Loans are outstanding. If issued, the interest rate on Energy Future Holdings Corp. Senior Exchange Notes will be the same as the interest rate borne by Energy Future Holdings Corp. Initial Loans; provided, that if any Energy Future Holdings Corp. Senior Exchange Notes are transferred by the lender to a third-party purchaser, the interest rate on those notes will be fixed at the interest rate in effect on the transfer date.

Prepayments and Redemptions—Energy Future Holdings Corp. will be required to make an offer to repay loans under Energy Future Holdings Corp. Unsecured Bridge Facilities and, following October 10, 2008, repurchase Energy Future Holdings Corp. Senior Exchange Notes with net proceeds from specified asset sales. In addition, after any payments required to be made to repay the TCEH Senior Secured Facilities, Energy Future Holdings Corp. will be required to offer to repay loans and, if issued, to repurchase Energy Future Holdings Corp. Senior Exchange Notes upon the occurrence of a change of control. Prior to October 10, 2008, Energy Future Holdings Corp. will also be required to prepay outstanding Energy Future Holdings Corp. Initial Loans with the net proceeds of any refinancing debt.

Energy Future Holdings Corp. may voluntarily repay outstanding Energy Future Holdings Corp. Initial Loans, in whole or in part, at its option at any time upon three business days’ prior notice, at par plus accrued and unpaid interest and subject to, in the case of Energy Future Holdings Corp. Initial Loans based on LIBOR,

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customary “breakage” costs with respect to such LIBOR loans, other than customary “breakage” costs with respect to LIBOR loans. Energy Future Holdings Corp. may optionally redeem Energy Future Holdings Corp. Senior Exchange Notes other than fixed-rate exchange notes, if issued, in whole or in part, at any time at par plus accrued and unpaid interest to the redemption date, provided that it also optionally prepays any outstanding Energy Future Holdings Corp. Initial Loans on a pro rata basis.

If any Energy Future Holdings Corp. Senior Exchange Note is sold by a lender to a third-party purchaser, and the interest rate on such Energy Future Holdings Corp. Senior Exchange Note becomes fixed, such Energy Future Holdings Corp. Senior Exchange Note will be non-callable for the first four years from October 10, 2008, subject to equity clawback and make-whole provisions consistent with those applicable to the notes offered hereby, and will be callable thereafter at a specified premium. The premium will decline ratably on each yearly anniversary of the date of such sale to zero on October 10, 2015.

Guarantee—All obligations under Energy Future Holdings Corp. Unsecured Bridge Facilities and, if Energy Future Holdings Corp. Senior Exchange Notes are issued, the senior indenture are jointly and severally guaranteed on a senior unsecured basis by Intermediate Holding and US Holdings.

Certain Covenants and Events of Default—Energy Future Holdings Corp. Unsecured Bridge Facilities and the senior indenture contain a number of covenants that, among other things, restrict, subject to certain exceptions, Energy Future Holdings Corp.’s ability to:

• incur additional indebtedness;

• create liens;

• engage in mergers or consolidations;

• sell or transfer assets and subsidiary stock;

• pay dividends and distributions or repurchase its capital stock;

• make certain investments, loans or advances;

• prepay certain indebtedness;

• enter into agreements that restrict the payment of dividends by subsidiaries or the repayment of intercompany loans and advances; and

• engage in certain transactions with affiliates.

In addition, Energy Future Holdings Corp. Unsecured Bridge Facilities and the senior indenture impose certain requirements as to future subsidiary guarantors. Energy Future Holdings Corp. Unsecured Bridge Facilities and the senior indenture also contain certain customary affirmative covenants consistent with those in TCEH Senior Secured Facilities, to the extent applicable.

Intercreditor Agreement

On October 10, 2007, in connection with the Merger, TCEH, US Holdings and the subsidiary guarantors under the TCEH Senior Secured Facilities entered into a Collateral Agency and Intercreditor Agreement (the Intercreditor Agreement) with Citibank, N.A., and four secured commodity hedge counterparties (Secured Commodity Hedge Counterparties).

The Intercreditor Agreement provides that the lien granted to the Secured Commodity Hedge Counterparties should rank pari passu with the lien granted to the secured parties under the TCEH Senior Secured Facilities on

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the collateral under the TCEH Senior Secured Facilities and the Secured Commodity Hedge Counterparties will be entitled to share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral in an amount provided in the TCEH Credit Agreement. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will have voting rights with respect to any amendment or waiver of any provision of the Intercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties’ lien on such collateral relative to the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to the Secured Commodity Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the lien granted to the secured parties under the TCEH Senior Secured Facilities.

Revolving Credit Facility – Oncor

Overview—Oncor has entered into a revolving credit agreement (the Oncor Credit Agreement) to provide for a secured revolving credit facility in an aggregate principal amount of up to $2.0 billion (the Oncor Revolving Credit Facility).

Interest Rates and Fees—Loans under the Oncor Revolving Credit Facility bear interest at per annum rates equal to, at Oncor’s option, (i) adjusted LIBOR plus a spread of 0.275% to 0.800% (which spread shall depend on the rating assigned to Oncor’s senior secured debt) or (ii) a base rate (the higher of (1) the prime rate of JPMorgan Chase Bank, N.A. and (2) the federal funds effective rate plus 0.50%). Based on Oncor’s current ratings, its LIBOR-based borrowings will bear interest at LIBOR plus 0.575%.

A facility fee is payable quarterly in arrears and upon termination or commitment reduction at a rate per annum equal to 0.100% to 0.200% (such spread shall depend on the rating assigned to Oncor’s senior secured debt) of the commitments under the Oncor Revolving Credit Facility. Based on Oncor’s current ratings, its facility fee will be 0.175%.

A utilization fee is payable quarterly in arrears and upon termination on the average daily amount outstanding (to the extent of borrowings in excess of 50% of the commitments) under the Oncor Revolving Credit Facility at a rate per annum equal to 1.25% per annum.

Letter of credit fees under the Oncor Revolving Credit Facility are payable quarterly in arrears and upon termination at a rate per annum equal to the spread over adjusted LIBOR under the Oncor Revolving Credit Facility, less the issuing bank’s fronting fee.

Security—The Oncor Revolving Credit Facility, including hedging transactions, will be secured, on a post-closing basis, by certain of Oncor’s assets used in connection with its the transmission and distribution business.

Covenants—The Oncor Revolving Credit Facility contains customary covenants for facilities of this type, restricting, subject to certain exceptions, Oncor and its subsidiaries from, among other things:

• incurring additional liens;

• entering into mergers and consolidations;

• sales of substantial assets; and

• acquisitions and investments in subsidiaries.

In addition, the Oncor Revolving Credit Facility requires that Oncor maintain a maximum consolidated senior debt to capitalization ratio of 0.65 to 1.00 and observe certain customary reporting requirements and other affirmative covenants.

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Maturity—Amounts borrowed under the Oncor Revolving Credit Facility may be reborrowed from time to time from and after October 10, 2007 until October 10, 2013.

Events of Default—The Oncor Revolving Credit Facility contains certain customary events of default for facilities of this type the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments.

TXU Receivables Program

Also in connection with the Merger, the accounts receivable securitization program was amended. Concurrently, the financial institutions required that Oncor Electric Delivery repurchase all of the receivables it had previously sold to TXU Receivables Company totaling $113 million, which amount was refinanced by the Oncor Electric Delivery Revolving Facility.

Repayment of Existing Credit Facilities

On October 10, 2007, in connection with the Merger, TCEH and Oncor repaid in full all outstanding borrowings totaling $2.4 billion, together with interest and all other amounts due in connection with such repayment under the $6.5 billion of existing credit facilities. TCEH and Oncor also repaid floating rate senior notes with an aggregate principal amount of $1.0 billion and $800 million, respectively. (See Note 8).

Management Agreement

On October 10, 2007, in connection with the Merger, Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P., Goldman, Sachs & Co. and Lehman Brothers Inc. entered into a management agreement with Energy Future Holdings Corp. (the Management Agreement), pursuant to which affiliates of the investors will provide management, consulting, financial and other advisory services to Energy Future Holdings Corp. Pursuant to the Management Agreement, the Sponsor Group is entitled to receive an aggregate annual management fee of $35.0 million, which amount will increase 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of Energy Future Holdings Corp. or in connection with an initial public offering of Energy Future Holdings Corp. or if the parties mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, the Sponsor Group is also entitled to receive aggregate transaction fees of $300 million in connection with certain services provided in connection with the Merger and related transactions. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances.

Tax Sharing Agreement

In connection with the Merger, on October 10, 2007, Oncor, Oncor Holdings and Energy Future Holdings Corp. entered into a tax sharing agreement stating that, among other things, the allocation of tax liability to each of Oncor Holdings and Oncor will occur substantially as if these entities were stand-alone corporations and will require tax payments determined on that basis (without duplication for taxes paid by a subsidiary of Oncor or Oncor Holdings).

Oncor Limited Liability Company Agreement

In connection with the Merger, Oncor was converted from a Texas corporation to a Delaware limited liability company under the laws of the States of Texas and Delaware and entered into a limited liability

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company agreement (as amended, the Oncor LLC Agreement). The Oncor LLC Agreement provides that the independent directors of Oncor (who must comprise a majority of the members of Oncor’s board of directors), acting by majority vote, shall have the authority to prevent Oncor from making any distribution if they determine that it is in Oncor’s best interests to retain such amounts to meet expected future requirements (including continued compliance with the debt-to-equity ratio established from time to time by the Public Utility Commission of the State of Texas for ratemaking purposes). The Oncor LLC Agreement also provides that the Board of Directors of Oncor shall not distribute any amounts to Oncor’s member(s) to the extent that the Board of Directors of Oncor determines in good faith that it is necessary to retain such amounts to meet expected future requirements of the applicable entity. In addition to such restrictions on distributions, the Oncor LLC Agreement contains certain separateness provisions that require Oncor to conduct its activities separate and distinct from the activities of Energy Future Holdings Corp. and its other subsidiaries, including, without limitation, holding itself out as a separate legal entity.

Tender Offers and Consent Solicitations

On September 25, 2007, Energy Future Holdings Corp. commenced offers to purchase and consent solicitations with respect to $1.0 billion in aggregate principal amount of Energy Future Holdings Corp.’s outstanding 4.80% Series O Senior Notes due 2009, $250 million in aggregate principal amount of TCEH’s outstanding 6.125% Senior Notes due 2008 and $1.0 billion in aggregate principal amount of TCEH’s outstanding 7.000% Senior Notes due 2013. On the closing date of the Merger, Energy Future Holdings Corp. purchased an aggregate of $996 million, $247 million and $995 million of these notes, respectively.

Oncor Agreement in Principle with Stakeholders and PUCT Staff

On October 5, 2007, Oncor and Texas Energy Future Holdings Limited Partnership (TEF) reached an agreement in principle with major interested parties to resolve all outstanding issues in the PUCT review related to the proposed merger of TXU Corp. with Merger Sub including the outstanding rate case. TEF was formed by a group of investors led by Kohlberg Kravis Roberts & Co. (KKR) and Texas Pacific Group (TPG) to facilitate the merger. The agreement which was filed with the PUCT, was conditional upon the completion of the Merger and is subject to approval by the PUCT.

In addition to commitments Oncor made in its filings in the PUCT review, the stipulated agreement includes the following provisions, among others:

• Oncor will agree to $72 million in rate refunds, which is intended for all retail customers in its service territory, which will be requested by the parties to the settlement agreement. It is the intent of the parties to the agreement that the benefits of the credit flow directly to consumers, rather than to retail electric providers.

• The PUCT will dismiss Oncor’s pending rate case. Consistent with its existing agreement with the cities it serves, Oncor will file a system-wide rate case no later than July 1, 2008 based on a test-year ended December 31, 2007.

• Oncor will write off regulatory assets of approximately $56 million related to storm costs and 2002 restructuring expenses.

• TEF and Oncor will limit the dividends paid by Oncor through December 31, 2012, to an amount not to exceed Oncor’s net income (determined in accordance with GAAP), subject to certain defined adjustments.

• Oncor will commit to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions.

• Oncor will commit to $100 million in spending over the five-year period ending December 31, 2012 on demand side management or other energy efficiency initiatives. This spending will not be recoverable in rates.

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