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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2010

— OR —

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-12833

Energy Future Holdings Corp.

(Exact name of registrant as specified in its charter)

 

Texas		75-2669310
(State of incorporation)		(I.R.S. Employer Identification No.)
1601 Bryan Street, Dallas, TX 75201-3411		(214) 812-4600
(Address of principal executive offices) (Zip Code)		(Registrant’s telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨    (The registrant is not currently required to submit such files.)

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨    Accelerated filer  ¨

Non-Accelerated filer  þ    (Do not check if a smaller reporting company)    Smaller reporting company  ¨

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  þ

As of July 30, 2010, there were 1,669,277,542 shares of common stock outstanding, stated value $0.001 per share, of Energy Future Holdings Corp. (substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.’s parent holding company, and none of which is publicly traded).

 

 

 

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TABLE OF CONTENTS

 

 

				PAGE
GLOSSARY				ii
PART I. FINANCIAL INFORMATION
Item 1.		Financial Statements (Unaudited)
		Condensed Statements of Consolidated Income (Loss) – Three and Six Months Ended June 30, 2010 and 2009		1
		Condensed Statements of Consolidated Comprehensive Income (Loss) – Three and Six Months Ended June 30, 2010 and 2009		2
		Condensed Statements of Consolidated Cash Flows – Six Months Ended June 30, 2010 and 2009		3
		Condensed Consolidated Balance Sheets – June 30, 2010 and December 31, 2009		5
		Notes to Condensed Consolidated Financial Statements		6
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		56
Item 3.		Quantitative and Qualitative Disclosures About Market Risk		93
Item 4.		Controls and Procedures		99
PART II. OTHER INFORMATION
Item 1.		Legal Proceedings		99
Item 1A.		Risk Factors		99
Item 5.		Other Information		101
Item 6.		Exhibits		102
SIGNATURE				105

Energy Future Holdings Corp.’s (EFH Corp.) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the EFH Corp. website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on EFH Corp.’s website shall not be deemed a part of, or incorporated by reference into, this report on Form 10-Q. Readers should not rely on or assume the accuracy of any representation or warranty in any agreement that EFH Corp. has filed as an exhibit to this Form 10-Q because such representation or warranty may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent the parties’ risk allocation in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes or may no longer continue to be true as of any given date.

This Form 10-Q and other Securities and Exchange Commission filings of EFH Corp. and its subsidiaries occasionally make references to EFH Corp. (or “we,” “our,” “us” or “the company”), EFC Holdings, Intermediate Holding, TCEH, TXU Energy, Luminant, Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent companies’ financial statements 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 any other affiliate.

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GLOSSARY

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

 

2009 Form 10-K		EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2009
Adjusted EBITDA		Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this Form 10-Q (see reconciliation in Exhibits 99(b), 99(c) and 99(d)) solely because of the important role that Adjusted EBITDA plays in respect of the certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
Competitive Electric segment		Refers to the EFH Corp. business segment that consists principally of TCEH.
CREZ		Competitive Renewable Energy Zone
EBITDA		Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above.
EFC Holdings		Refers to Energy Future Competitive Holdings Company, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context.
EFH Corp.		Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include TCEH and Oncor.
EFH Corp. Senior Notes		Refers collectively to EFH Corp.’s 10.875% Senior Notes due November 1, 2017 (EFH Corp. 10.875% Notes) and EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes).
EFH Corp. Senior Secured Notes		Refers collectively to EFH Corp.’s 9.75% Senior Secured Notes due October 15, 2019 (EFH Corp. 9.75% Notes) and EFH Corp.’s 10.000% Senior Secured Notes due January 15, 2020 (EFH Corp. 10% Notes).
EFIH Finance		Refers to EFIH Finance Inc., a direct, wholly-owned subsidiary of Intermediate Holding, formed for the sole purpose of serving as co-issuer with Intermediate Holding of certain debt securities.
EFIH 9.75% Notes		Refers to Intermediate Holding’s and EFIH Finance’s 9.75% Senior Secured Notes due October 15, 2019.
EPA		US Environmental Protection Agency

 

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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
FASB		Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting
FERC		US Federal Energy Regulatory Commission
Fitch		Fitch Ratings, Ltd. (a credit rating agency)
GAAP		generally accepted accounting principles
GHG		greenhouse gas
GWh		gigawatt-hours
Intermediate Holding		Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.
kWh		kilowatt-hours
Lehman		Refers to certain subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code in 2008.
LIBOR		London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.
Luminant		Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.
Market heat rate		Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.
Merger		The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.
Merger Agreement		Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.

 

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MMBtu		million British thermal units
Moody’s		Moody’s Investors Services, Inc. (a credit rating agency)
MW		megawatts
MWh		megawatt-hours
NERC		North American Electric Reliability Corporation
NRC		US Nuclear Regulatory Commission
Oncor		Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities.
Oncor Holdings		Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of Intermediate Holding and the direct majority owner of Oncor, and/or its subsidiaries, depending on context.
Oncor Ring-Fenced Entities		Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.
OPEB		other postretirement employee benefits
PUCT		Public Utility Commission of Texas
PURA		Texas Public Utility Regulatory Act
Purchase accounting		The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
Regulated Delivery segment		Refers to the EFH Corp. business segment that consists of the operations of Oncor.
REP		retail electric provider
RRC		Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
S&P		Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency)
SEC		US Securities and Exchange Commission
Securities Act		Securities Act of 1933, as amended

 

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SG&A		selling, general and administrative
Sponsor Group		Refers collectively to the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co. (See Texas Holdings below.)
TCEH		Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFC Holdings and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy markets activities. Its major subsidiaries include Luminant and TXU Energy.
TCEH Finance		Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.
TCEH Senior Notes		Refers collectively to TCEH’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015 Series B (collectively, TCEH 10.25% Notes) and TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).
TCEH Senior Secured Facilities		Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 6 to Financial Statements for details of these facilities.
TCEQ		Texas Commission on Environmental Quality
Texas Holdings		Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.
Texas Holdings Group		Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.
Texas Transmission		Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of its subsidiaries or any member of the Sponsor Group.
TRE		Refers to Texas Regional Entity, an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and ERCOT protocols.
TXU Energy		Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.
TXU Gas		TXU Gas Company, a former subsidiary of EFH Corp.
US		United States of America
VIE		variable interest entity

 

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PART I. FINANCIAL INFORMATION

 

Item 1.

FINANCIAL STATEMENTS

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

(millions of dollars)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Operating revenues		$	1,993			$	2,342			$	3,992			$	4,481
Fuel, purchased power costs and delivery fees			(1,074	)			(700	)			(2,121	)			(1,301	)
Net gain (loss) from commodity hedging and trading activities			67				(248	)			1,280				880
Operating costs			(229	)			(395	)			(426	)			(783	)
Depreciation and amortization			(350	)			(423	)			(692	)			(830	)
Selling, general and administrative expenses			(185	)			(270	)			(373	)			(516	)
Franchise and revenue-based taxes			(26	)			(79	)			(49	)			(165	)
Impairment of goodwill			—				—				—				(90	)
Other income (Note 16)			211				13				244				26
Other deductions (Note 16)			(7	)			(7	)			(18	)			(18	)
Interest income			—				11				9				12
Interest expense and related charges (Note 16)			(1,122	)			(431	)			(2,074	)			(1,096	)
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries			(722	)			(187	)			(228	)			600
Income tax (expense) benefit			237				48				35				(285	)
Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 2)			59				—				122				—
Net income (loss)			(426	)			(139	)			(71	)			315
Net income attributable to noncontrolling interests			—				(16	)			—				(28	)
Net income (loss) attributable to EFH Corp.		$	(426	)		$	(155	)		$	(71	)		$	287

See Notes to Financial Statements.

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(millions of dollars)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Net income (loss)		$	(426	)		$	(139	)		$	(71	)		$	315
Other comprehensive income (loss), net of tax effects:
Reclassification of pension and other retirement benefit costs (net of tax benefit of $2, $—, $— and $—)			(4	)			—				—				—
Cash flow hedges:
Net increase (decrease) in fair value of derivatives (net of tax benefit of $—, $—, $— and $9)			—				1				—				(16	)
Derivative value net loss related to hedged transactions recognized during the period and reported in net income (loss) (net of tax benefit of $8, $17, $18 and $32)			17				32				36				58
Total effect of cash flow hedges			17				33				36				42
Total adjustments to net income (loss)			13				33				36				42
Comprehensive income (loss)			(413	)			(106	)			(35	)			357
Comprehensive income attributable to noncontrolling interests			—				(16	)			—				(28	)
Comprehensive income (loss) attributable to EFH Corp.		$	(413	)		$	(122	)		$	(35	)		$	329

See Notes to Financial Statements.

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(millions of dollars)

 

		Six Months Ended June 30,
		2010				2009
Cash flows – operating activities:
Net income (loss)		$	(71	)		$	315
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization			881				1,045
Deferred income tax expense – net			3				223
Impairment of goodwill			—				90
Increase of toggle notes in lieu of cash interest (Note 6)			269				248
Unrealized net gains from mark-to-market valuations of commodity positions			(848	)			(710	)
Unrealized net (gains) losses from mark-to-market valuations of interest rate swaps			361				(665	)
Equity in earnings of unconsolidated subsidiaries			(122	)			—
Distributions of earnings from unconsolidated subsidiaries			87				—
Net gain on debt exchanges (Note 6)			(143	)			—
Bad debt expense (Note 5)			59				41
Stock-based incentive compensation expense			13				12
Losses on dedesignated cash flow hedges (interest rate swaps)			53				84
Net gain on sale of assets			(81	)			—
Other, net			1				(3	)
Changes in operating assets and liabilities:
Impact of accounts receivable securitization program (Note 5)			(383	)			80
Margin deposits – net			25				98
Deferred advanced metering system revenues			—				37
Other operating assets and liabilities			30				(391	)
Cash provided by operating activities			134				504
Cash flows – financing activities:
Issuances of long-term debt (Note 6)			500				435
Repayments and repurchases of long-term debt (Note 6)			(401	)			(228	)
Net short-term borrowings under accounts receivable securitization program (Note 5)			158				—
Increase (decrease) in other short-term borrowings (Note 6)			(218	)			205
Decrease in note payable to unconsolidated subsidiary			(17	)			—
Contributions from noncontrolling interests			14				32
Distributions paid to noncontrolling interests			—				(17	)
Debt exchange and issuance costs			(15	)			(4	)
Other, net			18				21
Cash provided by financing activities			39				444
Cash flows – investing activities:
Capital expenditures			(571	)			(1,277	)
Nuclear fuel purchases			(66	)			(87	)
Money market fund redemptions			—				142
Investment redeemed/(posted) with derivative counterparty (Note 11)			400				(400	)
Proceeds from sale of assets			141				1
Reduction of letter of credit facility deposited with trustee (Note 6)			—				115
Other changes in restricted cash			(5	)			14
Proceeds from sales of environmental allowances and credits			6				7
Purchases of environmental allowances and credits			(10	)			(14	)
Proceeds from sales of nuclear decommissioning trust fund securities			803				2,231
Investments in nuclear decommissioning trust fund securities			(811	)			(2,238	)
Other, net			(9	)			28
Cash used in investing activities			(122	)			(1,478	)

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)

(Unaudited)

(millions of dollars)

 

Net change in cash and cash equivalents			51				(530	)
Effects of deconsolidation of Oncor Holdings			(29	)			—
Cash and cash equivalents – beginning balance			1,189				1,689
Cash and cash equivalents – ending balance		$	1,211			$	1,159

See Notes to Financial Statements.

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(millions of dollars)

 

		June 30, 2010				December 31, 2009 (see Note 2)
ASSETS
Current assets:
Cash and cash equivalents		$	1,211			$	1,189
Investment posted with counterparty (Note 11)			—				425
Restricted cash (Note 16)			6				48
Trade accounts receivable – net (2010 includes $880 in pledged amounts related to a VIE (Notes 3 and 5))			1,280				1,260
Inventories			401				485
Commodity and other derivative contractual assets (Note 11)			2,857				2,391
Accumulated deferred income taxes			169				5
Margin deposits related to commodity positions			173				187
Other current assets			76				136
Total current assets			6,173				6,126
Restricted cash (Note 16)			1,135				1,149
Receivables from unconsolidated subsidiary (Note 14)			1,270				—
Investments in unconsolidated subsidiaries (Note 2)			5,450				44
Other investments (Note 16)			628				706
Property, plant and equipment – net (Note 16)			20,770				30,108
Goodwill (Note 4)			10,252				14,316
Identifiable intangible assets – net (Note 4)			2,513				2,876
Regulatory assets – net			—				1,959
Commodity and other derivative contractual assets (Note 11)			2,132				1,533
Other noncurrent assets, principally unamortized debt issuance costs			719				845
Total assets		$	51,042			$	59,662
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (2010 includes $158 related to a VIE (Notes 3 and 6))		$	893			$	1,569
Long-term debt due currently (Note 6)			253				417
Trade accounts payable			724				896
Net payables due to unconsolidated subsidiary (Note 14)			218				—
Commodity and other derivative contractual liabilities (Note 11)			2,648				2,392
Margin deposits related to commodity positions			530				520
Accrued interest			457				526
Other current liabilities			352				744
Total current liabilities			6,075				7,064
Accumulated deferred income taxes			4,953				6,131
Investment tax credits			—				37
Commodity and other derivative contractual liabilities (Note 11)			1,336				1,060
Notes or other liabilities due to unconsolidated subsidiary (Note 14)			347				—
Long-term debt, less amounts due currently (Note 6)			36,768				41,440
Other noncurrent liabilities and deferred credits (Note 16)			4,771				5,766
Total liabilities			54,250				61,498
Commitments and Contingencies (Note 7)
Equity (Note 8):
EFH Corp. shareholders’ equity			(3,269	)			(3,247	)
Noncontrolling interests in subsidiaries			61				1,411
Total equity			(3,208	)			(1,836	)
Total liabilities and equity		$	51,042			$	59,662

See Notes to Financial Statements.

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1.	BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

EFH Corp., a Texas corporation, is a Dallas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority (approximately 80%) owned subsidiary engaged in regulated electricity transmission and distribution operations in Texas. See Note 3 regarding the deconsolidation of Oncor (and its majority owner, Oncor Holdings) as a result of amended consolidation accounting standards related to variable interest entities (VIEs) effective January 1, 2010.

References in this report to “we,” “our,” “us” and “the company” are to EFH Corp. and/or its subsidiaries, TCEH and/or its subsidiaries, or Oncor and/or its subsidiary as apparent in the context. See “Glossary” for other defined terms.

Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. Such measures include, among other things: the sale of a 19.75% equity interest in Oncor to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor’s board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or contractual obligations of any member of the Texas Holdings Group. Moreover, Oncor’s operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.

We have two reportable segments: the Competitive Electric segment, which is comprised principally of TCEH, and the Regulated Delivery segment, which is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary. See Note 15 for further information concerning reportable business segments.

Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in the 2009 Form 10-K with the exception of the prospective adoption of amended guidance regarding consolidation accounting standards related to VIEs that resulted in the deconsolidation of Oncor Holdings as discussed in Note 3 and amended guidance regarding transfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding under the program now reported as short-term borrowings as discussed in Note 5. Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method (see Notes 2 and 3). 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. All acquisitions of outstanding debt for cash, including the notes that had been issued in lieu of cash interest, are presented in the financing activities section of the statement of cash flows. 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 2009 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.

 

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Use of Estimates

Preparation of financial statements requires 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 fair value measurements. 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.

Changes in Accounting Standards

In June 2009, the FASB issued new guidance that requires reconsideration of consolidation conclusions for all VIEs and other entities with which we are involved. We adopted this new guidance as of January 1, 2010. See Note 3 for discussion of our evaluation of VIEs and the resulting deconsolidation of Oncor Holdings and its subsidiaries that resulted in our investment in Oncor Holdings and its subsidiaries being prospectively reported as an equity method investment. There were no other material effects on our financial statements as a result of the adoption of this new guidance.

In June 2009, the FASB issued new guidance regarding accounting for transfers of financial assets that eliminates the concept of a qualifying special purpose entity, changes the requirements for derecognizing financial assets and requires additional disclosures. We adopted this new guidance as of January 1, 2010. Accordingly, the trade accounts receivable amounts under the accounts receivable securitization program discussed in Note 5 are prospectively reported as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, the activity was accounted for as a sale of accounts receivable in accordance with previous accounting standards, which resulted in the funding being recorded as a reduction of accounts receivable. This new guidance does not impact the covenant-related ratio calculations in our debt agreements.

 

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2.	EQUITY METHOD INVESTMENTS

Investments in unconsolidated subsidiaries consisted of the following:

 

		June 30, 2010			December 31, 2009
Investment in Oncor Holdings (100% owned) (a)		$	5,450		$	—
Investment in natural gas gathering pipeline business (25% owned) (b)			—			44
Total investments in unconsolidated subsidiaries		$	5,450		$	44

 

(a)	Oncor Holdings was deconsolidated effective January 1, 2010 (see Notes 1 and 3).

(b)	A controlling interest in this previously consolidated subsidiary was sold in 2009, and the remaining interests were sold in June 2010.

Oncor Holdings

Effective January 1, 2010, we account for our investment in Oncor Holdings under the equity method (see Note 3). Prior to this date, Oncor Holdings was a consolidated subsidiary. Oncor Holdings owns approximately 80% of Oncor (an SEC registrant), which is engaged in regulated electricity transmission and distribution operations in Texas. Distribution revenues from TCEH represented 37% of total revenues for Oncor Holdings for both the six months ended June 30, 2010 and 2009. Condensed statements of consolidated income of Oncor Holdings for the three and six months ended June 30, 2010 and 2009 are presented below:

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Operating revenues		$	702			$	653			$	1,405			$	1,266
Operation and maintenance expenses			(252	)			(230	)			(501	)			(456	)
Depreciation and amortization			(164	)			(132	)			(331	)			(258	)
Taxes other than income taxes			(93	)			(90	)			(187	)			(187	)
Other income			9				10				19				20
Other deductions			(2	)			(4	)			(3	)			(8	)
Interest income			9				10				19				19
Interest expense and related charges			(86	)			(87	)			(170	)			(171	)
Income before income taxes			123				130				251				225
Income tax expense			(49	)			(48	)			(98	)			(85	)
Net income			74				82				153				140
Net income attributable to noncontrolling interests			(15	)			(16	)			(31	)			(28	)
Net income attributable to Oncor Holdings		$	59			$	66			$	122			$	112

 

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Assets and liabilities of Oncor Holdings at June 30, 2010 and December 31, 2009 are presented below:

 

		June 30, 2010			December 31, 2009
		(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents		$	14		$	29
Restricted cash			47			47
Trade accounts receivable — net			282			243
Trade accounts and other receivables from affiliates			215			188
Income taxes receivable from EFH Corp.			3			—
Inventories			95			92
Accumulated deferred income taxes			6			10
Prepayments			82			76
Other current assets			4			8
Total current assets			748			693
Restricted cash			16			14
Other investments			75			72
Property, plant and equipment — net			9,459			9,174
Goodwill			4,064			4,064
Note receivable due from TCEH			199			217
Regulatory assets — net			1,707			1,959
Other noncurrent assets			207			51
Total assets		$	16,475		$	16,244
LIABILITIES
Current liabilities:
Short-term borrowings		$	948		$	616
Long-term debt due currently			110			108
Trade accounts payable – nonaffiliates			147			129
Income taxes payable to EFH Corp.			—			5
Accrued taxes other than income			80			137
Accrued interest			102			104
Other current liabilities			92			106
Total current liabilities			1,479			1,205
Accumulated deferred income taxes			1,374			1,369
Investment tax credits			35			37
Long-term debt, less amounts due currently			4,942			4,996
Other noncurrent liabilities and deferred credits			1,788			1,879
Total liabilities		$	9,618		$	9,486

 

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3.	CONSOLIDATION OF VARIABLE INTEREST ENTITIES

We adopted amended accounting standards on January 1, 2010 that require consolidation of a VIE if we have the power to direct the significant activities of the VIE and the right or obligation to absorb profit and loss from the VIE. A VIE is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. As discussed below, our balance sheet includes assets and liabilities of VIEs that meet the consolidation standards and also reflects the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor.

Our variable interests consist of equity investments. In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE.

Consolidated VIEs

See discussion in Note 5 regarding the VIE related to our accounts receivable securitization program that continues to be consolidated under the amended accounting standards.

We also continue to consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our existing Comanche Peak nuclear-fueled generation facility using MHI’s US-Advanced Pressurized Water Reactor technology and to obtain a combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries of TCEH and MHI that hold 88% and 12% of the equity interests, respectively (see Note 8).

The carrying amounts and classifications of the assets and liabilities related to our consolidated VIEs as of June 30, 2010 are as follows:

 

Assets:					Liabilities:
Cash and cash equivalents		$	8		Short-term borrowings (a)		$	158
Accounts receivable (a)			880		Trade accounts payable			3
Property, plant and equipment			93		Other current liabilities			1
Other assets, including $2 of current assets			9
Total assets		$	990		Total liabilities		$	162

 

(a)	As a result of the January 1, 2010 adoption of new accounting guidance related to transfers of financial assets, the balance sheet at June 30, 2010 reflects $880 million of pledged accounts receivable and $158 million of short-term borrowings (see Note 5).

The assets of our consolidated VIEs can only be used to settle the obligations of the VIE, and the creditors of our consolidated VIEs do not have recourse to our general credit.

 

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Non-Consolidated VIEs

The adoption of the amended accounting standards resulted in the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor, and the reporting of our investment in Oncor Holdings under the equity method on a prospective basis.

In reaching the conclusion to deconsolidate, we conducted an extensive analysis of Oncor Holdings’ underlying governing documents and management structure. Oncor Holdings’ unique governance structure was adopted in conjunction with the Merger, when the Sponsor Group, EFH Corp. and Oncor agreed to implement structural and operational measures to “ring-fence” (the Ring-Fencing Measures) Oncor Holdings and Oncor as discussed in Note 1. The Ring-Fencing Measures were designed to prevent, among other things, (i) increased borrowing costs at Oncor due to the attribution to Oncor of debt from any of our other subsidiaries, (ii) the activities of our unregulated operations following the Merger resulting in the deterioration of Oncor’s business, financial condition and/or investment in infrastructure, and (iii) Oncor becoming substantively consolidated into a bankruptcy proceeding involving any member of the Texas Holdings Group. The Ring-Fencing Measures effectively separated the daily operational and management control of Oncor Holdings and Oncor from EFH Corp. and its other subsidiaries. By implementing the Ring-Fencing Measures, Oncor maintained its investment grade credit rating following the Merger and reaffirmed Oncor’s independence from our unregulated businesses to the PUCT.

We determined the most significant activities affecting the economic performance of Oncor Holdings (and Oncor) are the operation, maintenance and growth of Oncor’s electric transmission and distribution assets and the preservation of its investment grade credit profile. The boards of directors of Oncor Holdings and Oncor have ultimate responsibility for the management of the day-to-day operations of their respective businesses, including the approval of Oncor’s capital expenditure and operating budgets and the timing and prosecution of Oncor’s rate cases. While the boards include members appointed by EFH Corp., a majority of the board members are independent in accordance with rules established by the New York Stock Exchange, and therefore, we concluded for purposes of applying the amended accounting standards that EFH Corp. does not have power to control the activities deemed most significant to Oncor Holdings’ (and Oncor’s) economic performance.

In assessing EFH Corp.’s ability to exercise control over Oncor Holdings and Oncor, we considered whether it could take actions to circumvent the purpose and intent of the Ring-Fencing Measures (including changing the composition of Oncor Holdings’ or Oncor’s board) in order to gain control over the day-to-day operations of either Oncor Holdings or Oncor. We also considered whether (i) EFH Corp. has the unilateral power to dissolve, liquidate or force into bankruptcy either Oncor Holdings or Oncor, (ii) EFH Corp. could unilaterally amend the Ring-Fencing Measures contained in underlying governing documents of Oncor Holdings or Oncor, and (iii) EFH Corp. could control Oncor’s ability to pay distributions and thereby enhance its own cash flow. We concluded that, in each case, no such opportunity exists.

We account for our investment in Oncor Holdings under the equity method, as opposed to the cost method, because we have the ability to exercise significant influence (as defined by US GAAP) over its activities.

The carrying value of our variable interest in VIEs that we do not consolidate totaled $5.450 billion at June 30, 2010, which represents our investment in Oncor Holdings, and is reported as investments in unconsolidated subsidiaries in the balance sheet. Our maximum exposure to loss from these interests does not exceed our carrying value. See Note 2 for additional information about equity method investments including condensed income statement and balance sheet data for Oncor Holdings.

 

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4.	GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

Reported goodwill as of June 30, 2010 and December 31, 2009 totaled $10.2 billion and $14.3 billion, respectively, with $10.2 billion assigned to the Competitive Electric segment. The change from December 31, 2009 reflects the deconsolidation of Oncor Holdings effective January 1, 2010 due to the adoption of new accounting guidance for consolidation discussed in Note 1, as $4.1 billion of goodwill has been assigned to the Regulated Delivery segment. None of the goodwill is being deducted for tax purposes.

EFH Corp. management continues to evaluate the effect of declining wholesale power prices, largely due to lower natural gas prices, on the carrying value of goodwill related to the Competitive Electric segment. In light of the continuing decline in natural gas prices, this evaluation could result in the recording of a non-cash goodwill impairment charge, possibly in the third quarter 2010.

Identifiable Intangible Assets

Identifiable intangible assets reported in the balance sheet are comprised of the following:

 

		As of June 30, 2010 (a)									As of December 31, 2009
Identifiable Intangible Asset		Gross Carrying Amount			Accumulated Amortization			Net			Gross Carrying Amount			Accumulated Amortization			Net
Retail customer relationship		$	463		$	254		$	209		$	463		$	215		$	248
Favorable purchase and sales contracts			700			398			302			700			374			326
Capitalized in-service software			259			79			180			490			167			323
Environmental allowances and credits			993			256			737			992			212			780
Land easements			—			—			—			188			72			116
Mining development costs			46			11			35			32			5			27
Total intangible assets subject to amortization		$	2,461		$	998			1,463		$	2,865		$	1,045			1,820
Trade name (not subject to amortization)									955									955
Mineral interests (not currently subject to amortization)									95									101
Total intangible assets								$	2,513								$	2,876

 

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010.

 

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Amortization expense related to intangible assets (including income statement line item) consisted of:

 

						Three Months Ended June 30,						Six Months Ended June 30,
Identifiable Intangible Asset		Income Statement Line		Segment		2010			2009			2010			2009
Retail customer relationship		Depreciation and amortization		Competitive Electric		$	19		$	21		$	39		$	43
Favorable purchase and sales contracts		Operating revenues/fuel, purchased power costs and delivery fees		Competitive Electric			10			32			24			73
Capitalized in-service software		Depreciation and amortization		All (a)			9			12			17			23
Environmental allowances and credits		Fuel, purchased power costs and delivery fees		Competitive Electric			22			20			44			41
Land easements		Depreciation and amortization		Regulated Delivery (a)			—			1			—			2
Mining development costs		Depreciation and amortization		Competitive Electric			3			—			5			—
Total amortization expense						$	63		$	86		$	129		$	182

 

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010.

Estimated Amortization of Intangible Assets — The estimated aggregate amortization expense of intangible assets for each of the next five fiscal years is as follows:

 

Year		Amount
2010		$	252
2011			191
2012			150
2013			129
2014			114

 

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5.	TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM

TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). Under the program, TXU Energy (originator) sells trade accounts receivable to TXU Receivables Company, which is an entity created for the special purpose of purchasing receivables from the originator and is a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. In accordance with the amended transfers and servicing accounting standard as discussed in Note 1, the trade accounts receivable amounts under the program are reported as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, the activity was accounted for as a sale of accounts receivable in accordance with previous accounting standards, which resulted in the funding being recorded as a reduction of accounts receivable.

In June 2010, the accounts receivable securitization program was amended. The amendments, among other things, reduced the maximum funding amount under the program to $350 million from $700 million. Program funding declined from $383 million at December 31, 2009 to $158 million at June 30, 2010. Under the terms of the program, available funding was reduced by $46 million of customer deposits held by the originator because TCEH’s credit ratings were lower than Ba3/BB-. The declines in actual and maximum funding amounts reflected exclusion of receivables under contractual sales agreements.

All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Ongoing 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 and other factors such as changes in sales prices and volumes. TXU Receivables Company has issued a subordinated note payable to the originator for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The subordinated note issued by TXU Receivables Company is subordinated to the undivided interests of the funding entities in the purchased receivables. The balance of the subordinated note payable, which is eliminated in consolidation, totaled $722 million and $463 million at June 30, 2010 and December 31, 2009, respectively.

The discount from face amount on the purchase of receivables from the originator principally funds program fees paid to the funding entities. The program fees consist primarily of interest costs on the underlying financing. Consistent with the change in balance sheet presentation of the funding discussed above, the program fees are currently reported as interest expense and related charges but were previously reported as losses on sale of receivables reported in SG&A expense. The discount also funds a servicing fee, which is reported as SG&A expense, paid by TXU Receivables Company to EFH Corporate Services Company (Service Co.), a direct wholly-owned subsidiary of EFH Corp., which provides recordkeeping services and is the collection agent for the program.

Program fee amounts were as follows:

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Program fees		$	3			$	3			$	5			$	7
Program fees as a percentage of average funding (annualized)			4.2	%			2.9	%			2.8	%			3.3	%

Funding under the program decreased $225 million for the six months ended June 30, 2010 and increased $80 million for the six months ended June 30, 2009.

 

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Activities of TXU Receivables Company were as follows:

 

		Six Months Ended June 30,
		2010				2009
Cash collections on accounts receivable		$	2,921			$	2,769
Face amount of new receivables purchased			(2,955	)			(2,931	)
Discount from face amount of purchased receivables			6				8
Program fees paid to funding entities			(5	)			(7	)
Servicing fees paid to Service Co. for recordkeeping and collection services			(1	)			(1	)
Increase in subordinated notes payable			259				82
Financing/operating cash flows used by (provided to) originator under the program		$	225			$	(80	)

Changes in funding under the program have previously been reported as operating cash flows, and the amended accounting rule requires that the amount of funding under the program upon the January 1, 2010 adoption ($383 million) be reported as a use of operating cash flows and a source of financing cash flows. All changes in funding subsequent to adoption of the amended standard are reported as financing activities.

The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if 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 funding entities do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Receivables Company or Service Co. defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than Service Co., any parent guarantor of the originator or the originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of June 30, 2010, there were no such events of termination.

Upon termination of the program, liquidity would be reduced 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.

Trade Accounts Receivable

 

		June 30, 2010 (a)				December 31, 2009
Wholesale and retail trade accounts receivable, including $880 in pledged retail receivables at June 30, 2010		$	1,348			$	1,726
Undivided interests in retail accounts receivable sold by TXU Receivables Company			—				(383	)
Allowance for uncollectible accounts			(68	)			(83	)
Trade accounts receivable — reported in balance sheet		$	1,280			$	1,260

 

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010.

Gross trade accounts receivable at June 30, 2010 and December 31, 2009 included unbilled revenues of $433 million and $546 million, respectively.

Allowance for Uncollectible Accounts Receivable

 

		Six Months Ended June 30,
		2010				2009
Allowance for uncollectible accounts receivable as of beginning of period		$	81			$	70
Increase for bad debt expense			59				41
Decrease for account write-offs			(72	)			(51	)
Other			—				(1	)
Allowance for uncollectible accounts receivable as of end of period		$	68			$	59

 

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6.	SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At June 30, 2010, outstanding short-term borrowings totaled $893 million, which included $735 million under TCEH credit facilities at a weighted average interest rate of 3.87%, excluding certain customary fees, and $158 million under the accounts receivable securitization program discussed in Note 5.

At December 31, 2009, we had outstanding short-term borrowings of $1.569 billion at a weighted average interest rate of 2.50%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $953 million for TCEH and $616 million for Oncor.

Credit Facilities

Credit facilities with cash borrowing and/or letter of credit availability at June 30, 2010 are presented below. The facilities are all senior secured facilities of TCEH.

 

				At June 30, 2010
Authorized Borrowers and Facility		Maturity Date		Facility Limit			Letters of Credit			Cash Borrowings			Availability
TCEH Revolving Credit Facility (a)		October 2013		$	2,700		$	—		$	735		$	1,880
TCEH Letter of Credit Facility (b)		October 2014			1,250			—			1,250			—
Subtotal TCEH				$	3,950		$	—		$	1,985		$	1,880
TCEH Commodity Collateral Posting Facility (c)		December 2012			Unlimited		$	—		$	—			Unlimited

 

(a)

Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $144 million of commitments from Lehman that are only available from the fronting banks and the swingline lender and excludes $85 million of requested cash draws that have not been funded by Lehman. All outstanding borrowings under this facility at June 30, 2010 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility.

(b)

Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the inception of the facility, are classified as long-term debt, and except for $115 million related to a letter of credit drawn in June 2009, have been retained as restricted cash. Letters of credit totaling $706 million issued as of June 30, 2010 are supported by the restricted cash, and the remaining letter of credit availability totals $429 million.

(c)

Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 490 million MMBtu as of June 30, 2010. As of June 30, 2010, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information.

 

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Long-Term Debt

At June 30, 2010 and December 31, 2009, long-term debt consisted of the following:

 

		June 30, 2010				December 31, 2009
TCEH
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
8.250% Fixed Series 2001A due October 1, 2030			71				71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a)			217				217
8.250% Fixed Series 2001D-1 due May 1, 2033			171				171
0.282% Floating Series 2001D-2 due May 1, 2033 (b)			97				97
0.370% Floating Taxable Series 2001I due December 1, 2036 (c)			62				62
0.282% 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
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
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028			14				14
Unamortized fair value discount related to pollution control revenue bonds (d)			(140	)			(147	)
Senior Secured Facilities:
3.904% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)(g)			15,977				16,079
3.851% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f)			4,054				4,075
3.847% TCEH Letter of Credit Facility maturing October 10, 2014 (f)			1,250				1,250
0.329% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (h)			—				—
Other:
10.25% Fixed Senior Notes due November 1, 2015 (i)			2,834				2,944
10.25% Fixed Senior Notes due November 1, 2015, Series B (i)			1,855				1,913
10.50 / 11.25% Senior Toggle Notes due November 1, 2016 (j)			2,007				1,952
7.000% Fixed Senior Notes due March 15, 2013			5				5
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015			42				55
Capital lease obligations			83				153
Unamortized fair value discount (d)			(3	)			(4	)
Total TCEH		$	29,499			$	29,810

 

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		June 30, 2010				December 31, 2009
EFC Holdings
9.580% Fixed Notes due in semiannual installments through December 4, 2019		$	51			$	51
8.254% Fixed Notes due in quarterly installments through December 31, 2021			48				50
1.144% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (f)			1				1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037			8				8
Unamortized fair value discount (d)			(10	)			(11	)
Total EFC Holdings			98				99
EFH Corp. (parent entity)
10.875% Fixed Senior Notes due November 1, 2017			1,812				1,831
11.25 / 12.00% Senior Toggle Notes due November 1, 2017			2,758				2,797
9.75% Fixed Senior Secured Notes due October 15, 2019			115				115
10.000% Fixed Senior Secured Notes due January 15, 2020			606				—
5.550% Fixed Senior Notes Series P due November 15, 2014 (k)			983				983
6.500% Fixed Senior Notes Series Q due November 15, 2024 (k)			740				740
6.550% Fixed Senior Notes Series R due November 15, 2034 (k)			744				744
8.820% Building Financing due semiannually through February 11, 2022 (l)			71				75
Unamortized fair value premium related to Building Financing (d)			16				17
Capital lease obligations			7				—
Unamortized fair value discount (d)			(569	)			(599	)
Total EFH Corp.			7,283				6,703
Intermediate Holding
9.75% Fixed Senior Secured Notes due October 15, 2019			141				141
Oncor (m) (n)
6.375% Fixed Senior Notes due May 1, 2012			—				700
5.950% Fixed Senior Notes due September 1, 2013			—				650
6.375% Fixed Senior Notes due January 15, 2015			—				500
6.800% Fixed Senior Notes due September 1, 2018			—				550
7.000% Fixed Debentures due September 1, 2022			—				800
7.000% Fixed Senior Notes due May 1, 2032			—				500
7.250% Fixed Senior Notes due January 15, 2033			—				350
7.500% Fixed Senior Notes due September 1, 2038			—				300
Unamortized discount			—				(15	)
Total Oncor			—				4,335
Oncor Electric Delivery Transition Bond Company LLC (n) (o)
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010			—				13
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013			—				130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015			—				145
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012			—				197
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016			—				290
Total Oncor Electric Delivery Transition Bond Company LLC			—				775
Unamortized fair value discount related to transition bonds (d)			—				(6	)
Total Oncor consolidated			—				5,104
Total EFH Corp. consolidated			37,021				41,857
Less amount due currently			(253	)			(417	)
Total long-term debt		$	36,768			$	41,440

 

(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, 2010. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(c)	Interest rate in effect at June 30, 2010. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit.

(d)	Amount represents unamortized fair value adjustments recorded under purchase accounting.

(e)	Interest rate swapped to fixed on $16.30 billion principal amount.

(f)	Interest rates in effect at June 30, 2010.

(g)	Amount excludes $20 million that is held by EFH Corp. and eliminated in consolidation.

(h)	Interest rate in effect at June 30, 2010, excluding a quarterly maintenance fee of $11 million. See “Credit Facilities” above for more information.

 

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(i)	Amounts exclude $166 million and $145 million of the TCEH Senior Notes and TCEH Senior Notes, Series B, respectively, that are held by EFH Corp. and Intermediate Holding and eliminated in consolidation.

(j)	Amount excludes $55 million that is held by EFH Corp. and eliminated in consolidation.

(k)	Amounts exclude $9 million, $6 million and $3 million of the Series P, Series Q and Series R notes, respectively, that are held by Intermediate Holding and eliminated in consolidation.

(l)

This financing is secured and will be serviced with $115 million in restricted cash drawn in June 2009 by the beneficiary of a letter of credit. The issuer elected not to extend the expiration date of the letter of credit, and TCEH elected to allow the drawing in lieu of reissuing the letter of credit under the TCEH Revolving Credit Facility. The remaining $104 million of the prepayment (net of $11 million of debt service payments) is included in other current assets and other noncurrent assets on the balance sheet.

(m)	Secured with first priority lien.

(n)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010.

(o)	These bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset.

Debt-Related Activity in 2010 — Repayments of long-term debt in 2010 totaling $190 million represented principal payments at scheduled maturity dates as well as other repayments totaling $87 million, principally related to capitalized leases. Payments at scheduled amortization or maturity dates included $82 million repaid under the TCEH Initial Term Loan Facility and $21 million repaid under the TCEH Delayed Draw Term Loan Facility. See “2010 Debt Exchanges and Repurchases” below for $460 million principal amount of debt acquired in debt exchanges and repurchases completed in March through June 2010 and $648 million principal amount of debt acquired in debt exchanges and repurchases in July 2010.

Long-term debt increased as a result of EFH Corp. issuing, through the payment-in-kind (PIK) election, $162 million principal amount of its 11.25%/12.00% Senior Toggle Notes due November 2017 (EFH Corp. Toggle Notes) and TCEH issuing, through the PIK election, $110 million principal amount of its 10.50%/11.25% Senior Toggle Notes due November 2016 (TCEH Toggle Notes), in each case, in lieu of making cash interest payments.

EFH Corp. 10% Senior Secured Notes — In January 2010, EFH Corp. issued $500 million aggregate principal amount of 10.000% Senior Secured Notes due 2020 (the EFH Corp. 10% Notes). In various exchange transactions during 2010, EFH Corp. issued an additional $561 million of EFH Corp. 10% Notes (see “2010 Debt Exchanges and Repurchases” below). The notes will mature on January 15, 2020, and interest is payable in cash in arrears on January 15 and July 15 of each year, beginning July 15, 2010, at a fixed rate of 10.00% per annum.

The EFH Corp. 10% Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding. The guarantee from Intermediate Holding is secured by the pledge of all membership interests and other investments Intermediate Holding owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries (the Collateral). The guarantee from EFC Holdings is not secured. The EFH Corp. 10% Notes are secured by the Collateral on an equal and ratable basis with the EFH Corp. 9.75% Senior Secured Notes and EFIH 9.75% Notes.

The EFH Corp. 10% Notes are a senior obligation and rank equally in right of payment with all senior indebtedness of EFH Corp. and are senior in right of payment to any future subordinated indebtedness of EFH Corp. These notes are effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other liabilities of EFH Corp.’s non-guarantor subsidiaries.

The guarantees of the EFH Corp. 10% Notes are the general senior obligations of each guarantor and rank equally in right of payment with all existing and future senior indebtedness of each guarantor. The guarantee from Intermediate Holding is effectively senior to all unsecured indebtedness of Intermediate Holding to the extent of the value of the Collateral. The guarantees are effectively subordinated to all secured indebtedness of each guarantor secured by assets other than the Collateral to the extent of the value of the assets securing such indebtedness and are structurally subordinated to any existing and future indebtedness and liabilities of EFH Corp.’s subsidiaries that are not guarantors.

 

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The EFH Corp. 10% Notes and indenture governing such notes restrict EFH Corp. and its restricted subsidiaries’ ability to, among other things, make restricted payments, incur debt and issue preferred stock, incur liens, pay dividends, merge, consolidate or sell assets and engage in certain transactions with affiliates. These covenants are subject to a number of limitations and exceptions. These notes and indenture also contain customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur and are continuing under these notes and the related indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount of the notes to be due and payable immediately.

Until January 15, 2013, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFH Corp. 10% Notes from time to time at a redemption price of 110.000% of the aggregate principal amount of the notes being redeemed, plus accrued and unpaid interest, if any. EFH Corp. may redeem the notes at any time prior to January 15, 2015 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. EFH Corp. may also redeem the notes, in whole or in part, at any time on or after January 15, 2015, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control (as described in the indenture), EFH Corp. must offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

The EFH Corp. 10% Notes were issued in private placements and have not been registered under the Securities Act. EFH Corp. has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFH Corp. 10% Notes (except for provisions relating to the transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the EFH Corp. 10% Notes. EFH Corp. has agreed to use commercially reasonable efforts to cause the exchange offer to be completed or, if required under special circumstances, to have one or more shelf registration statements declared effective, within 360 days after the issue date of the notes. If this obligation is not satisfied (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.

2010 Debt Exchanges and Repurchases — Debt exchanges and repurchases completed year-to-date July 2010 resulted in acquisitions of $1.108 billion aggregate principal amount of outstanding EFH Corp. and TCEH debt in exchange for $561 million aggregate principal amount of EFH Corp. 10% Notes due 2020 and $235 million in cash. These transactions are described immediately below.

In a private exchange completed in March 2010, EFH Corp. issued an additional $34 million principal amount of EFH Corp. 10% Notes in exchange for $20 million principal amount of EFH Corp. Toggle Notes and $27 million principal amount of TCEH Toggle Notes resulting in a debt extinguishment gain of $14 million in the first quarter 2010 (reported as other income).

In private transactions completed in April through June 2010, EFH Corp. repurchased $96 million principal amount of EFH Corp. Toggle Notes, $19 million principal amount of EFH Corp. 10.875% Notes, $168 million principal amount of TCEH 10.25% Notes, $8 million principal amount of TCEH Toggle Notes and $20 million principal amount of TCEH’s initial term loans under its Senior Secured Facilities for $211 million in cash plus accrued interest, and also issued an additional $72 million principal amount of EFH Corp. 10% Notes in exchange for $85 million principal amount of EFH Corp. Toggle Notes and $17 million principal amount of TCEH Toggle Notes. These transactions resulted in debt extinguishment gains totaling $129 million in the second quarter 2010 (reported as other income).

In private transactions completed in July 2010, EFH Corp. repurchased $28 million principal amount of EFH Corp. Toggle Notes and $8 million principal amount of TCEH 10.25% Notes for $24 million in cash plus accrued interest, and also issued an additional $455 million principal amount of EFH Corp. 10% Notes in exchange for $549 million principal amount of EFH Corp. 5.55% Series P Senior Notes (EFH Corp. 5.55% Notes), $25 million principal amount of EFH Corp. Toggle Notes, $25 million principal amount of EFH Corp. 10.875% Notes and $13 million principal amount of TCEH 10.25% Notes. These transactions resulted in debt extinguishment gains totaling $93 million.

 

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In connection with the transactions involving the EFH Corp. 5.55% Notes in July 2010, the holder of a majority of the outstanding aggregate principal amount of the EFH Corp. 5.55% Notes gave its consent to certain amendments to the indenture that governs the EFH Corp. 5.55% Notes. As a result of the consent, EFH Corp. and The Bank of New York Mellon, as trustee under the indenture, amended and supplemented the indenture. The amendments to the indenture, among other things, modified or eliminated substantially all of the restrictive covenants contained in the indenture, modified or eliminated certain events of default, modified covenants regarding mergers and consolidations and modified or eliminated certain other provisions of the indenture, including the limitation on the incurrence of secured indebtedness.

The EFH Corp. Toggle and 10.875% Notes acquired in the transactions described above have been cancelled, and the TCEH notes and initial term loans under the TCEH Senior Secured Facilities acquired are held as an investment by EFH Corp.

July 2010 Debt Exchange Offers — In July 2010, Intermediate Holding and EFIH Finance, a wholly-owned subsidiary of Intermediate Holding, (collectively, the Offerors) commenced offers to exchange outstanding EFH Corp. Toggle Notes and EFH Corp. 10.875% Notes (collectively, the Exchange Notes) for up to $2.18 billion aggregate principal amount of new 10.000% senior secured notes due 2020 (new senior secured notes) to be issued by the Offerors and an aggregate of up to $500 million in cash, subject to certain conditions. The purpose of the exchange offers is to reduce the outstanding principal amount and extend the weighted average maturity of the long-term debt of EFH Corp. and its subsidiaries.

Concurrent with the exchange offers, EFH Corp. solicited consents from holders of the Exchange Notes to certain proposed amendments to the indenture that governs the Exchange Notes. The proposed amendments would eliminate substantially all of the restrictive covenants in the indenture, eliminate certain events of default, modify the covenant regarding mergers and consolidations, and modify or eliminate certain other provisions.

EFH Corp. has been advised by the exchange agent for the exchange offers that, as of 5:00 p.m., New York City time, on July 29, 2010, consents were delivered with respect to $4.47 billion aggregate principal amount of outstanding Exchange Notes, representing approximately 99.5% of the outstanding Exchange Notes. As a result, EFH Corp. received the requisite consents to adopt, and executed a supplemental indenture to effectuate, the proposed amendments. This supplemental indenture to the indenture related to the Exchange Notes will not become operative until the exchange offers are complete.

The consummation of the exchange offers is conditioned, among other things, on at least a majority of the outstanding aggregate principal amount of Exchange Notes being validly tendered (and not validly withdrawn) at or prior to midnight, New York City time, on August 12, 2010. Subject to applicable law, the Offerors have the right to amend any of the exchange offers or the consent solicitation at any time and for any reason and to terminate or withdraw any of the exchange offers and consent solicitation if any of the applicable conditions are not satisfied.

The Offerors filed a registration statement on Form S-4 (Registration Statement) relating to the exchange offers and the consent solicitation with the SEC in July 2010. The Registration Statement has not yet become effective, and the new senior secured notes may not be issued, nor may the exchange offers be completed, until such time as the Registration Statement has been declared effective by the SEC and is not subject to a stop order or any proceedings for that purpose. There is no assurance that the exchange offers will be completed or that they will be completed on the contemplated terms and conditions.

 

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TCEH Senior Secured Facilities — The applicable rate on borrowings under the TCEH Initial Term Loan Facility, the TCEH Delayed Draw Term Loan Facility, the TCEH Revolving Credit Facility and the TCEH Letter of Credit Facility as of June 30, 2010 is provided in the long-term debt table and in the discussion of short-term borrowings above and reflects LIBOR-based borrowings. These borrowings totaled $22.016 billion at June 30, 2010, excluding $20 million held by EFH Corp. as a result of debt repurchases.

In August 2009, the TCEH Senior Secured Facilities were amended to reduce the existing first lien capacity under the TCEH Senior Secured Facilities by $1.25 billion in exchange for the ability for TCEH to issue up to an additional $4 billion of secured notes or loans ranking junior to TCEH’s first lien obligations, provided that:

 

•

such notes or loans mature later than the latest maturity date of any of the initial term loans under the TCEH Senior Secured Facilities, and

 

•

any net cash proceeds from any such issuances are used (i) in exchange for, or to refinance, repay, retire, refund or replace indebtedness of TCEH or (ii) to acquire, directly or indirectly, all or substantially all of the property and assets or business of another person or to finance the purchase price, cost of design, acquisition, construction, repair, restoration, replacement, expansion, installation or improvement of certain fixed or capital assets.

In addition, the amended facilities permit TCEH to, among other things:

 

•

issue new secured notes or loans, which may include, in each case, indebtedness secured on a pari passu basis with the obligations under the TCEH Senior Secured Facilities, so long as, in each case, among other things, the net cash proceeds from any such issuance are used to prepay certain loans under the TCEH Senior Secured Facilities at par;

 

•

upon making an offer to all lenders within a particular series, agree with lenders of that series to extend the maturity of their term loans or extend or refinance their revolving credit commitments under the TCEH Senior Secured Facilities, and pay increased interest rates or otherwise modify the terms of their loans or revolving commitments in connection with such an extension, and

 

•

exclude from the financial maintenance covenant under the TCEH Senior Secured Facilities any new debt issued that ranks junior to TCEH’s first lien obligations under the TCEH Senior Secured Facilities.

Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are several and not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the TCEH Senior Secured Facilities.

The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis by EFC Holdings, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US restricted subsidiary of TCEH. The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Swap Transactions” below are secured by (a) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities and (b) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of such facility ($41 million quarterly), with the balance payable in October 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the actual principal outstanding under such facility as of December 2009 ($10 million quarterly), with the balance payable in October 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013. The TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility will mature in October 2014 and December 2012, respectively.

 

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TCEH Senior Notes — The indebtedness under TCEH’s 10.25% Notes bear interest that is payable semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum payable in cash. The indebtedness under the TCEH Toggle Notes bear interest that is payable semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum for PIK Interest. For any interest period until November 2012, the issuers may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once TCEH makes a PIK election, the election is valid for each succeeding interest payment period until TCEH revokes the election.

The TCEH 10.25% and Toggle Notes (collectively, the TCEH Senior Notes) had a total principal amount at June 30, 2010 of $6.696 billion and are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH’s direct parent, EFC Holdings (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities.

Before November 1, 2010, the issuers may redeem with the cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of the TCEH 10.25% and Toggle Notes from time to time at a redemption price of 110.250% and 110.500%, respectively, of their respective aggregate principal amount plus accrued and unpaid interest, if any. The issuers may also redeem the TCEH Senior Notes at any time prior to November 1, 2011 and 2012, respectively, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. The issuers may redeem the TCEH Senior Notes, in whole or in part, at any time on or after November 1, 2011 and 2012, respectively, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFC Holdings or TCEH, the issuers must offer to repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

EFH Corp. Senior Notes — The indebtedness under EFH Corp.’s 10.875% Notes bear interest that is payable semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.875% per annum payable in cash. The indebtedness under EFH Corp.’s Toggle Notes due November 1, 2017 bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 11.250% per annum for cash interest and at a fixed rate of 12.000% per annum for PIK Interest. For any interest period until November 1, 2012, EFH Corp. may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once EFH Corp. makes a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. revokes the election.

The EFH Corp. 10.875% and Toggle Notes (collectively, the EFH Corp. Senior Notes) had a total principal amount at June 30, 2010 of $4.570 billion and are fully and unconditionally guaranteed on a joint and several unsecured basis by EFC Holdings and Intermediate Holding.

Until November 1, 2010, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of its 10.875% and Toggle Notes from time to time at a redemption price of 110.875% and 111.250%, respectively, of their respective aggregate principal amounts, plus accrued and unpaid interest, if any. EFH Corp. may also redeem these notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. EFH Corp. may also redeem these notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFH Corp., EFH Corp. must offer to repurchase the EFH Corp. Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

 

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TCEH Interest Rate Swap Transactions — As of June 30, 2010, TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $16.30 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 8.3% on debt maturing from 2010 to 2014. No interest rate swap transactions have been entered into in 2010.

As of June 30, 2010, TCEH has entered into interest rate basis swap transactions pursuant to which payments at floating interest rates of three-month LIBOR on an aggregate of $16.30 billion principal amount of senior secured term loans of TCEH were exchanged for floating interest rates of one-month LIBOR plus spreads ranging from 0.0625% to 0.2055%. These transactions include swaps entered into in the six months ended June 30, 2010 related to an aggregate $2.55 billion principal amount of senior secured term loans of TCEH and reflect the expiration of swaps in the six months ended June 30, 2010 related to an aggregate $2.50 billion principal amount of senior secured term loans of TCEH.

The interest rate swap counterparties are proportionately secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. Changes in the fair value of such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $254 million and $361 million in net losses in the three and six months ended June 30, 2010 and $460 million and $665 million in net gains in the three and six months ended June 30, 2009. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.574 billion at June 30, 2010, of which $140 million (pre-tax) was reported in accumulated other comprehensive income.

See Note 11 for discussion of collateral investments related to certain of these interest rate swaps that expired in March 2010.

 

7.	COMMITMENTS AND CONTINGENCIES

Guarantees

We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Material guarantees are discussed below.

Disposed TXU Gas operations — In connection with the sale of TXU Gas in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, 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, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.

Residual value guarantees in operating leases — We are the lessee under various operating leases that guarantee the residual values of the leased assets. At June 30, 2010, the aggregate maximum amount of residual values guaranteed was $13 million with an estimated residual recovery of $13 million. These leased assets consist primarily of rail cars. The average life of the residual value guarantees under the lease portfolio is approximately six years.

See Note 6 above and Note 12 to Financial Statements in the 2009 Form 10-K for discussion of guarantees and security for certain of our indebtedness.

 

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Letters of Credit

At June 30, 2010, TCEH had outstanding letters of credit under its credit facilities totaling $706 million as follows:

 

•

$318 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;

 

•

$208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204 million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014);

 

•

$84 million to support TCEH’s REP’s financial requirements with the PUCT, and

 

•

$96 million for miscellaneous credit support requirements.

Litigation Related to Generation Facilities

In September 2007, an administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs asked the District Court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, filed pleas to the jurisdiction seeking dismissal of all but the administrative appeal. In May 2009, the District Court dismissed the claims that contest the merits of the TCEQ’s permitting decision, but declined to dismiss the claims that contest the process by which the TCEQ handled the permit application. Oak Grove Management Company LLC (a subsidiary of TCEH) has subsequently intervened in these proceedings and has filed its own pleas to the jurisdiction asking the court to dismiss the remaining collateral attack claims. In October 2009, one of the plaintiffs ended its legal challenge to the permit. In December 2009, the Attorney General and Oak Grove Management Company LLC filed pleadings asking the court to dismiss the administrative appeal challenging the permit for want of prosecution by the plaintiffs. In January 2010, the court denied that request and set the case for a hearing on the merits in June 2010. In March 2010, the remaining two non-parties to the administrative hearing before the TCEQ and SOAH filed a notice of non-suit, thus ending their legal challenge. Therefore, only one plaintiff remains in the case. After conducting the hearing in June 2010, the court in July issued its order rejecting the remaining plaintiff’s claims and upholding the TCEQ’s issuance of the permit. We believe the Oak Grove air permit granted by the TCEQ was issued in accordance with applicable law. There can be no assurance that the outcome of these matters will not adversely impact the Oak Grove project.

 

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In July 2008, Alcoa Inc. filed a lawsuit in the State District Court of Milam County, Texas against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of its subsidiaries, Texas Holdings and Texas Holdings’ general partner as parties to the suit. The lawsuit made various claims concerning the operation of the Sandow Unit 4 generation facility and the related Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud, tortious interference, civil conspiracy and conversion. The plaintiff requested money damages of no less than $500 million, declaratory judgment, rescission and other forms of equitable relief. In May 2010, the trial court granted a summary judgment dismissing substantially all of Alcoa’s claims other than its breach of contract claims against Luminant Generation and Luminant Mining. On the breach of contract claims against Luminant Generation relating to the Sandow Unit 4 generation facility, a jury rendered a verdict in Luminant Generation’s favor in June 2010. The jury awarded no damages to Alcoa and awarded $10 million in damages to Luminant Generation. In June 2010, the judge presiding in the case ruled in Luminant Mining’s favor on the claims against it, awarding no damages to Alcoa and awarding nearly $2 million in damages to Luminant Mining. As a result, the lawsuit was concluded favorably to Luminant, subject to any appeals. We cannot predict whether Alcoa will file an appeal with respect to the jury’s verdict or the court’s ruling. If such appeals are filed, we intend to vigorously defend the appeals.

In February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. This notice is similar to the notice that Luminant received in July 2008 with respect to its Martin Lake generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.

Regulatory Investigations and Reviews

In June 2008, the EPA issued a request for information to TCEH under EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.

Sandow Power Company LLC (Sandow Power), a subsidiary of TCEH, is a party to a federal consent decree (the Consent Decree) with, among others, the US Department of Justice (DOJ) and certain private plaintiffs related to Sandow Power’s Sandow Unit 5 lignite-fueled generation facility. Between December 3, 2009 and March 31, 2010, Sandow Power submitted several force majeure claims to the DOJ regarding deviations from emissions limits at Sandow Unit 5 resulting from force majeure events, as that term is defined in the Consent Decree. In June 2010, Sandow Power and the DOJ agreed to extend, to August 31, 2010, the DOJ’s deadline to respond to these force majeure claims. We anticipate that this extension period will be used to pursue a negotiated resolution of the force majeure claims. We believe that a negotiated resolution of the force majeure claims between Sandow Power, the DOJ and the private plaintiffs, if reached, would likely involve a payment that is immaterial to the company, but in excess of the $100,000 disclosure threshold applicable to such matters.

Other Proceedings

In addition to the above, we 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 our financial position, results of operations or cash flows.

 

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8.

EQUITY

Dividend Restrictions

The indentures governing the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes include covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our capital stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under these indentures and/or after such distributions, on a pro forma basis, after giving effect to such payment, EFH Corp.’s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, “consolidated leverage ratio” is defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. In addition, the indenture governing the EFIH 9.75% Notes generally restricts Intermediate Holding from making any cash distribution to EFH Corp. for the ultimate purpose of making a cash distribution on our common stock unless at the time, and after giving effect to such distribution, Intermediate Holding’s consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indenture governing the EFIH 9.75% Notes, the term “consolidated leverage ratio” is defined as the ratio of Intermediate Holding’s consolidated total indebtedness (as defined in the indenture) to Intermediate Holding’s Adjusted EBITDA on a consolidated basis.

The TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companies for the ultimate purpose of making a cash distribution on our common stock unless at the time, and after giving effect to such distribution, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. In addition, the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes generally restrict TCEH’s ability to make distributions or loans to any of its parent companies, EFC Holdings and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes. Those agreements generally permit TCEH to make unlimited distributions or loans to its parent companies for corporate overhead costs, SG&A expenses, taxes and principal and interest payments. In addition, those agreements contain certain investment and dividend baskets that would allow TCEH to make additional distributions and/or loans to its parent companies up to the amount of such baskets. At June 30, 2010, EFH Corp. demand notes payable to TCEH totaled $1.631 billion, of which $668 million is related to principal and interest payments. Such principal and interest amounts are guaranteed by EFC Holdings and Intermediate Holding on a pari passu basis with their guarantees of the EFH Corp. Senior Notes; the remaining balance of the demand notes is not guaranteed.

In addition, under applicable law, we would be prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent.

EFH Corp. did not declare or pay any cash dividends in 2010 or 2009.

Distributions from Oncor — Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s net income determined in accordance with GAAP, subject to certain defined adjustments. Distributions are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.

Noncontrolling Interests

Of the noncontrolling interests balance at December 31, 2009 in the table below, $1.363 billion related to Oncor. See Note 1 for discussion of the deconsolidation of Oncor in 2010. As of December 31, 2009 (and June 30, 2010), Oncor’s ownership was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission.

 

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In connection with the filing of a combined operating license application with the NRC for two new nuclear generation units, in January 2009, TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, CPNPC, to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture agreement, a subsidiary of TCEH owns an 88% interest in the venture and a subsidiary of MHI owns a 12% interest. This joint venture is a variable interest entity, and a subsidiary of TCEH is considered the primary beneficiary (see Note 3).

Equity

The following table presents the changes to equity during the six months ended June 30, 2010.

 

		EFH Corp. Shareholders’ Equity
		Common Stock (a)			Additional Paid-in Capital				Retained Earnings (Deficit)				Accumulated Other Comprehensive Income (Loss)				Noncontrolling Interests				Total Equity
Balance at December 31, 2009		$	2		$	7,914			$	(10,854	)		$	(309	)		$	1,411			$	(1,836	)
Net loss			—			—				(71	)			—				—				(71	)
Effects of EFH Corp. stock-based incentive compensation plans			—			14				—				—				—				14
Net effects of cash flow hedges			—			—				—				36				—				36
Effects of deconsolidation of Oncor Holdings			—			—				—				—				(1,363	)			(1,363	)
Investment by noncontrolling interests			—			—				—				—				14				14
Stock repurchases			—			(1	)			—				—				—				(1	)
Other			—			—				—				—				(1	)			(1	)
Balance at June 30, 2010		$	2		$	7,927			$	(10,925	)		$	(273	)		$	61			$	(3,208	)

 

(a)	Authorized shares totaled 2,000,000,000 as of June 30, 2010. Outstanding shares totaled 1,668,680,542 and 1,668,065,133 as of June 30, 2010 and December 31, 2009, respectively.

 

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9.	FAIR VALUE MEASUREMENTS

Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.

We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:

 

•

Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures and swaps transacted through clearing brokers for which prices are actively quoted.

 

•

Level 2 valuations use inputs, in the absence of actively quoted market prices, that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available.

 

•

Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means.

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.

In utilizing broker quotes, we attempt to obtain multiple quotes from brokers that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume trends and various other factors. In addition, for valuation of interest rate swaps, we use a combination of dealer provided market valuations (generally non-binding) and Bloomberg valuations based on month-end interest rate curves and standard rate swap valuation models.

 

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Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.

With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

At June 30, 2010, assets and liabilities measured at fair value on a recurring basis consisted of the following:

 

		Level 1			Level 2			Level 3 (a)			Reclassification (b)			Total
Assets:
Commodity contracts		$	992		$	3,447		$	425		$	17		$	4,881
Interest rate swaps			—			108			—			—			108
Nuclear decommissioning trust – equity securities (c)			149			98			—			—			247
Nuclear decommissioning trust – debt securities (c)			—			222			—			—			222
Total assets		$	1,141		$	3,875		$	425		$	17		$	5,458
Liabilities:
Commodity contracts		$	1,150		$	850		$	256		$	17		$	2,273
Interest rate swaps			—			1,711			—			—			1,711
Total liabilities		$	1,150		$	2,561		$	256		$	17		$	3,984

 

(a)	Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including a long-term wind generation purchase contract and certain natural gas positions (collars) in the long-term hedging program.

(b)	Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

(c)	The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 16.

 

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At December 31, 2009, assets and liabilities measured at fair value on a recurring basis consisted of the following:

 

		Level 1			Level 2			Level 3 (a)			Reclassification (b)			Total
Assets:
Commodity contracts		$	918		$	2,588		$	350		$	4		$	3,860
Interest rate swaps			—			64			—			—			64
Nuclear decommissioning trust – equity securities (c)			154			105			—			—			259
Nuclear decommissioning trust – debt securities (c)			—			216			—			—			216
Total assets		$	1,072		$	2,973		$	350		$	4		$	4,399
Liabilities:
Commodity contracts		$	1,077		$	796		$	269		$	4		$	2,146
Interest rate swaps			—			1,306			—			—			1,306
Total liabilities		$	1,077		$	2,102		$	269		$	4		$	3,452

 

(a)	Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including a long-term wind generation purchase contract and certain natural gas positions (collars) in the long-term hedging program.

(b)	Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

(c)	The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 16.

Commodity contracts consist primarily of natural gas, electricity, fuel oil and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales. See Note 11 for further discussion regarding the company’s use of derivative instruments.

Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 6 for discussion of interest rate swaps.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

There were no significant transfers between the levels of the fair value hierarchy for the three and six months ended June 30, 2010.

 

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The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts) for the three and six months ended June 30, 2010 and 2009:

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Balance at beginning of period		$	156			$	(78	)		$	81			$	(72	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)			14				(1	)			65				16
Included in other comprehensive income (loss)			—				1				—				(25	)
Purchases, sales, issuances and settlements (net) (b)			13				7				31				(10	)
Transfers into Level 3 (c)			—				—				—				—
Transfers out of Level 3 (c)			(14	)			(1	)			(8	)			19
Balance at end of period		$	169			$	(72	)		$	169			$	(72	)
Net change in unrealized gains (losses) included in net income relating to instruments held at end of period (d)		$	21			$	2			$	75			$	16

 

(a)	Substantially all changes in values of commodity contracts are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

(b)	Settlements represent reversals of unrealized mark-to-market valuations of these positions previously recognized in net income. Purchases and issuances reflect option premiums paid or received.

(c)

Includes transfers due to changes in the observability of significant inputs. For 2010, in accordance with new accounting guidance issued by the FASB in January 2010, transfers in and out occur at the end of each quarter, which is when the assessments are performed. Prior period transfers in were assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter.

(d)	Includes unrealized gains and losses of instruments held at the end of the period.

 

10.	FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments at June 30, 2010 and December 31, 2009 were as follows:

 

		June 30, 2010						December 31, 2009
		Carrying Amount			Fair Value (a)			Carrying Amount			Fair Value (a)
On balance sheet liabilities:
Long-term debt (including current maturities) (b):
TCEH, EFH Corp., and other		$	36,931		$	26,740		$	36,600		$	29,115
Oncor (c)		$	—		$	—		$	5,104		$	5,644
Total		$	36,931		$	26,740		$	41,704		$	34,759
Off balance sheet liabilities:
Financial guarantees		$	—		$	5		$	—		$	6

 

(a)	Fair value determined in accordance with accounting standards related to the determination of fair value.

(b)	Excludes capital leases.

(c)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010.

See Notes 9 and 11 for discussion of accounting for financial instruments that are derivatives.

 

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11.	COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We enter into physical and financial derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a long-term commodity hedging program and the hedging of interest costs on our long-term debt. See Note 9 for a discussion of the fair value of all derivatives.

Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity is highly correlated to the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas through 2014. These transactions are intended to hedge a majority of electricity price exposure related to expected baseload generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 6 for additional information about these and other interest rate swap agreements.

Other Commodity Hedging and Trading Activity — In addition to the long-term hedging program, TCEH enters into derivatives, including electricity, natural gas, fuel oil and coal instruments, generally for shorter-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets.

Financial Statement Effects of Derivatives

Substantially all commodity and other derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of commodity and other derivative contractual assets and liabilities as reported in the balance sheets at June 30, 2010 and December 31, 2009:

 

		June 30, 2010
		Derivative assets							Derivative liabilities
		Commodity contracts				Interest rate swaps			Commodity contracts				Interest rate swaps				Total
Current assets		$	2,740			$	108		$	9			$	—			$	2,857
Noncurrent assets			2,129				—			3				—				2,132
Current liabilities			(3	)			—			(1,908	)			(737	)			(2,648	)
Noncurrent liabilities			(2	)			—			(360	)			(974	)			(1,336	)
Net assets (liabilities)		$	4,864			$	108		$	(2,256	)		$	(1,711	)		$	1,005

 

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		December 31, 2009
		Derivative assets						Derivative liabilities
		Commodity contracts			Interest rate swaps			Commodity contracts				Interest rate swaps				Total
Current assets		$	2,327		$	60		$	4			$	—			$	2,391
Noncurrent assets			1,529			4			—				—				1,533
Current liabilities			—			—			(1,705	)			(687	)			(2,392	)
Noncurrent liabilities			—			—			(441	)			(619	)			(1,060	)
Net assets (liabilities)		$	3,856		$	64		$	(2,142	)		$	(1,306	)		$	472

As of June 30, 2010 and December 31, 2009, there were no derivative positions accounted for as cash flow or fair value hedges.

Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $367 million and $358 million in net liabilities at June 30, 2010 and December 31, 2009, respectively, which do not include the collateral investments related to certain interest rate swaps and commodity positions discussed immediately below. Reported amounts as presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

In 2009, we entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which we elected to enter into as a cash management measure, as of December 31, 2009, EFH Corp. (parent) had posted $400 million in cash and TCEH had posted $65 million in letters of credit to the counterparties, with the outstanding balance of such collateral earning interest. TCEH had also entered into commodity hedging transactions with one of these counterparties, and under an arrangement effective August 2009, both the interest rate swaps and certain of the commodity hedging transactions with the counterparty are under the same derivative agreement, which continues to be secured by a first-lien interest in the assets of TCEH. In accordance with the agreements, the counterparties returned the collateral, along with accrued interest, on March 31, 2010. As of December 31, 2009, the cash collateral was recorded as an investment and was presented in the balance sheet (including accrued interest) as a separate line item under current assets.

The following table presents the pre-tax effect of derivatives not under hedge accounting on net income, including realized and unrealized effects:

 

		Three Months Ended June 30,								Six Months Ended June 30,
Derivative (Income statement presentation)		2010				2009				2010				2009
Commodity contracts (Net gain (loss) from commodity hedging and trading activities)		$	73			$	(265	)		$	1,276			$	890
Interest rate swaps (Interest expense and related charges)			(422	)			288				(698	)			333
Net gain (loss)		$	(349	)		$	23			$	578			$	1,223

 

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The following tables present the pre-tax effect of derivative instruments previously accounted for as cash flow hedges on net income and other comprehensive income (OCI) for the three and six months ended June 30, 2010 and 2009:

 

		Amount of gain  (loss) recognized in OCI (effective portion)
Derivative		Three  Months Ended June 30, 2010			Six  Months Ended June 30, 2010			Income statement presentation of loss reclassified from accumulated OCI into income (effective portion)		Three  Months Ended June 30, 2010				Six  Months Ended June 30, 2010
Interest rate swaps		$	—		$	—		Interest expense and related charges		$	(24	)		$	(53	)
Commodity contracts			—			—		Fuel, purchased power costs and delivery fees			—				—
								Operating revenues			(1	)			(1	)
Total		$	—		$	—				$	(25	)		$	(54	)

 

		Amount of gain (loss) recognized in  OCI (effective portion)							Income statement presentation of loss reclassified from accumulated OCI into income (effective portion)
Derivative		Three  Months Ended June 30, 2009			Six  Months Ended June 30, 2009						Three  Months Ended June 30, 2009				Six  Months Ended June 30, 2009
Interest rate swaps		$	—		$	—			Interest expense and related charges		$	(44	)		$	(84	)
Commodity contracts			1			(25	)		Fuel, purchased power costs and delivery fees			(4	)			(4	)
									Operating revenues			(1	)			(2	)
Total		$	1		$	(25	)				$	(49	)		$	(90	)

There were no transactions designated as cash flow hedges during the three and six months ended June 30, 2010. There were no ineffectiveness net gains or losses related to transactions designated as cash flow hedges in the three and six months ended June 30, 2009.

Accumulated other comprehensive income related to cash flow hedges at June 30, 2010 and December 31, 2009 totaled $92 million and $128 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. We expect that $35 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of June 30, 2010 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

 

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Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at June 30, 2010 and December 31, 2009:

 

		June 30, 2010			December 31, 2009
Derivative type		Notional Volume						Unit of Measure
Interest rate swaps:
Floating/fixed		$	18,000		$	18,000		Million US dollars
Basis		$	16,300		$	16,250		Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)			2,946			3,402		Million MMBtu
Locational basis swaps			996			1,010		Million MMBtu
All other			1,431			1,433		Million MMBtu
Electricity			178,873			198,230		GWh
Coal			5			6		Million tons
Fuel oil			130			161		Million gallons

 

(a)

Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, was 1.4 billion MMBtu and 1.6 billion MMBtu as of June 30, 2010 and December 31, 2009, respectively.

Credit Risk-Related Contingent Features of Derivatives

The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of those agreements require the posting of collateral if our credit rating is downgraded by one or more of the credit rating agencies; however, due to our below investment grade credit ratings, substantially all of such collateral posting requirements are already effective.

As of June 30, 2010 and December 31, 2009, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $619 million and $687 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $109 million and $152 million as of June 30, 2010 and December 31, 2009, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of June 30, 2010 and December 31, 2009, the remaining related liquidity requirement would have totaled $23 million and $20 million, respectively, after reduction for net accounts receivable and derivative assets under netting arrangements.

In addition, certain derivative agreements that are collateralized primarily with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of June 30, 2010 and December 31, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $2.032 billion and $1.482 billion, respectively, (before consideration of the amount of assets under the liens). There were no cash collateral and letters of credit posted with these counterparties to reduce the liquidity exposure as of June 30, 2010. The liquidity exposure associated with these liabilities was reduced by cash collateral and letters of credit posted with counterparties totaling $489 million as of December 31, 2009. If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered as of June 30, 2010 and December 31, 2009, the remaining related liquidity requirement would have totaled $1.102 billion and $480 million, respectively, after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 12 to Financial Statements in the 2009 Form 10-K for a description of other obligations that are supported by asset liens.

 

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As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.651 billion and $2.169 billion at June 30, 2010 and December 31, 2009, respectively. This amount is before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.

Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.

Concentrations of Credit Risk Related to Derivatives

TCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. As of June 30, 2010, total credit risk exposure to all counterparties related to derivative contracts totaled $5.1 billion (including associated accounts receivable). The net exposure to those counterparties totaled $1.9 billion after taking into effect master netting arrangements, setoff provisions and collateral. The net exposure, assuming setoff provisions in the event of default across all EFH Corp. consolidated subsidiaries, totaled $1.4 billion as of June 30, 2010. As of June 30, 2010, the credit risk exposure to the banking and financial sector represented 93% of the total credit risk exposure, a significant amount of which is related to the long-term hedging program. As of June 30, 2010, the largest net exposure to a single counterparty totaled approximately $750 million. Exposure to the banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because substantially all of this exposure is with counterparties with credit ratings of “A” or better. However, this concentration increases the risk that a default by any of these counterparties would have a material adverse effect on our financial condition and results of operations.

The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies 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. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.

 

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12.	PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) COSTS

Net pension and OPEB costs for the three and six months ended June 30, 2010 and 2009 are comprised of the following:

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Components of net pension costs:
Service cost		$	10			$	9			$	21			$	18
Interest cost			39				39				78				78
Expected return on assets			(39	)			(41	)			(79	)			(83	)
Amortization of prior service cost			—				—				—				—
Amortization of net loss			13				2				26				4
Net pension costs			23				9				46				17
Components of net OPEB costs:
Service cost			3				3				6				6
Interest cost			15				15				30				30
Expected return on assets			(3	)			(3	)			(6	)			(6	)
Amortization of prior service cost			—				—				—				—
Amortization of net loss			5				3				10				6
Net OPEB costs			20				18				40				36
Total net pension and OPEB costs			43				27				86				53
Less amounts expensed by Oncor			(9	)			—				(18	)			—
Less amounts deferred principally as a regulatory asset or property by Oncor			(21	)			(17	)			(42	)			(33	)
Amount recognized as expense by EFH Corp. and consolidated subsidiaries		$	13			$	10			$	26			$	20

The discount rate reflected in net pension and OPEB costs in 2010 is 5.90%. The expected rates of return on pension and OPEB plan assets reflected in the 2010 cost amounts are 8.0% and 7.6%, respectively.

We made cash contributions related to our pension and OPEB plans totaling $14 million and $12 million, respectively, in the first half of 2010, including $22 million contributed by Oncor. We expect to make additional contributions of $31 million and $12 million, respectively, in the remainder of 2010, including $37 million expected to be contributed by Oncor.

 

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13.	EFFECT OF HEALTH CARE LEGISLATION

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act enacted in March 2010 reduces, effective in 2013, the amount of OPEB costs deductible for federal income tax purposes by the amount of the Medicare Part D subsidy we receive. Under income tax accounting rules, deferred tax assets related to accrued OPEB liabilities must be reduced immediately for the future effect of the legislation. Accordingly, in the three months ended March 31, 2010, EFH Corp.’s and Oncor’s deferred tax assets were reduced by $50 million. Of this amount, $8 million was recorded as a charge to income tax expense and $42 million was recorded as a regulatory asset by Oncor (before gross-up for liability in lieu of deferred income taxes) as the additional income taxes are expected to be recoverable in Oncor’s future rates.

 

14.	RELATED PARTY TRANSACTIONS

The following represent the significant related-party transactions of EFH Corp.:

 

•

We incur an annual management fee under the terms of a management agreement with the Sponsor Group for which we accrued $9 million for both the three months ended June 30, 2010 and 2009, and $18 million for both the six months ended June 30, 2010 and 2009. The fee is reported as SG&A expense.

 

•

In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of GS Capital Partners and Kohlberg Kravis Roberts & Co. L.P. (a member of the Sponsor Group) have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business.

 

•

Goldman, Sachs & Co. (Goldman) acted as an initial purchaser in the issuance of $500 million principal amount of EFH Corp. 10% Notes in January 2010 as discussed in Note 6. Goldman received fees totaling $3 million for this transaction. Goldman is also acting as a dealer manager and solicitation agent in the ongoing debt exchange offers launched in July 2010 as discussed in Note 6. For its services in connection with the exchange offers and related consent solicitation, we have agreed to pay Goldman an exchange agent fee of up to $5.5 million and an incentive fee of up to $3 million that will be determined at the end of the exchange offers depending on the results of the exchange.

 

•

Affiliates of Goldman Sachs & Co. are parties to certain commodity and interest rate hedging transactions with us in the normal course of business.

 

•

Affiliates of the Sponsor Group may sell or acquire debt or debt securities issued by us in open market transactions or through loan syndications.

 

•

TCEH’s retail operations incur electricity delivery fees charged by Oncor, which totaled $257 million and $521 million for the three and six months ended June 30, 2010, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheet at June 30, 2010 reflects amounts due currently to Oncor of $177 million (included in net payables due to unconsolidated subsidiary), primarily related to these electricity delivery fees.

 

•

Oncor’s bankruptcy-remote financing subsidiary has issued securitization bonds to recover generation-related regulatory assets through a transition surcharge to its customers. Oncor’s incremental income taxes related to the transition surcharges it collects are being reimbursed by TCEH. Therefore, the balance sheet reflects a noninterest bearing note payable to Oncor of $237 million ($38 million current portion included in net payables due to unconsolidated subsidiary) at June 30, 2010.

 

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•

TCEH reimburses Oncor for interest expense on Oncor’s bankruptcy-remote financing subsidiary’s securitization bonds. This interest expense totaled $9 million and $19 million for the three and six months ended June 30, 2010, respectively.

 

•

A subsidiary of EFH Corp. charges Oncor for financial and other administrative services at cost, which totaled $10 million and $17 million for the three and six months ended June 30, 2010, respectively.

 

•

Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in other investments on the balance sheet, is funded by a delivery fee surcharge billed to REPs by Oncor and remitted to TCEH, with the intent that the trust fund assets will be sufficient to fund the decommissioning liability, reported in noncurrent liabilities on the balance sheet. Income and expenses associated with the trust fund and the decommissioning liability incurred by us are offset by a net change in the intercompany receivable/payable with Oncor, which in turn results in a change in Oncor’s net regulatory asset/liability. At June 30, 2010, the excess of the trust fund balance over the decommissioning liability resulted in a payable to Oncor totaling $148 million included in noncurrent payables to unconsolidated subsidiary in the balance sheet.

The intercompany receivable/payable with Oncor has changed from a receivable of $85 million on January 1, 2010 to a payable of $148 million on June 30, 2010 due to a new decommissioning cost estimate completed in the second quarter 2010 that resulted in a decline of the liability. The new cost estimate was completed in accordance with regulatory requirements to perform a cost estimate every five years. The lower estimated liability was driven by lower cost escalation assumptions in the new estimate. (Also see Note 16 under “Asset Retirement Obligations.”)

 

•

We file a consolidated federal income tax return; however, Oncor Holdings’ federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., are recorded as if Oncor Holdings files its own income tax return. At June 30, 2010, the amount due to Oncor Holdings totaled $3 million and is included in net payables due to unconsolidated subsidiary.

 

•

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 TCEH’s credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, as of June 30, 2010, TCEH had posted a letter of credit in the amount of $16 million for the benefit of Oncor.

 

•

EFH Corp. and Oncor are jointly and severally liable for the funding of the EFH Corp. pension plan and a portion of the OPEB plan obligations. EFH Corp. is liable for the majority of the OPEB plan obligations. Oncor has contractually agreed to reimburse EFH Corp. with respect to certain pension plan and OPEB liabilities. Accordingly, at June 30, 2010, the balance sheet of EFH Corp. reflects such unfunded liabilities and a corresponding receivable from Oncor in the amount of $1.270 billion, classified as noncurrent, which represents the portion of the obligations recoverable by Oncor under regulatory rate-setting provisions and reported by Oncor in its balance sheet.

 

•

Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor if two or more rating agencies downgrade Oncor’s credit ratings below investment grade.

 

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15.	SEGMENT INFORMATION

Our 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.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, all largely in Texas. These activities are conducted by TCEH.

The Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary. See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings and, accordingly, the Regulated Delivery segment, effective as of January 1, 2010.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses and interest on EFH Corp. (parent entity), Intermediate Holding and EFC Holdings debt.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 above and in Note 1 in the 2009 Form 10-K. We evaluate performance based on income from continuing operations. We account 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,
		2010				2009				2010				2009
Operating revenues:
Competitive Electric		$	1,993			$	1,945			$	3,992			$	3,711
Regulated Delivery			—				653				—				1,266
Corporate and Other			—				6				—				13
Eliminations							(262	)			—				(509	)
Consolidated		$	1,993			$	2,342			$	3,992			$	4,481
Affiliated revenues included in operating revenues:
Competitive Electric		$	—			$	1			$	—			$	3
Regulated Delivery			—				257				—				496
Corporate and Other			—				4				—				10
Eliminations			—				(262	)			—				(509	)
Consolidated		$	—			$	—			$	—			$	—
Equity in earnings of unconsolidated subsidiaries (net of tax):
Regulated Delivery		$	59			$	—			$	122			$	—
Net income (loss):
Competitive Electric		$	(427	)		$	(78	)		$	5			$	479
Regulated Delivery			59				82				122				140
Corporate and Other			(58	)			(143	)			(198	)			(304	)
Consolidated		$	(426	)		$	(139	)		$	(71	)		$	315

 

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16.	SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Operating revenues
Regulated		$	—			$	653			$	—			$	1,266
Unregulated			1,993				1,951				3,992				3,724
Intercompany sales eliminations – regulated			—				(257	)			—				(496	)
Intercompany sales eliminations – unregulated			—				(5	)			—				(13	)
Total operating revenues			1,993				2,342				3,992				4,481
Fuel, purchased power and delivery fees – unregulated (a)			(1,074	)			(700	)			(2,121	)			(1,301	)
Net gain (loss) from commodity hedging and trading activities – unregulated			67				(248	)			1,280				880
Operating costs – regulated			—				(221	)			—				(441	)
Operating costs – unregulated			(229	)			(174	)			(426	)			(342	)
Depreciation and amortization – regulated			—				(132	)			—				(258	)
Depreciation and amortization – unregulated			(350	)			(291	)			(692	)			(572	)
Selling, general and administrative expenses – regulated			—				(44	)			—				(88	)
Selling, general and administrative expenses – unregulated			(185	)			(226	)			(373	)			(428	)
Franchise and revenue-based taxes – regulated			—				(58	)			—				(118	)
Franchise and revenue-based taxes – unregulated			(26	)			(21	)			(49	)			(47	)
Impairment of goodwill			—				—				—				(90	)
Other income			211				13				244				26
Other deductions			(7	)			(7	)			(18	)			(18	)
Interest income			—				11				9				12
Interest expense and other charges			(1,122	)			(431	)			(2,074	)			(1,096	)
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries		$	(722	)		$	(187	)		$	(228	)		$	600

 

 

(a)

Includes unregulated cost of fuel consumed of $325 million and $298 million for the three months ended June 30, 2010 and 2009, respectively, and $680 million and $582 million for the six months ended June 30, 2010 and 2009, respectively. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

 

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Other Income and Deductions

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2010			2009			2010			2009
Other income:
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting		$	—		$	10		$	—		$	20
Debt extinguishment gain (Note 6)			129			—			143			—
Gain on sale of interest in natural gas gathering pipeline business (a)			30			—			37			—
Gain on sale of land/water rights assets resulting from purchase accounting			44			—			44			—
Sales tax refund			—			—			5			—
Mineral rights royalty income			—			1			1			2
Other			8			2			14			4
Total other income		$	211		$	13		$	244		$	26
Other deductions:
Net charges related to cancelled development of generation facilities		$	1		$	1		$	2		$	2
Severance charges			—			1			2			7
Ongoing pension and OPEB expense related to discontinued businesses			2			—			5			—
Other			4			5			9			9
Total other deductions		$	7		$	7		$	18		$	18

 

 

(a)

The six months ended June 30, 2010 amount includes adjustments totaling $12 million associated with the sale of a controlling interest in 2009 that arose as a result of completion of fair value determination related to the respective parties’ investment balance and a gain totaling $25 million related to the sale of remaining interests in June 2010.

Interest Expense and Related Charges

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)		$	808			$	873			$	1,602			$	1,745
Unrealized mark-to-market net (gain) loss on interest rate swaps			254				(460	)			361				(665	)
Amortization of interest rate swap losses at dedesignation of hedge accounting			24				44				53				84
Amortization of fair value debt discounts resulting from purchase accounting			19				20				38				39
Amortization of debt issuance costs and discounts			33				35				67				69
Capitalized interest			(16	)			(81	)			(47	)			(176	)
Total interest expense and related charges		$	1,122			$	431			$	2,074			$	1,096

Restricted Cash

 

		At June 30, 2010						At December 31, 2009
		Current Assets			Noncurrent Assets			Current Assets			Noncurrent Assets
Amounts related to TCEH’s Letter of Credit Facility (See Note 6)		$	—		$	1,135		$	—		$	1,135
Amounts related to margin deposits held			6			—			1			—
Amounts related to securitization (transition) bonds			—			—			47			14
Total restricted cash		$	6		$	1,135		$	48		$	1,149

 

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Inventories by Major Category

 

		June 30, 2010			December 31, 2009
Materials and supplies (a)		$	162		$	248
Fuel stock			205			204
Natural gas in storage			34			33
Total inventories		$	401		$	485

 

 

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010.

Other Investments

 

		June 30, 2010			December 31, 2009
Nuclear decommissioning trust		$	469		$	475
Assets related to employee benefit plans, including employee savings programs, net of distributions (a)			115			184
Land			41			43
Miscellaneous other			3			4
Total investments		$	628		$	706

 

 

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010.

Nuclear Decommissioning Trust — Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor’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 Oncor’s regulatory asset/liability. A summary of investments in the fund follows:

 

		June 30, 2010
		Cost (a)			Unrealized gain			Unrealized loss				Fair market value
Debt securities (b)		$	216		$	8		$	(2	)		$	222
Equity securities (c)			203			67			(23	)			247
Total		$	419		$	75		$	(25	)		$	469
		December 31, 2009
		Cost (a)			Unrealized gain			Unrealized loss				Fair market value
Debt securities (b)		$	211		$	8		$	(3	)		$	216
Equity securities (c)			195			83			(19	)			259
Total		$	406		$	91		$	(22	)		$	475

 

 

(a)	Includes realized gains and losses of securities sold.

(b)

The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.41% and 4.44% and an average maturity of 7.9 years and 7.8 years at June 30, 2010 and December 31, 2009, respectively.

(c)	The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.

Debt securities held at June 30, 2010 mature as follows: $81 million in one to five years, $37 million in five to ten years and $104 million after ten years.

 

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Property, Plant and Equipment

As of June 30, 2010 and December 31, 2009, property, plant and equipment of $20.8 billion and $30.1 billion, respectively, is stated net of accumulated depreciation and amortization of $3.5 billion and $7.1 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’s rates.

The following table summarizes the changes to the asset retirement liability, reported in other current liabilities and other noncurrent liabilities and deferred credits in the balance sheet, during the six months ended June 30, 2010:

 

Asset retirement liability at January 1, 2010		$	948
Additions:
Accretion			36
Reductions:
Payments, essentially all mining reclamation			(20	)
Adjustment for new cost estimate (a)			(498	)
Asset retirement liability at June 30, 2010			466
Less amounts due currently			(42	)
Noncurrent asset retirement liability at June 30, 2010		$	424

 

(a)

Essentially all of the adjustment relates to the nuclear decommissioning liability, which resulted from a new cost estimate completed in the second quarter 2010. In accordance with regulatory requirements, a new cost estimate is completed every five years. A decline in the liability was driven by lower cost escalation assumptions in the new estimate. The reduction in the liability was offset in part by a reduction in the carrying value of the nuclear facility with the balance offset by an increase in the noncurrent liability to Oncor, which in turn resulted in a regulatory liability on Oncor’s balance sheet. (Also see Note 14.)

 

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Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:

 

		June 30, 2010			December 31, 2009
Uncertain tax positions (including accrued interest)		$	1,958		$	1,999
Retirement plan and other employee benefits			1,658			1,711
Asset retirement obligations			424			948
Unfavorable purchase and sales contracts			687			700
Liabilities related to subsidiary tax sharing agreement (a)			—			321
Other			44			87
Total other noncurrent liabilities and deferred credits		$	4,771		$	5,766

 

 

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010.

No recent events have occurred that would cause us to materially adjust the total amount of liabilities recorded related to uncertain tax positions, although the amount could change materially within the next 12 months if sufficient progress is made on matters in appeals with the IRS (see Note 8 to Financial Statements in the 2009 Form 10-K).

Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $6 million and $7 million in the three months ended June 30, 2010 and 2009, respectively and $13 and $14 million in the six months ended June 30, 2010 and 2009, respectively. Favorable purchase and sales contracts are recorded as intangible assets (see Note 4).

The estimated amortization of unfavorable purchase and sales contracts for each of the five fiscal years from December 31, 2009 is as follows:

 

Year		Amount
2010		$	27
2011			27
2012			27
2013			26
2014			25

Supplemental Cash Flow Information

 

		Six Months Ended June 30,
		2010				2009
Cash payments (receipts) related to:
Interest paid (a)		$	1,289			$	1,513
Capitalized interest			(47	)			(176	)
Interest paid (net of capitalized interest) (a)			1,242				1,337
Income taxes			52				(45	)
Noncash investing and financing activities:
Noncash construction expenditures (b)			51				175
Capital leases			9				15

 

 

(a)	Net of interest received on interest rate swaps.

(b)	Represents end-of-period accruals.

 

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17.	SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

In 2007, EFH Corp. issued $2.0 billion EFH Corp. 10.875% Notes and $2.5 billion EFH Corp. Toggle Notes (collectively, the EFH Corp. Senior Notes). In May 2009, November 2009 and May 2010, EFH Corp. issued an additional $150 million, $159 million and $162 million, respectively, of the EFH Corp. Toggle Notes in payment of accrued interest. In November 2009, EFH Corp. issued $115 million EFH Corp. 9.75% Notes in exchange for certain outstanding debt securities. In January 2010, EFH Corp. issued $500 million EFH Corp. 10% Notes (collectively with the EFH Corp. 9.75% Notes, the EFH Corp. Senior Secured Notes). In the first half of 2010, EFH Corp. issued an additional $106 million of the EFH Corp. 10% Notes in exchange for certain outstanding debt securities. The EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes are unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis except for Intermediate Holding’s guarantee of the EFH Corp. Senior Secured Notes, which is secured by a pledge of all membership interests and other investments Intermediate Holding owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries as described in Note 6. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Senior Notes and Senior Secured Notes. The guarantees by EFC Holdings and the guarantee of the EFH Corp. Senior Notes by Intermediate Holding rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of EFH Corp., either direct or indirect, do not guarantee the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes (collectively, the Non-Guarantors). The indentures governing the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes contain certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments. See Note 8.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the three-month and six-month periods ended June 30, 2010 and 2009, 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, 2010 and 2009 and the consolidating balance sheets as of June 30, 2010 and December 31, 2009 of the Parent/Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5-J, “Push Down Basis of Accounting Required in Certain Limited Circumstances,” including the effects of the push down of the $4.57 billion and $4.63 billion principal amount of EFH Corp. Senior Notes and $299 million and $115 million principal amount of the EFH Corp. Senior Secured Notes to the Guarantors as of June 30, 2010 and December 31, 2009, respectively (see Note 6). Amounts pushed down reflect Merger-related debt and additional debt guaranteed by the Guarantors that was issued by EFH Corp. to refinance Merger-related or other debt existing at the time of the Merger.

EFH Corp. (Parent) received dividends from its subsidiaries totaling $2 million and $58 million for the six months ended June 30, 2010 and 2009, respectively.

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended June 30, 2010

(millions of dollars)

 

		Parent/ Issuer				Guarantors				Non- Guarantors				Eliminations				Consolidated
Operating revenues		$	—			$	—			$	1,993			$	—			$	1,993
Fuel, purchased power costs and delivery fees			—				—				(1,074	)			—				(1,074	)
Net gain from commodity hedging and trading activities			—				—				67				—				67
Operating costs			—				—				(229	)			—				(229	)
Depreciation and amortization			—				—				(350	)			—				(350	)
Selling, general and administrative expenses			(6	)			—				(179	)			—				(185	)
Franchise and revenue-based taxes			—				—				(26	)			—				(26	)
Other income			66				—				81				64				211
Other deductions			—				—				(7	)			—				(7	)
Interest income			47				3				75				(125	)			—
Interest expense and related charges			(273	)			(152	)			(965	)			268				(1,122	)
Loss before income taxes and equity in earnings of subsidiaries			(166	)			(149	)			(614	)			207				(722	)
Income tax benefit			56				49				203				(71	)			237
Equity in earnings of consolidated subsidiaries			(375	)			(406	)			—				781				—
Equity in earnings of unconsolidated subsidiaries (net of tax)			59				59				—				(59	)			59
Net loss			(426	)			(447	)			(411	)			858				(426	)
Net income attributable to noncontrolling interests			—				—				—				—				—
Net loss attributable to EFH Corp.		$	(426	)		$	(447	)		$	(411	)		$	858			$	(426	)

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended June 30, 2009

(millions of dollars)

 

		Parent/ Issuer				Guarantors				Non- Guarantors				Eliminations				Consolidated
Operating revenues		$	—			$	—			$	2,342			$	—			$	2,342
Fuel, purchased power costs and delivery fees			—				—				(700	)			—				(700	)
Net loss from commodity hedging and trading activities			—				—				(248	)			—				(248	)
Operating costs			—				—				(395	)			—				(395	)
Depreciation and amortization			—				—				(423	)			—				(423	)
Selling, general and administrative expenses			(35	)			—				(235	)			—				(270	)
Franchise and revenue-based taxes			—				—				(79	)			—				(79	)
Other income			1				—				12				—				13
Other deductions			(3	)			—				(4	)			—				(7	)
Interest income			60				—				32				(81	)			11
Interest expense and related charges			(240	)			(141	)			(269	)			219				(431	)
Income (loss) before income taxes and equity earnings of subsidiaries			(217	)			(141	)			33				138				(187	)
Income tax (expense) benefit			67				47				(19	)			(47	)			48
Equity earnings of subsidiaries			(5	)			7				—				(2	)			—
Net income (loss)			(155	)			(87	)			14				89				(139	)
Net income attributable to noncontrolling interests			—				—				(16	)			—				(16	)
Net loss attributable to EFH Corp.		$	(155	)		$	(87	)		$	(2	)		$	89			$	(155	)

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Six Months Ended June 30, 2010

(millions of dollars)

 

		Parent/ Issuer				Guarantors				Non- Guarantors				Eliminations				Consolidated
Operating revenues		$	—			$	—			$	3,992			$	—			$	3,992
Fuel, purchased power costs and delivery fees			—				—				(2,121	)			—				(2,121	)
Net gain from commodity hedging and trading activities			—				—				1,280				—				1,280
Operating costs			—				—				(426	)			—				(426	)
Depreciation and amortization			—				—				(692	)			—				(692	)
Selling, general and administrative expenses			(12	)			—				(361	)			—				(373	)
Franchise and revenue-based taxes			—				—				(49	)			—				(49	)
Other income			74				—				98				72				244
Other deductions			—				—				(18	)			—				(18	)
Interest income			104				5				163				(263	)			9
Interest expense and related charges			(536	)			(300	)			(1,786	)			548				(2,074	)
Income (loss) before income taxes and equity in earnings of subsidiaries			(370	)			(295	)			80				357				(228	)
Income tax (expense) benefit			116				97				(58	)			(120	)			35
Equity in earnings of consolidated subsidiaries			61				44				—				(105	)			—
Equity in earnings of unconsolidated subsidiaries (net of tax)			122				122				—				(122	)			122
Net income (loss)			(71	)			(32	)			22				10				(71	)
Net income attributable to noncontrolling interests			—				—				—				—				—
Net income (loss) attributable to EFH Corp.		$	(71	)		$	(32	)		$	22			$	10			$	(71	)

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Six Months Ended June 30, 2009

(millions of dollars)

 

		Parent/ Issuer				Guarantors				Non- Guarantors				Eliminations				Consolidated
Operating revenues		$	—			$	—			$	4,481			$	—			$	4,481
Fuel, purchased power costs and delivery fees			—				—				(1,301	)			—				(1,301	)
Net gain from commodity hedging and trading activities			—				—				880				—				880
Operating costs			—				—				(783	)			—				(783	)
Depreciation and amortization			—				—				(830	)			—				(830	)
Selling, general and administrative expenses			(63	)			—				(453	)			—				(516	)
Franchise and revenue-based taxes			—				—				(165	)			—				(165	)
Impairment of goodwill			—				—				(90	)			—				(90	)
Other income			2				—				24				—				26
Other deductions			(3	)			—				(15	)			—				(18	)
Interest income			111				—				57				(156	)			12
Interest expense and related charges			(476	)			(281	)			(770	)			431				(1,096	)
Income (loss) before income taxes and equity earnings of subsidiaries			(429	)			(281	)			1,035				275				600
Income tax (expense) benefit			137				92				(421	)			(93	)			(285	)
Equity earnings of subsidiaries			579				629				—				(1,208	)			—
Net income			287				440				614				(1,026	)			315
Net income attributable to noncontrolling interests			—				—				(28	)			—				(28	)
Net income attributable to EFH Corp.		$	287			$	440			$	586			$	(1,026	)		$	287

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Six Months Ended June 30, 2010

(millions of dollars)

 

		Parent/ Issuer				Guarantors				Non-guarantors				Eliminations				Consolidated
Cash provided by (used in) operating activities		$	77			$	74			$	(147	)		$	130			$	134
Cash flows – financing activities:
Issuances of long-term borrowings			500				—				—				—				500
Repayments/repurchases of long-term borrowings			(81	)			(2	)			(186	)			(132	)			(401	)
Net short-term borrowings under accounts receivable sales program			—				—				158				—				158
Change in other short-term borrowings			—				—				(218	)			—				(218	)
Contributions from noncontrolling interests			—				—				14				—				14
Cash dividends paid			—				(2	)			—				2				—
Change in advances – affiliates			(804	)			34				850				(80	)			—
Other, net			(17	)			—				3				—				(14	)
Cash provided by (used in) financing activities			(402	)			30				621				(210	)			39
Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases			—				—				(637	)			—				(637	)
Investment posted with derivative counterparty			400				—				—				—				400
Proceeds from sale of assets			—				—				141				—				141
Proceeds from sale of environmental allowances and credits			—				—				6				—				6
Purchases of environmental allowances and credits			—				—				(10	)			—				(10	)
Proceeds from sales of nuclear decommissioning trust fund securities			—				—				803				—				803
Investments in nuclear decommissioning trust fund securities			—				—				(811	)			—				(811	)
Change in advances – affiliates			(60	)			(20	)			—				80				—
Other, net			(3	)			—				(11	)			—				(14	)
Cash provided by (used in) investing activities			337				(20	)			(519	)			80				(122	)
Net change in cash and cash equivalents			12				84				(45	)			—				51
Effects of deconsolidation of Oncor Holdings			(29	)			—				—				—				(29	)
Cash and cash equivalents – beginning balance			1,059				—				130				—				1,189
Cash and cash equivalents – ending balance		$	1,042			$	84			$	85			$	—			$	1,211

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Six Months Ended June 30, 2009

(millions of dollars)

 

		Parent/ Issuer				Guarantors				Non-Guarantors				Eliminations				Consolidated
Cash provided by (used in) operating activities		$	(114	)		$	50			$	684			$	(116	)		$	504
Cash flows – financing activities:
Issuances of long-term borrowings			—				—				435				—				435
Retirements of long-term borrowings			—				(2	)			(226	)			—				(228	)
Change in short-term borrowings			—				—				205				—				205
Contributions from noncontrolling interests			—				—				32				—				32
Distributions paid to noncontrolling interests			—				—				(17	)			—				(17	)
Cash dividends paid			—				(58	)			(58	)			116				—
Change in advances – affiliates			281				10				—				(291	)			—
Other, net			20				—				(3	)			—				17
Cash provided by (used in) financing activities			301				(50	)			368				(175	)			444
Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases			—				—				(1,343	)			—				(1,343	)
Redemption of investment held in money market fund			—				—				142				—				142
Investment posted with counterparty			(400	)			—				—				—				(400	)
Reduction of restricted cash from letter of credit facility posted with trustee			—				—				115				—				115
Proceeds from sale of environmental allowances and credits			—				—				7				—				7
Purchases of environmental allowances and credits			—				—				(14	)			—				(14	)
Proceeds from sales of nuclear decommissioning trust fund securities			—				—				2,231				—				2,231
Investments in nuclear decommissioning trust fund securities			—				—				(2,238	)			—				(2,238	)
Change in advances – affiliates			—				—				(291	)			291				—
Other, net			—				—				22				—				22
Cash used in investing activities			(400	)			—				(1,369	)			291				(1,478	)
Net change in cash and cash equivalents			(213	)			—				(317	)			—				(530	)
Cash and cash equivalents – beginning balance			1,075				—				614				—				1,689
Cash and cash equivalents – ending balance		$	862			$	—			$	297			$	—			$	1,159

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at June 30, 2010

(millions of dollars)

 

		Parent/ Issuer				Guarantors				Non-Guarantors				Eliminations				Consolidated
ASSETS
Current assets:
Cash and cash equivalents		$	1,042			$	84			$	85			$	—			$	1,211
Restricted cash			—				—				6				—				6
Advances to affiliates			—				—				237				(237	)			—
Trade accounts receivable – net			12				2				1,273				(7	)			1,280
Income taxes receivable			33				1				—				(34	)			—
Notes receivable from affiliates			920				—				1,631				(2,551	)			—
Inventories			—				—				401				—				401
Commodity and other derivative contractual assets			107				—				2,750				—				2,857
Accumulated deferred income taxes			62				—				107				—				169
Margin deposits related to commodity positions			—				—				173				—				173
Other current assets			2				—				74				—				76
Total current assets			2,178				87				6,737				(2,829	)			6,173
Restricted cash			—				—				1,135				—				1,135
Receivables from unconsolidated subsidiary			1,270				—				—				—				1,270
Investments in unconsolidated subsidiaries			4,711				3,703				—				(2,964	)			5,450
Other investments			283				70				560				(285	)			628
Property, plant and equipment – net			—				—				20,770				—				20,770
Notes receivable from affiliates			12				—				1,609				(1,621	)			—
Goodwill			—				—				10,252				—				10,252
Intangible assets – net			—				—				2,513				—				2,513
Commodity and other derivative contractual assets			—				—				2,132				—				2,132
Accumulated deferred income taxes			562				135				—				(697	)			—
Unamortized debt issuance costs and other noncurrent assets			108				89				612				(90	)			719
Total assets		$	9,124			$	4,084			$	46,320			$	(8,486	)		$	51,042
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings		$	—			$	—			$	893			$	—			$	893
Advances from affiliates			236				1				—				(237	)			—
Long-term debt due currently			—				8				245				—				253
Trade accounts payable			1				—				723				—				724
Payables to affiliates/unconsolidated subsidiary			1,638				34				1,094				(2,548	)			218
Commodity and other derivative contractual liabilities			136				—				2,512				—				2,648
Margin deposits related to commodity positions			—				—				530				—				530
Accrued interest			147				100				312				(102	)			457
Other current liabilities			2				—				362				(12	)			352
Total current liabilities			2,160				143				6,671				(2,899	)			6,075
Accumulated deferred income taxes			—				—				5,506				(553	)			4,953
Commodity and other derivative contractual liabilities			—				—				1,336				—				1,336
Notes or other liabilities due affiliates/unconsolidated subsidiary			1,282				—				686				(1,621	)			347
Long-term debt, less amounts due currently			7,202				5,099				29,735				(5,268	)			36,768
Other noncurrent liabilities and deferred credits			1,749				3				3,019				—				4,771
Total liabilities			12,393				5,245				46,953				(10,341	)			54,250
EFH Corp. shareholders’ equity			(3,269	)			(1,161	)			(702	)			1,863				(3,269	)
Noncontrolling interests in subsidiaries			—				—				69				(8	)			61
Total equity			(3,269	)			(1,161	)			(633	)			1,855				(3,208	)
Total liabilities and equity		$	9,124			$	4,084			$	46,320			$	(8,486	)		$	51,042

 

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31, 2009

(millions of dollars)

 

		Parent/ Issuer				Guarantors				Non-Guarantors			Eliminations				Consolidated
ASSETS
Current assets:
Cash and cash equivalents		$	1,059			$	—			$	130		$	—			$	1,189
Investment posted with counterparty			425				—				—			—				425
Restricted cash			—				—				48			—				48
Advances to affiliates			471				5				—			(476	)			—
Trade accounts receivable – net			8				2				1,253			(3	)			1,260
Income taxes receivable			23				2				—			(25	)			—
Accounts receivable from affiliates			—				—				22			(22	)			—
Notes receivable from affiliates			114				—				1,469			(1,583	)			—
Inventories			—				—				485			—				485
Commodity and other derivative contractual assets			52				—				2,339			—				2,391
Accumulated deferred income taxes			—				3				11			(9	)			5
Margin deposits related to commodity positions			—				—				187			—				187
Other current assets			2				—				134			—				136
Total current assets			2,154				12				6,078			(2,118	)			6,126
Restricted cash			—				—				1,149			—				1,149
Investments in unconsolidated subsidiaries			—				—				44			—				44
Other investments			4,586				3,634				638			(8,152	)			706
Property, plant and equipment – net			—				—				30,108			—				30,108
Notes receivable from affiliates			12				—				2,236			(2,248	)			—
Goodwill			—				—				14,316			—				14,316
Intangible assets – net			—				—				2,876			—				2,876
Regulatory assets – net			—				—				1,959			—				1,959
Commodity and other derivative contractual assets			—				—				1,533			—				1,533
Accumulated deferred income taxes			647				111				—			(758	)			—
Unamortized debt issuance costs and other noncurrent assets			108				99				733			(95	)			845
Total assets		$	7,507			$	3,856			$	61,670		$	(13,371	)		$	59,662
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings		$	—			$	—			$	1,569		$	—			$	1,569
Advances from affiliates			—				—				476			(476	)			—
Long-term debt due currently			—				8				409			—				417
Trade accounts payable			4				—				892			—				896
Accounts payable to affiliates			16				6				—			(22	)			—
Notes payable to affiliates			1,406				27				150			(1,583	)			—
Commodity and other derivative contractual liabilities			82				—				2,310			—				2,392
Margin deposits related to commodity positions			—				—				520			—				520
Accumulated deferred income taxes			9				—				—			(9	)			—
Accrued interest			119				93				408			(94	)			526
Other current liabilities			7				—				761			(24	)			744
Total current liabilities			1,643				134				7,495			(2,208	)			7,064
Accumulated deferred income taxes			—				—				6,764			(633	)			6,131
Investment tax credits			—				—				37			—				37
Commodity and other derivative contractual liabilities			—				—				1,060			—				1,060
Notes or other liabilities due affiliates			2,019				—				229			(2,248	)			—
Long-term debt, less amounts due currently			6,626				4,975				34,740			(4,901	)			41,440
Other noncurrent liabilities and deferred credits			466				3				5,297			—				5,766
Total liabilities			10,754				5,112				55,622			(9,990	)			61,498
EFH Corp. shareholders’ equity			(3,247	)			(1,256	)			4,637			(3,381	)			(3,247	)
Noncontrolling interests in subsidiaries			—				—				1,411			—				1,411
Total equity			(3,247	)			(1,256	)			6,048			(3,381	)			(1,836	)
Total liabilities and equity		$	7,507			$	3,856			$	61,670		$	(13,371	)		$	59,662

 

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Item 2.

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 for the three and six months ended June 30, 2010 and 2009 should be read in conjunction with our consolidated financial statements and the notes to those statements.

All dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwise indicated.

BUSINESS

We are a Dallas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority-owned (approximately 80%) subsidiary engaged in regulated electricity transmission and distribution operations in Texas. Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. See Notes 1 and 3 to Financial Statements for a description of the material features of these “ring-fencing” measures and for a discussion of the deconsolidation of Oncor (and its majority owner, Oncor Holdings) in 2010 as the result of a change in accounting principles.

Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment is principally comprised of TCEH. The Regulated Delivery segment is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary. See Notes 1 and 3 to Financial Statements for discussion of the deconsolidation of Oncor Holdings and, accordingly, Oncor and the Regulated Delivery segment, in 2010.

See Note 15 to Financial Statements for further information regarding reportable business segments.

Significant Activities and Events

Natural Gas Prices and Long-Term Hedging Program — TCEH has 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, the company has entered into market transactions involving natural gas-related financial instruments, and as of June 30, 2010, has effectively sold forward approximately 1.4 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 175,000 GWh at an assumed 8.0 market heat rate) for the period from July 1, 2010 through December 31, 2014 at weighted average annual hedge prices ranging from $7.80 per MMBtu to $7.18 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 65% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning July 1, 2010 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which is expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.

The long-term hedging program is comprised primarily of contracts with prices based on the New York Mercantile Exchange (NYMEX) Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged more than 95% of the Houston Ship Channel versus Henry Hub pricing point risk for 2010.

 

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The company has entered into related put and call transactions (referred to as collars), primarily for year 2014 of the program, that effectively hedge natural gas prices within a range. These transactions represented 8% of the positions in the long-term hedging program at June 30, 2010, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. The company expects to use financial instruments, including collars, in future hedging activity under the long-term hedging program.

The following table summarizes the natural gas hedges in the long-term hedging program as of June 30, 2010:

 

Measure

Balance 2010 (a)

2011

2012

2013

2014

Total

Natural gas hedge volumes (b)

mm MMBtu

~126

~372

~475

~298

~105

~1,376

Weighted average hedge price (c)

$/MMBtu

~7.75

~7.53

~7.34

~7.18

~7.80

—

Weighted average market price (d)

$/MMBtu

~4.82

~5.34

~5.68

~5.89

~6.10

—

 

(a)	Balance of 2010 is from July 1, 2010 through December 31, 2010.

(b)	Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e., delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 105 million MMBtu in 2014.

(c)

Weighted average hedge prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the long-term hedging program (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). Where collars are reflected, sales price represents the collar floor price.

(d)	Based on NYMEX Henry Hub prices.

Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the long-term hedging program as of June 30, 2010, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $1.4 billion in pretax unrealized mark-to-market gains or losses.

Unrealized mark-to-market net gains (losses) related to the long-term hedging program are as follows:

 

		Period Ended June 30, 2010
		Three Months				Six Months
Effect of natural gas market price changes on open positions		$	119			$	1,419
Reversals of previously recorded amounts on positions settled			(286	)			(529	)
Total unrealized effect (pre-tax)		$	(167	)		$	890

The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $2.868 billion and $1.978 billion at June 30, 2010 and December 31, 2009, respectively. See discussion below under “Operating Results” for realized net gains from hedging activities, which amounts are largely related to the long-term hedging program.

Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost.

 

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The significant cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program reflects declining forward market natural gas prices. As previously disclosed, forward natural gas prices have generally trended downward since mid-2008 as shown in the table of forward NYMEX Henry Hub natural gas prices below. While the long-term hedging program is designed to mitigate the effect on earnings of lower wholesale power prices, due to the lower natural gas prices, these market conditions are challenging to the long-term profitability of our generation assets. Specifically, this downward trend in natural gas prices and the correlated trend in ERCOT power prices could have a material adverse impact on the overall profitability of our generation assets for periods in which we do not have significant hedge positions. Additionally, a continued decline in forward natural gas prices will limit our ability to hedge our wholesale power revenues at reasonable price levels to support our interest payments and debt maturities.

 

		Forward Market Prices for Calendar Year ($/MMBtu)  (a)
Date		2010 (b)			2011			2012			2013			2014
June 30, 2008		$	11.24		$	10.78		$	10.74		$	10.90		$	11.12
September 30, 2008		$	8.58		$	8.54		$	8.41		$	8.30		$	8.30
December 31, 2008		$	7.13		$	7.31		$	7.23		$	7.15		$	7.15
March 31, 2009		$	5.93		$	6.67		$	6.96		$	7.11		$	7.18
June 30, 2009		$	6.06		$	6.89		$	7.16		$	7.30		$	7.43
September 30, 2009		$	6.21		$	6.87		$	7.00		$	7.06		$	7.17
December 31, 2009		$	5.79		$	6.34		$	6.53		$	6.67		$	6.84
March 31, 2010		$	4.27		$	5.34		$	5.79		$	6.07		$	6.36
June 30, 2010		$	4.82		$	5.34		$	5.68		$	5.89		$	6.10

 

(a)	Based on NYMEX Henry Hub prices.

(b)	For June 30, 2010 and March 31, 2010, natural gas prices for 2010 represent the average of forward prices for July through December and April through December, respectively.

As of June 30, 2010, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility – see discussion below under “Financial Condition – Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.

The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of June 30, 2010, which for natural gas reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling twelve-month basis, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

 

		Balance 2010 (a)			2011			2012			2013			2014
$1.00/MMBtu change in gas price (b)		$	~9		$	~55		$	~85		$	~295		$	~500
0.1/MMBtu/MWh change in market heat rate (c)		$	~3		$	~30		$	~45		$	~50		$	~50
$1.00/gallon change in diesel fuel price		$	~1		$	~2		$	~3		$	~50		$	~50

 

(a)	Balance of 2010 is from August 1, 2010 through December 31, 2010.

(b)	Assumes conversion of electricity positions based on an approximate 8.0 market heat rate with natural gas being on the margin 75% to 90% of the time (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated).

(c)	Based on Houston Ship Channel natural gas prices as of June 30, 2010.

 

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Liability Management Program — As of June 30, 2010, EFH Corp. and its subsidiaries (excluding Oncor and its subsidiaries) had $38 billion aggregate principal amount of debt outstanding. Of that amount, $22 billion matures in 2014 and the majority of the remaining amount matures from 2015 to 2017. As a result, in October 2009, we implemented a liability management program focused on improving our balance sheet by reducing debt and extending debt maturities.

Year-to-date July 2010, EFH Corp. acquired $1.108 billion aggregate principal amount of EFH Corp. and TCEH outstanding debt. As consideration for this acquired debt, EFH Corp. issued $561 million aggregate principal amount of EFH Corp. 10% Notes and paid $235 million in cash (excluding accrued interest payments).

The following table details our liability management program from its inception in October 2009 through July 2010 (debt amounts are principal amounts):

 

Security		Debt Acquired			Debt Issued/ Cash Paid
EFH Corp 10.875% Notes due 2017		$	213		$	—
EFH Corp. Toggle Notes due 2017			266			—
EFH Corp. 5.55% Series P Senior Notes due 2014			566			—
EFH Corp. 6.50% Series Q Senior Notes due 2024			10			—
EFH Corp. 6.55% Series R Senior Notes due 2034			6			—
TCEH 10.25% Notes due 2015			332			—
TCEH Toggle Notes due 2016			52			—
Term Loans under the TCEH Senior Secured Facilities due 2014			20			—
EFH Corp. and EFIH 9.75% Notes due 2019			—			256
EFH Corp 10% Notes due 2020			—			561
Cash			—			235
Total		$	1,465		$	1,052

The transactions resulted in the capture of $413 million of debt discount and aggregate projected interest savings (pre-tax) through 2014 of $148 million.

See Note 6 to Financial Statements for further discussion of the transactions completed under our liability management program and the exchange offers and consent solitications commenced in July 2010.

TCEH Interest Rate Swap Transactions — As of June 30, 2010, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $16.30 billion principal amount of its senior secured debt maturing from 2010 to 2014. All of these swaps were entered into prior to January 1, 2010. Taking into consideration these swap transactions, 11% of our total long-term debt portfolio at June 30, 2010 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions, which further reduce the fixed (through swaps) borrowing costs, related to an aggregate of $16.30 billion principal amount of senior secured debt, including swaps entered into in 2010 related to $2.55 billion principal amount of debt and reflecting the expiration in 2010 of swaps related to an aggregate $2.50 billion principal amount of debt. We may enter into additional interest rate hedges from time to time. Unrealized mark-to-market net losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $254 million and $361 million for the three and six months ended June 30, 2010, respectively. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.574 billion and $1.212 billion at June 30, 2010 and December 31, 2009, respectively, of which $140 million and $194 million (both pre-tax), respectively, was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 6 to Financial Statements regarding various interest rate swap transactions.

 

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Texas Generation Facilities Development — TCEH has substantially completed a program to develop three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in Texas with a total estimated capacity of approximately 2,200 MW. The Sandow and first Oak Grove units achieved substantial completion (as defined in the EPC agreements) in the fourth quarter 2009, and the second Oak Grove unit achieved substantial completion in the second quarter 2010. We began depreciating the units and recognizing revenues and fuel costs for accounting purposes in those respective periods. Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which $3.21 billion was spent as of June 30, 2010. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $4.8 billion, and the balance was $4.7 billion as of June 30, 2010. See discussion in Note 7 to Financial Statements regarding contingencies related to these units.

Idling of Natural Gas-Fueled Units — In February 2010, we notified ERCOT of plans to mothball (idle) four of our natural gas-fueled units, totaling 1,856 MW of capacity (1,933 MW installed nameplate capacity), in September 2010. In April 2010, ERCOT affirmed that the units may be mothballed. As discussed in the 2009 Form 10-K, in 2009 we retired 10 units, totaling 2,114 MW of capacity (2,226 MW installed nameplate capacity), mothballed three units, totaling 1,081 MW capacity (1,135 MW installed nameplate capacity) and entered into RMR (operational standby) agreements with ERCOT for two units, totaling 630 MW capacity (655 MW installed nameplate capacity).

As of June 30, 2010, TCEH’s operational fleet of natural gas-fueled generation facilities is generally used as peaking resources and consists of 16 units, totaling 2,848 MW installed nameplate capacity, including two units under RMR agreements and excluding eight units operated for unaffiliated parties as well as seven currently, and four pending, mothballed units.

Financial Services Reform Legislation — In July 2010, the US Congress enacted, and President Obama signed, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act). The primary purposes of the Financial Reform Act are, among other things, to address systemic risk in the financial system; to establish a Bureau of Consumer Financial Protection with broad powers to enforce consumer protection laws and promulgate rules against unfair, deceptive or abusive practices; to enhance regulation of the derivatives markets, including the requirement for central clearing of over-the counter derivative instruments and additional capital and margin requirements for certain derivative market participants; and to implement a number of new corporate governance requirements for companies with listed or, in some cases, publicly-traded securities. While the legislation is broad and detailed, substantial portions of the legislation will require rulemaking by federal governmental agencies to either implement the standards set out in the legislation or to adopt new standards. As a result, the full scope and effect of the legislation will likely not be known for several years.

Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives market. The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we use to hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However, end-users that are non-financial entities using the swap to hedge or mitigate commercial risk are exempt from these clearing requirements. The type of asset-backed OTC derivatives that we use to hedge commodity and interest rate risk should be exempt from the clearing requirements. In addition, existing swaps are grandfathered from the clearing requirements.

The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateral requirements are unclear as to whether an end-user or its counterparty (i.e., swap dealer) is required to post cash collateral, there is a risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. However, the legislative history of the Financial Reform Act suggests that it was not Congress’ intent to require end-users (rather that such requirement applies to swap dealers) to post cash collateral with respect to swaps. If we were required to post cash collateral on our swap transactions, our liquidity would likely be materially impacted, and our ability to enter into OTC derivatives to hedge our commodity and interest rate risks would be significantly limited.

 

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We cannot predict the outcome of the rulemaking to implement the OTC derivative market provisions of the Financial Reform Act. This rulemaking could negatively affect our ability to hedge our commodity and interest rate risks. The inability to hedge these risks would likely have a material adverse effect on our results of operations, financial condition or cash flows. See Part II. Item 1A. Risk Factors.

Global Climate Change — Several bills have been introduced in the US Congress or advocated by the Obama Administration that are intended to address climate change using different approaches, including most prominently a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade). These bills include the Waxman-Markey bill, known as the American Clean Energy and Security Act of 2009 (Waxman-Markey), the Kerry-Boxer bill, known as the Clean Energy Jobs and American Power Act (Kerry-Boxer) and the Kerry-Lieberman bill, known as the American Power Act (Kerry-Lieberman). This proposed legislation is not law, but in June 2009 Waxman-Markey was passed by the US House of Representatives and sent to the US Senate for consideration. Kerry-Boxer was reported out of the US Senate Environment and Public Works Committee, but has not been taken up by the Senate as a whole. Kerry-Lieberman was released by its sponsors in May 2010 when it appeared that progress on passing Kerry-Boxer had stalled.

Recent developments in the US Senate indicate that the prospects for passage of any cap-and-trade legislation in this Congress are not likely. However, if any of them or similar legislation were to be adopted, our costs of compliance could be material.

In December 2009, the EPA issued a finding that GHG emissions endanger human health and the environment and that emissions from motor vehicles contribute to that endangerment. The EPA’s finding required it to begin regulating GHG emissions from motor vehicles and ultimately stationary sources under existing provisions of the federal Clean Air Act. Following its endangerment finding, the EPA took three regulatory actions with respect to the control of GHG emissions. First, in March 2010, the EPA completed a reconsideration of a memorandum issued in December 2008 by then EPA Administrator Stephen Johnson on the issue of when the Clean Air Act’s Prevention of Significant Deterioration (PSD) program would apply to newly identified pollutants such as GHG’s. The EPA determined that the Clean Air Act’s PSD permit requirements would apply when a nation-wide rule requiring the control of a pollutant takes effect. Under this determination, the earliest time that PSD permitting requirements would apply to GHG emissions from stationary sources, including our power generation facilities, would be January 2011 – the first date that new motor vehicles must meet the new GHG standards. Second, in April 2010, the EPA adopted GHG emission standards for certain new motor vehicles. Third, in June 2010, the EPA finalized its so-called “tailoring rule” that established new thresholds of GHG emissions for the applicability of permits under the Clean Air Act for stationary sources, including our power generation facilities. The EPA’s tailoring rule defines the threshold of GHG emissions for determining applicability of the Clean Air Act’s permitting programs and PSD program at levels greater than the lower emission thresholds contained in the Clean Air Act. In addition, in September 2009, the EPA issued a final rule requiring the reporting, by March 2011, of calendar year 2010 GHG emissions from specified large GHG emissions sources in the US (such reporting rule would apply to our lignite-fueled generation facilities).

Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions — Following the invalidation of the Clean Air Interstate Rule (CAIR) by the federal courts in July 2008, the EPA was required to revise CAIR to correct the shortcomings identified by the federal courts. In July 2010, the EPA released a proposed rule called the Clean Air Transport Rule (CATR). The CATR, as proposed, would replace CAIR in 2012 and would require no additional emission reductions for Luminant. However, we cannot predict the impact of a final rule on our business, results of operations and financial condition.

 

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The Clean Air Act requires each state to monitor air quality for compliance with federal health standards. The EPA is required to periodically review, and if appropriate, revise all national ambient quality standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted State Implementation Plan (SIP) rules in May 2007 to deal with eight-hour ozone standards, which required NO_x emission reductions from certain of our peaking natural gas-fueled units in the Dallas-Fort Worth area. In March 2008, the EPA made the eight-hour ozone standards more stringent. In January 2010, the EPA proposed to further reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. Since the EPA projects that SIP rules to address attainment of these new more stringent standards will not be required until December 2013, we cannot yet predict the impact of this action on our generation facilities. In January 2010, the EPA added a new one-hour NO_x National Ambient Air Quality standard that may require actions within Texas to reduce emissions. The TCEQ will be required to revise its monitoring network and submit an implementation plan with compliance required by January 2021/2022. In June 2010, the EPA adopted a new one-hour SO₂ national ambient air quality standard that may require action within Texas to reduce SO₂ emissions. The TCEQ will be required to conduct modeling and develop an implementation plan by 2014, pursuant to which compliance will be required by 2017, according to the EPA’s implementation timeline. We cannot predict the impact of the new standards on our business, results of operations or financial condition until the TCEQ adopts (if required) an implementation plan with respect to the standards.

Solid Waste, Including Fly Ash Associated with Lignite/Coal-Fueled Generation — Treatment, storage and disposal of solid and hazardous waste are regulated at the federal and state level. In December 2008, an ash impoundment facility at a Tennessee Valley Authority (TVA) site ruptured, releasing a significant quantity of coal ash slurry. No impoundment failures of this magnitude have ever occurred at any of our impoundments, which are inspected on a regular basis, and we routinely sample groundwater monitoring wells to ensure compliance with all applicable regulations. As a result of the TVA ash impoundment failure, in May 2010, the EPA released a proposed rule that considers regulating coal combustion residuals as either a hazardous waste or a non-hazardous waste. We are unable to predict the requirements of a final rule; however, the potential cost of compliance could be material.

Oncor Technology Initiatives — Oncor continues to invest in technology initiatives that include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor’s plans provide for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits.

As of June 30, 2010, Oncor has installed approximately 1,085,000 advanced digital meters, including approximately 425,000 during the six months ended June 30, 2010. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $277 million as of June 30, 2010. Oncor expects to complete installations of all 3 million meters by the end of 2012.

Oncor Matters with the PUCT — See discussion of these matters, including the awarded construction of CREZ-related transmission lines, below under “Regulation and Rates.”

 

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RESULTS OF OPERATIONS

Pro Forma Consolidated Financial Results

As the result of deconsolidation of Oncor Holdings effective 2010, the results of Oncor Holdings are reflected in the 2010 consolidated statement of income as equity in earnings of unconsolidated subsidiary (net of tax) instead of separately as revenues and expenses as they are shown for periods prior to January 1, 2010. The following pro forma results for the three and six months ended June 30, 2009 are presented to provide for a meaningful comparison, along with the analyses on the following pages, of consolidated operating results in consideration of the deconsolidation of Oncor Holdings as discussed in Notes 1 and 3 to Financial Statements.

 

		Three  Months Ended June 30, 2010				Three Months Ended June 30, 2009
						As Reported				Pro Forma Adjustments (a)				Pro Forma
		(millions of dollars)
Operating revenues		$	1,993			$	2,342			$	(395	)		$	1,947
Fuel, purchased power costs and delivery fees			(1,074	)			(700	)			(258	)			(958	)
Net gain (loss) from commodity hedging and trading activities			67				(248	)			—				(248	)
Operating costs			(229	)			(395	)			221				(174	)
Depreciation and amortization			(350	)			(423	)			132				(291	)
Selling, general and administrative expenses			(185	)			(270	)			44				(226	)
Franchise and revenue-based taxes			(26	)			(79	)			58				(21	)
Other income			211				13				(10	)			3
Other deductions			(7	)			(7	)			1				(6	)
Interest income			—				11				1				12
Interest expense and related charges			(1,122	)			(431	)			76				(355	)
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries			(722	)			(187	)			(130	)			(317	)
Income tax (expense) benefit			237				48				48				96
Equity in earnings of unconsolidated subsidiaries (net of tax)			59				—				66				66
Net income (loss)			(426	)			(139	)			(16	)			(155	)
Net income attributable to noncontrolling interests			—				(16	)			16				—
Net income (loss) attributable to EFH Corp.		$	(426	)		$	(155	)		$	—			$	(155	)

 

(a)	All pro forma adjustments relate to Oncor Holdings and result in the presentation of the investment in Oncor Holdings under the equity method of accounting for the three months ended June 30, 2009.

 

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		Six  Months Ended June 30, 2010				Six Months Ended June 30, 2009
						As Reported				Pro Forma Adjustments (a)				Pro Forma
		(millions of dollars)
Operating revenues		$	3,992			$	4,481			$	(766	)		$	3,715
Fuel, purchased power costs and delivery fees			(2,121	)			(1,301	)			(500	)			(1,801	)
Net gain from commodity hedging and trading activities			1,280				880				—				880
Operating costs			(426	)			(783	)			441				(342	)
Depreciation and amortization			(692	)			(830	)			258				(572	)
Selling, general and administrative expenses			(373	)			(516	)			88				(428	)
Franchise and revenue-based taxes			(49	)			(165	)			118				(47	)
Impairment of goodwill			—				(90	)			—				(90	)
Other income			244				26				(20	)			6
Other deductions			(18	)			(18	)			4				(14	)
Interest income			9				12				2				14
Interest expense and related charges			(2,074	)			(1,096	)			150				(946	)
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries			(228	)			600				(225	)			375
Income tax (expense) benefit			35				(285	)			85				(200	)
Equity in earnings of unconsolidated subsidiaries (net of tax)			122				—				112				112
Net income (loss)			(71	)			315				(28	)			287
Net income attributable to noncontrolling interests			—				(28	)			28				—
Net income (loss) attributable to EFH Corp.		$	(71	)		$	287			$	—			$	287

 

(a)	All pro forma adjustments relate to Oncor Holdings and result in the presentation of the investment in Oncor Holdings under the equity method of accounting for the six months ended June 30, 2009.

 

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Consolidated Financial Results — Three Months Ended June 30, 2010 Compared to Pro Forma Three Months Ended June 30, 2009

See comparison of results of the Competitive Electric segment for discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain (loss) from commodity hedging and trading activities, operating costs; depreciation and amortization, and franchise and revenue-based taxes.

SG&A expenses decreased $41 million, or 18%, to $185 million in 2010. The decline reflected decreases in both the Competitive Electric segment and Corporate and Other and was driven by $30 million in lower transition costs associated with outsourced support services and the retail customer information system implemented in 2009.

Other income totaled $211 million in 2010 and $3 million in 2009. The 2010 amount included debt extinguishment gains totaling $129 million (see discussion of debt exchanges and repurchases in Note 6 to Financial Statements), a $44 million gain on sale of land and related water rights and a $30 million gain on sale of interests in a natural gas gathering pipeline business. See Note 16 to Financial Statements for details of other income and deductions.

Interest income totaled $12 million in 2009 primarily representing interest on $465 million in collateral under a funding arrangement described in Note 11 to Financial Statements.

Interest expense and related charges increased $767 million to $1.122 billion in 2010 reflecting a $254 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $460 million net gain in 2009 and a $63 million decrease in capitalized interest due to completion of certain new generation facility construction activities, partially offset by a $20 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges. See Note 16 to Financial Statements.

Income tax benefit totaled $237 million in 2010 compared to $96 million in 2009. The effective tax rate was 32.8% and 30.3% in 2010 and 2009, respectively. The increase in the rate reflects the effect of ongoing accruals of interest on uncertain tax positions on a significantly higher pre-tax loss in 2010.

Equity in earnings of unconsolidated subsidiaries (net of tax) totaled $59 million in 2010 compared to $66 million in 2009 reflecting a $6 million decline (which is before the effect of noncontrolling interests) in Oncor’s net income. The decrease was driven by timing differences in recognizing increased revenues and expenses resulting from Oncor’s August 2009 rate case order.

Net loss attributable to EFH Corp. increased $271 million to $426 million in 2010.

 

•

Net loss in the Competitive Electric segment increased $349 million to $427 million.

 

•

Earnings from the Regulated Delivery segment decreased $7 million to $59 million as discussed above.

 

•

Corporate and Other net expenses (after-tax) totaled $58 million in 2010 and $143 million in 2009. The amounts in 2010 and 2009 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The decrease of $85 million reflected debt extinguishment gains totaling $83 million and $19 million in lower SG&A expense primarily reflecting lower transition costs associated with outsourced support services and costs allocated to the competitive operations effective 2010, partially offset by a $21 million increase in interest expense driven by higher borrowings (all amounts after-tax).

 

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Consolidated Financial Results — Six Months Ended June 30, 2010 Compared to Pro Forma Six Months Ended June 30, 2009

See comparison of results of the Competitive Electric segment for discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain from commodity hedging and trading activities, operating costs; depreciation and amortization, and franchise and revenue-based taxes.

SG&A expenses decreased $55 million, or 13%, to $373 million in 2010 driven by $46 million in lower transition costs associated with outsourced support services and the retail customer information system implemented in 2009.

The $90 million impairment of goodwill recorded in 2009 largely related to the Competitive Electric segment and resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter of 2008 as discussed in Note 3 to Financial Statements in the 2009 Form 10-K.

Other income totaled $244 million in 2010 and $6 million in 2009. The 2010 amount included debt extinguishment gains totaling $143 million (see discussion of debt exchanges and repurchases in Note 6 to Financial Statements), a $44 million gain on sale of land and related water rights and a $37 million gain on sale of interests in a natural gas gathering pipeline business. See Note 16 to Financial Statements for details of other income and deductions.

Interest income decreased $5 million, or 36%, to $9 million in 2010 reflecting lower interest in 2010 on $465 million in collateral under a funding arrangement, due to settlement of the arrangement as described in Note 11 to Financial Statements.

Interest expense and related charges increased $1.128 billion to $2.074 billion in 2010 reflecting a $361 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $665 million net gain in 2009 and a $126 million decrease in capitalized interest due to completion of certain new generation facility construction activities, partially offset by $31 million in decreased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges. See Note 16 to Financial Statements.

Income tax benefit totaled $35 million in 2010 compared to income tax expense of $200 million in 2009. The effective tax rate was 15.4% and 53.3% in 2010 and 2009, respectively. The decrease in the rate reflects the impact of the nondeductible goodwill impairment of $90 million in 2009, which increased the rate 10.3 percentage points in 2009 and the effect of the $8 million deferred tax charge in 2010 related to the Patient Protection and Affordable Care Act (see Note 13 to Financial Statements). In addition, interest accrued on uncertain tax positions increased the rate on income in 2009 and decreased the rate on the loss in 2010.

Equity in earnings of unconsolidated subsidiaries (net of tax) totaled $122 million in 2010 compared to $112 million in 2009 reflecting a $15 million increase (which is before the effect of noncontrolling interests) in Oncor’s net income. The increase was driven by the effects of higher average consumption on revenues, primarily due to colder winter weather, partially offset by timing differences in recognizing increased revenues and expenses resulting from Oncor’s 2009 rate case order.

 

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Net earnings attributable to EFH Corp. decreased $358 million to a loss of $71 million in 2010.

 

•

Net income in the Competitive Electric segment decreased $474 million to $5 million.

 

•

Earnings from the Regulated Delivery segment increased $10 million to $122 million as discussed above.

 

•

Corporate and Other net expenses (after-tax) totaled $198 million in 2010 and $304 million in 2009. The amounts in 2010 and 2009 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The decrease of $106 million reflected a $93 million debt extinguishment gain, $35 million in lower SG&A expense primarily reflecting lower transition costs associated with outsourced support services and costs allocated to the competitive operations effective 2010 and $20 million goodwill impairment charge in 2009, partially offset by a $32 million increase in interest expense driven by higher borrowings and an $8 million deferred tax charge due to the implementation of the Patient Protection and Affordable Care Act (all amounts after-tax).

Non-GAAP Earnings Measures

In communications with investors, we use a non-GAAP earnings measure that reflects adjustments to earnings reported in accordance with US GAAP in order to review underlying operating performance. These adjusting items, which are generally noncash, consist of unrealized mark-to-market gains and losses, impairment charges, debt extinguishment gains and other charges, credits or gains that are unusual or nonrecurring. All such items and related amounts are disclosed in our annual report on Form 10-K and quarterly reports on Form 10-Q. Our communications with investors also reference “adjusted EBITDA,” which is a non-GAAP measure used in calculation of ratios in covenants of certain of our debt securities (see “Financial Covenants, Credit Rating Provisions and Cross Default Provisions” below).

 

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Competitive Electric Segment

Financial Results

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Operating revenues		$	1,993			$	1,945			$	3,992			$	3,711
Fuel, purchased power costs and delivery fees			(1,074	)			(957	)			(2,121	)			(1,800	)
Net gain (loss) from commodity hedging and trading activities			67				(248	)			1,280				880
Operating costs			(229	)			(174	)			(426	)			(343	)
Depreciation and amortization			(345	)			(283	)			(681	)			(559	)
Selling, general and administrative expenses			(180	)			(192	)			(363	)			(363	)
Franchise and revenue-based taxes			(26	)			(22	)			(49	)			(46	)
Impairment of goodwill			—				—				—				(70	)
Other income			76				2				89				5
Other deductions			(5	)			(5	)			(11	)			(16	)
Interest income			21				12				42				19
Interest expense and related charges			(948	)			(191	)			(1,721	)			(617	)
Income (loss) before income taxes			(650	)			(113	)			31				801
Income tax (expense) benefit			223				35				(26	)			(322	)
Net income (loss)		$	(427	)		$	(78	)		$	5			$	479

 

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Competitive Electric Segment

Sales Volume and Customer Count Data

 

		Three Months Ended June 30,						% Change			Six Months Ended June 30,						% Change
		2010			2009						2010			2009
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential		6,848			7,084			(3.3	)		13,568			12,964			4.7
Small business (a)		1,993			1,908			4.5			3,974			3,629			9.5
Large business and other customers		3,925			3,551			10.5			7,444			6,857			8.6
Total retail electricity		12,766			12,543			1.8			24,986			23,450			6.6
Wholesale electricity sales volumes		10,985			10,262			7.0			23,348			20,053			16.4
Net sales (purchases) of balancing electricity to/from ERCOT		925			(112	)		—			270			(265	)		—
Total sales volumes		24,676			22,693			8.7			48,604			43,238			12.4
Average volume (kWh) per residential customer (b):		3,723			3,688			0.9			7,351			6,777			8.5
Weather (North Texas average) – percent of normal (c):
Cooling degree days		117.2	%		105.3	%		11.3			115.1	%		111.6	%		3.1
Heating degree days		63.5	%		143.2	%		(55.7	)		131.9	%		93.3	%		41.4
Customer counts:
Retail electricity customers (end of period and in thousands) (d):
Residential											1,830			1,911			(4.2	)
Small business (a)											241			279			(13.6	)
Large business and other customers											22			21			4.8
Total retail electricity customers											2,093			2,211			(5.3	)

 

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

(b)	Calculated using average number of customers for the 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 US Department of Commerce). Normal is defined as the average over a 10-year period.

(d)	Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers.

 

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Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

 

		Three Months Ended June 30,								% Change			Six Months Ended June 30,								% Change
		2010				2009							2010				2009
Operating revenues:
Retail electricity revenues:
Residential		$	906			$	984			(7.9	)		$	1,776			$	1,776			—
Small business (a)			263				295			(10.8	)			529				558			(5.2	)
Large business and other customers			307				310			(1.0	)			592				625			(5.3	)
Total retail electricity revenues			1,476				1,589			(7.1	)			2,897				2,959			(2.1	)
Wholesale electricity revenues (b)			425				314			35.4				970				663			46.3
Net sales (purchases) of balancing electricity to/from ERCOT			24				(22	)		—				(17	)			(45	)		62.2
Amortization of intangibles (c)			3				1			—				2				(10	)		—
Other operating revenues			65				63			3.2				140				144			(2.8	)
Total operating revenues		$	1,993			$	1,945			2.5			$	3,992			$	3,711			7.6
Net gain (loss) from commodity hedging and trading activities:
Unrealized net gains (losses) from changes in fair value		$	73			$	(265	)		—			$	1,276			$	890			43.4
Unrealized net losses representing reversals of previously recognized fair values of positions settled in the current period			(235	)			(35	)		—				(460	)			(141	)		—
Realized net gains on settled positions			229				52			—				464				131			—
Total gain (loss)		$	67			$	(248	)		—			$	1,280			$	880			45.5

 

 

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

(b)

Upon settlement of physical derivative power sales and purchase contracts that are marked-to-market in net income, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result, these line item amounts include a noncash component, which the company considers “unrealized.” (The offsetting differences between contract and market prices are reported in net gain (loss) from commodity hedging and trading activities.) These amounts are as follows:

 

		Three Months Ended June  30,								Six Months Ended June  30,
		2010				2009				2010				2009
Reported in revenues		$	(14	)		$	(63	)		$	(32	)		$	(123	)
Reported in fuel and purchased power costs			31				43				64				84
Net gain (loss)		$	17			$	(20	)		$	32			$	(39	)

 

(c)	Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting from purchase accounting.

 

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Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

 

		Three Months Ended June 30,								% Change			Six Months Ended June 30,								% Change
		2010				2009							2010				2009
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel		$	35			$	37	(f)		(5.4	)		$	73			$	75	(f)		(2.7	)
Lignite/coal			209				147			42.2				432				299			44.5
Total baseload fuel			244				184			32.6				505				374			35.0
Natural gas fuel and purchased power (a)			390				302			29.1				714				521			37.0
Amortization of intangibles (b)			37				62	(f)		(40.3	)			80				123	(f)		(35.0	)
Other costs			42				49			(14.3	)			106				107			(0.9	)
Fuel and purchased power costs			713				597			19.4				1,405				1,125			24.9
Delivery fees (c)			361				360			0.3				716				675			6.1
Total		$	1,074			$	957			12.2			$	2,121			$	1,800			17.8
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel		$	7.80			$	7.36	(f)		6.0			$	7.68			$	7.26	(f)		5.8
Lignite/coal (d)			19.49				16.03			21.6				19.76				16.47			20.0
Natural gas fuel and purchased power			44.32				39.31			12.7				46.25				41.14			12.4
Delivery fees per MWh		$	28.18			$	28.44			(0.9	)		$	28.57			$	28.51			0.2
Production and purchased power volumes (GWh):
Nuclear			4,527				5,103			(11.3	)			9,539				10,293			(7.3	)
Lignite/coal			12,479				10,450			19.4				25,297				20,705			22.2
Total baseload generation			17,006				15,553			9.3				34,836				30,998			12.4
Natural gas-fueled generation			464				775			(40.1	)			836				1,033			(19.1	)
Purchased power			8,344				6,904			20.9				14,600				11,633			25.5
Total energy supply			25,814				23,232			11.1				50,272				43,664			15.1
Less line loss and power imbalances (e)			1,138				539			—				1,668				426			—
Net energy supply volumes			24,676				22,693			8.7				48,604				43,238			12.4
Baseload capacity factors:
Nuclear			90.1	%			101.8	%		(11.5	)			95.5	%			103.2	%		(7.5	)
Lignite/coal			74.1	%			82.0	%		(9.6	)			78.1	%			81.7	%		(4.4	)
Total baseload			78.0	%			87.6	%		(11.0	)			82.3	%			87.8	%		(6.3	)

 

(a)	See note (b) on previous page.

(b)	Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.

(c)	Includes delivery fee charges from Oncor.

(d)	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.

(e)	Includes physical purchases and sales, the financial results of which are reported in commodity hedging and trading activities in the income statement.

(f)	Reflects reclassification to correct amortization.

 

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Competitive Electric Segment – Financial Results — Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

Operating revenues increased $48 million, or 2%, to $1.993 billion in 2010.

Wholesale electricity revenues increased $111 million, or 35%, to $425 million in 2010 as compared to 2009 when revenues decreased 70%. An 8% increase in average wholesale electricity prices, reflecting higher natural gas prices and market heat rates, increased revenues by $34 million. A 7% increase in wholesale electricity sales volumes, reflecting production from the new generation units, increased revenue $27 million. The balance of the revenue increase reflected a decrease in unrealized losses related to physical derivative commodity sales contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

Bilateral electricity contracting activity includes hedging transactions that utilize contracts for physical delivery. Wholesale sales and purchases of electricity are reported gross in the income statement if the transactions are scheduled for physical delivery with ERCOT.

Comparisons of wholesale balancing activity, reported net, are generally not meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable.

Retail electricity revenues decreased $113 million, or 7%, to $1.476 billion and reflected the following:

 

•

Lower average pricing decreased revenues by $141 million driven by the contract business market and also reflecting lower residential pricing. Lower average pricing in both business and residential markets is reflective of competitive activity and a change in customer mix.

 

•

A 2% increase in sales volumes increased revenues by $28 million reflecting an increase in the business markets, partially offset by a decrease in the residential market. An 8% increase in business markets sales volumes reflected a change in customer mix and improved economic activity. A 3% decrease in residential sales volumes reflected a 4% decline in customer count that was driven by competitive activity.

Fuel, purchased power costs and delivery fees increased $117 million, or 12%, to $1.074 billion in 2010. Higher purchased power costs contributed $91 million to the increase and reflected increased volumes driven by unplanned outages of the new lignite-fueled units and a planned nuclear-fueled unit outage, as well as higher prices driven by the effect of higher natural gas prices and market heat rates as discussed above regarding wholesale revenues. Other factors contributing to the increase included $32 million in lignite fuel costs related to production from the new generation units at Oak Grove and Sandow and $30 million in higher lignite/coal costs at existing plants, reflecting higher purchased coal commodity and transportation costs. These increases were partially offset by $25 million in lower amortization of the intangible net asset values (including the stepped-up value of nuclear fuel) resulting from purchase accounting.

Overall baseload generation production increased 9% in 2010 reflecting a 19% increase in lignite/coal-fueled production, driven by the production in 2010 from the new generation units, partially offset by an 11% decrease in nuclear production reflecting year-to-year timing differences of planned outages.

 

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Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the three months ended June 30, 2010 and 2009, which totaled a net gain of $67 million and a net loss of $248 million, respectively:

Three Months Ended June 30, 2010 — Unrealized mark-to-market net losses totaling $162 million included:

 

•

$149 million in net losses related to hedge positions, which includes $74 million in net gains from changes in fair value, $3 million in day one gains related to commodity hedging positions and $226 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

 

•

$13 million in net losses related to trading positions, which includes $4 million in net losses from changes in fair value and $9 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $229 million included:

 

•

$222 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, largely related to the long-term hedging program, and

 

•

$7 million in net gains related to trading positions.

Three Months Ended June 30, 2009 — Unrealized mark-to-market net losses totaling $300 million included:

 

•

$328 million in net losses related to hedge positions, which includes $272 million in net losses from changes in fair value, a $3 million day one loss related to a commodity hedging position (see Note 11 to Financial Statements) and $53 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

 

•

$28 million in net gains related to trading positions, which includes $10 million in net gains from changes in fair value and $18 million in net gains that represent reversals of previously recorded net losses on positions settled in the period.

Realized net gains totaling $52 million included:

 

•

$64 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, largely related to the long-term hedging program, and

 

•

$12 million in net losses related to trading positions.

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $17 million in net gains in 2010 and $20 million in net losses in 2009.

Operating costs increased $55 million, or 32%, to $229 million in 2010. The increase reflected $25 million in incremental expense related to the new generation units. The increase also reflects $17 million in higher costs due to the year-to-year timing of planned refueling outages at the Comanche Peak nuclear-fueled plant, $4 million in higher maintenance costs for legacy lignite/coal-fueled operations, $3 million in higher property taxes and $6 million in various other operating cost variances.

Depreciation and amortization increased $62 million, or 22%, to $345 million in 2010. The increase reflected $45 million in incremental expense related to the new generation units and associated mining operations. The balance of the increase was driven by equipment additions and changes in depreciation rate estimates related to pending equipment retirements.

 

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SG&A expenses decreased $12 million, or 6%, to $180 million in 2010. The decrease reflected $15 million in lower transition costs associated with outsourced services and the retail customer information management system implemented in 2009, $3 million in lower employee-related costs, $3 million related to accounts receivable securitization program fees that are reported as interest expense and related charges in 2010 (see Note 5 to Financial Statements) and $11 million of various other cost reductions, partially offset by $12 million of new costs in 2010 allocated from corporate, principally fees paid to the Sponsor Group and $8 million in higher marketing expenses.

Other income totaled $76 million in 2010 and $2 million in 2009. Other income in 2010 includes a $44 million gain on the sale of land and related water rights and a $30 million gain on the sale of interests in a natural gas gathering pipeline business.

Interest income increased $9 million, or 75%, to $21 million in 2010 reflecting higher notes receivable balances from affiliates.

Interest expense and related charges increased by $757 million to $948 million in 2010 reflecting a $254 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $460 million net gain in 2009 and a $63 million decrease in capitalized interest due to completion of certain new generation facility construction activities, partially offset by a $20 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges.

Income tax benefit totaled $223 million in 2010 compared to income tax benefit of $35 million in 2009. The effective tax rate was 34.3% and 31.0% on losses in 2010 and 2009, respectively. The increase in the effective rate reflects the effect of ongoing accruals of interest on uncertain tax positions.

Net loss for the segment increased $349 million in 2010 to $427 million reflecting higher interest expense and related charges, partially offset by higher realized net gains and lower unrealized net losses related to commodity hedging activities and higher baseload generation.

Competitive Electric Segment – Financial Results — Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Operating revenues increased $281 million, or 8%, to $3.992 billion in 2010.

Wholesale electricity revenues increased $307 million, or 46%, to $970 million in 2010 as compared to 2009 when revenues decreased 60%. A 16% increase in wholesale electricity sales volumes, reflecting production from the new generation units, increased revenues by $129 million. A 10% increase in average wholesale electricity prices, reflecting higher natural gas prices and market heat rates, increased revenues by $87 million. The balance of the revenue increase reflected a decrease in unrealized losses related to physical derivative commodity sales contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

 

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Retail electricity revenues decreased $62 million, or 2%, to $2.897 billion and reflected the following:

 

•

Lower average pricing decreased revenues by $256 million driven by the contract business market and also reflecting lower residential pricing. Lower average pricing in both business and residential markets is reflective of competitive activity and a change in customer mix.

 

•

A 7% increase in sales volumes increased revenues by $194 million reflecting increases in both the residential and business markets. A 9% increase in business markets sales volumes reflected a change in customer mix, the impact of colder winter weather and improved economic activity. Higher average consumption resulted in a 5% overall increase in residential sales volumes, reflecting colder than normal winter weather in 2010 compared to warmer than normal winter weather in 2009, partially offset by a decline in residential customer counts.

The change in operating revenues also reflected a $12 million decrease in amortization of intangible assets arising from purchase accounting reflecting expiration of retail sales contracts.

Fuel, purchased power costs and delivery fees increased $321 million, or 18%, to $2.121 billion in 2010. Higher purchased power costs contributed $166 million to the increase and reflected increased volumes driven by outages of the new lignite-fueled units and the nuclear facility and higher retail demand, as well as higher prices driven by the effect of higher natural gas prices and market heat rates as discussed above regarding wholesale revenues. Other factors contributing to the increase included $70 million in lignite fuel costs related to production from the new generation units at Oak Grove and Sandow, $63 million in higher lignite/coal costs at existing plants, reflecting higher purchased coal commodity and transportation costs, $41 million in higher delivery fees, reflecting increased retail sales volumes and tariffs and $26 million in higher fuel costs for natural gas-fueled generation driven by higher prices. These increases were partially offset by $43 million in lower amortization of the intangible net asset values (including the stepped-up value of nuclear fuel) resulting from purchase accounting.

Overall baseload generation production increased 12% in 2010 reflecting a 22% increase in lignite/coal-fueled production, driven by the production in 2010 from the new generation units, partially offset by a 7% decrease in nuclear-fueled production. The decrease in nuclear-fueled production was due to an unplanned transformer outage in January 2010 and year-to-year timing differences of planned refueling outages.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the six months ended June 30, 2010 and 2009, which totaled $1.280 billion and $880 million, respectively:

Six Months Ended June 30, 2010 — Unrealized mark-to-market net gains totaling $816 million included:

 

•

$814 million in net gains related to hedge positions, which includes $1.249 billion in net gains from changes in fair value, $3 million in day one gains related to commodity hedging positions and $438 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

 

•

$2 million in net gains related to trading positions, which includes $23 million in net gains from changes in fair value, a $1 million day one gain related to a trading position and $22 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $464 million included:

 

•

$431 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, largely related to the long-term hedging program, and

 

•

$33 million in net gains related to trading positions.

 

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Six Months Ended June 30, 2009 — Unrealized mark-to-market net gains totaling $749 million included:

 

•

$754 million in net gains related to hedge positions, which includes $892 million in net gains from changes in fair value, a $3 million day one loss related to a commodity hedging position and $135 million in net losses that represent reversals of previously recorded fair values of positions settled in the period, and

 

•

$5 million in net losses related to trading positions, which includes $1 million in net gains from changes in fair value and $6 million in net losses that represent reversals of previously recorded fair values of positions settled in the period.

Realized net gains totaling $131 million include:

 

•

$137 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, largely related to the long-term hedging program, and

 

•

$6 million in net losses related to trading positions.

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $32 million in net gains in 2010 and $39 million in net losses in 2009.

Operating costs increased $83 million, or 24%, to $426 million in 2010. The increase reflected $45 million in incremental expense related to the new generation units. The increase also reflects $25 million in outage-related costs at the Comanche Peak nuclear-fueled plant reflecting year-to-year timing of planned outage maintenance costs and the transformer outage, $7 million in higher lignite/coal maintenance costs for legacy operations and $6 million in various other operating cost variances.

Depreciation and amortization increased $122 million, or 22%, to $681 million in 2010. The increase reflected $80 million in incremental expense related to the new generation units and associated mining operations. The balance of the increase was driven by equipment additions and changes in depreciation rate estimates related to pending equipment retirements.

SG&A expenses totaled $363 million in both 2010 and 2009 and reflected:

 

•

$23 million of new costs in 2010 allocated from corporate, principally fees paid to the Sponsor Group;

 

•

$15 million in increased bad debt expense in 2010 for retail operations primarily associated with residential customers, reflecting higher delinquencies due to delays in final bills and disconnects resulting from a system conversion, customer losses and general economic conditions, and

 

•

$9 million of higher marketing expenses in 2010,

offset by:

 

•

$23 million in lower transition costs associated with outsourced services and the retail customer information management system implemented in 2009;

 

•

$10 million in lower employee compensation-related expense in 2010;

 

•

$6 million of accounts receivable securitization program fees that are reported in 2010 as interest expense and related charges (see Note 5 to Financial Statements), and

 

•

$8 million of various other cost reductions.

The $70 million impairment of goodwill recorded in 2009 resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter of 2008 as discussed in Note 3 to Financial Statements in the 2009 Form 10-K.

 

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Other income totaled $89 million in 2010 and $5 million in 2009. Other income in 2010 includes a $44 million gain on the sale of land and related water rights, a $37 million gain associated with the sale of interests in a natural gas gathering pipeline business (see Note 16) and a $5 million refund of sales taxes related to prior years. Other deductions totaled $11 million in 2010 and $16 million in 2009 reflecting lower severance charges in 2010.

Interest income increased $23 million to $42 million in 2010 reflecting higher notes receivable balances from affiliates.

Interest expense and related charges increased by $1.104 billion to $1.721 billion in 2010 reflecting a $361 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $665 million net gain in 2009 and a $126 million decrease in capitalized interest due to completion of certain new generation facility construction activities, partially offset by a $31 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges and $18 million in lower average rates.

Income tax expense totaled $26 million in 2010 compared to $322 million in 2009. The effective rate was 83.9% and 40.2% in 2010 and 2009, respectively. The increase in the effective tax rate reflects the effect of interest accrued on uncertain tax positions on a significantly lower pretax income base in 2010 compared to 2009, partially offset by the impact of the nondeductible goodwill impairment of $70 million in 2009, which increased the rate approximately three percentage points.

Net income for the segment decreased $474 million in 2010 to $5 million reflecting higher interest expense and related charges, partially offset by higher realized net gains related to commodity hedging activities, the charge for impairment of goodwill in 2009 and higher baseload generation.

 

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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, 2010 and 2009. The net change in these assets and liabilities, excluding “other activity” as described below, represents the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 11 to Financial Statements). The portfolio consists primarily of economic hedges but also includes trading positions.

 

		Six Months Ended June 30,
		2010				2009
Commodity contract net asset at beginning of period		$	1,718			$	430
Settlements of positions (a)			(428	)			(181	)
Changes in fair value (b)			1,276				890
Other activity (c)			44				40
Commodity contract net asset at end of period (d)		$	2,610			$	1,179

 

(a)	Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and losses recognized in the settlement period).

(b)	Represents unrealized gains and losses recognized, primarily related to positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”).

(c)

These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold and physical natural gas exchange transactions. 2010 amount includes $46 million related to net payment of option premiums and $10 million related to settlement of a power sales agreement, partially offset by $12 million for expired option premiums. 2009 amount includes $7 million related to net payment of option premiums, $29 million in natural gas provided under physical gas exchange transactions and $7 million related to settlement of a certain power sales agreement, partially offset by $3 million for expired option premiums.

(d)	2010 amount excludes $2 million in net derivative liability related to cash flow hedge positions not marked-to-market in net income. See Note 11 to Financial Statements for additional discussion of commodity contracts assets and liabilities.

Unrealized gains and losses related to commodity contracts are summarized as follows:

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010			2009
Unrealized gains/(losses) related to contracts marked-to-market		$	(145	)		$	(321	)		$	848		$	709
Ineffectiveness gains/losses related to cash flow hedges			—				1				—			1
Total unrealized gains (losses) related to commodity contracts		$	(145	)		$	(320	)		$	848		$	710

 

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Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of June 30, 2010, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

 

		Maturity dates of unrealized commodity contract asset at June  30, 2010
Source of fair value		Less than 1 year				1-3 years				4-5 years				Excess of 5 years				Total
Prices actively quoted		$	(102	)		$	(54	)		$	—			$	—			$	(156	)
Prices provided by other external sources			964				1,447				186				—				2,597
Prices based on models			32				(6	)			316				(173	)			169
Total		$	894			$	1,387			$	502			$	(173	)		$	2,610
Percentage of total fair value			34	%			53	%			19	%			(6	)%			100	%

The “prices actively quoted” category reflects only exchange traded contracts for which active quotes are readily available. The “prices provided by other external sources” category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT that are deemed active markets (excluding the West zone) generally extend through 2012 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 that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 9 to Financial Statements for fair value disclosures and discussion of fair value measurements.

 

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FINANCIAL CONDITION

Liquidity and Capital Resources

Cash Flows — Cash provided by operating activities for the six months ended June 30, 2010 and 2009 totaled $134 million and $504 million, respectively. The decrease in cash provided of $370 million was driven by a $383 million effect of the amended accounting standard related to the sale of accounts receivable program (see Note 5 to Financial Statements). Changes in funding under the program have previously been reported as operating cash flows, and the amended accounting rule requires that the amount of funding under the program upon the January 1, 2010 adoption ($383 million) be reported as a use of operating cash flows and a source of financing cash flows. All changes in funding subsequent to adoption of the amended standard are reported as financing activities.

Cash provided by financing activities decreased $405 million as summarized below:

 

		Six Months Ended June 30,
		2010				2009
Net issuances, repayments and repurchases of borrowings		$	(151	)		$	408
Net contributions from and distributions to noncontrolling interests			14				15
Net short-term borrowings under accounts receivable sales program			158				—
Other			18				21
Total provided by financing activities		$	39			$	444

Cash used in investing activities decreased $1.356 billion driven by the return in 2010 of the collateral posted in 2009 related to interest rate swaps discussed in Note 11 to Financial Statements and decreased capital expenditures. These activities are summarized below:

 

		Six Months Ended June 30,
		2010				2009
Capital expenditures, including nuclear fuel		$	(637	)		$	(1,364	)
Redemption of investment held in money market fund			—				142
Investment redeemed/(posted) with counterparty			400				(400	)
Proceeds from sale of assets			141				1
Change in restricted cash			(5	)			129
Other			(21	)			14
Total used in investing activities		$	(122	)		$	(1,478	)

The decline in capital spending for the six months ended June 30, 2010 as compared to the six months ended June 30, 2009 primarily reflected the deconsolidation of Oncor ($537 million capital expenditures in 2009) (see Note 3 to Financial Statements) in 2010 and a decrease in spending related to the construction of the now substantially complete new generation facilities.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $189 million and $215 million for the six months ended June 30, 2010 and 2009, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice, and amortization of intangible net assets and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs and delivery fees, other income and interest expense and related charges.

 

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Debt Financing Activity — Activities related to short-term borrowings and long-term debt during the six months ended June 30, 2010 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):

 

		Borrowings (a)			Repayments and Repurchases (b)
TCEH		$	107		$	426
EFC Holdings			—			2
Intermediate Holding			—			—
EFH Corp.			768			217
Total long-term			875			645
Total short-term – TCEH (c)			—			218
Total		$	875		$	863
(a)    Includes the following activities (see Note 6 to Financial Statements):   •   $500 million of EFH Corp. 10% Notes issued by EFH Corp., the proceeds of which may be used in debt exchanges or repurchases.   •   Principal increases in payment of accrued interest totaling $162 million and $107 million of EFH Corp. and TCEH Toggle Notes, respectively.   •   $106 million of EFH Corp. 10% Notes issued by EFH Corp. in debt exchanges.   (b)    Includes $249 million of noncash retirements as a result of 2010 debt exchange and repurchase transactions discussed in Note 6 to Financial Statements. (c)    Short-term amounts represent net borrowings/repayments.

See Note 6 to Financial Statements for further detail of long-term debt and other financing arrangements.

We, our affiliates or our agents may from time to time purchase our outstanding debt for cash in open market purchases or privately negotiated transactions (including pursuant to a Section 10b-5(1) plan) or via privately negotiated exchange transactions similar to the private exchange transactions completed in 2010, or we may refinance existing debt. We will evaluate any such transactions in light of market prices of the debt, taking into account liquidity requirements and prospects for future access to capital, contractual restrictions and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material.

 

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Available Liquidity — The following table summarizes changes in available liquidity for the six months ended June 30, 2010 (excluding Oncor):

 

		Available Liquidity
		June 30, 2010			December 31, 2009			Change
Cash and cash equivalents		$	1,211		$	1,161		$	50
TCEH Revolving Credit Facility (a)			1,880			1,721			159
TCEH Letter of Credit Facility			429			399			30
Subtotal		$	3,520		$	3,281		$	239
Short-term investment (b)			—			490			(490	)
Total liquidity		$	3,520		$	3,771		$	(251	)

 

(a)	As of June 30, 2010 and December 31, 2009, the TCEH Revolving Credit Facility includes $144 million and $141 million, respectively, of commitments from Lehman that are only available from the fronting banks and the swingline lender.

(b)

December 31, 2009 amount includes $425 million cash investment (including accrued interest) and $65 million in letters of credit posted related to certain interest rate and commodity hedge transactions. Pursuant to the related agreement, the collateral was returned in March 2010. See Note 11 to Financial Statements.

Note: Available liquidity above does not include the amounts available from exercising the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from November 2010 through November 2012 could avoid cash interest payments of approximately $1.2 billion, excluding any effect of the ongoing debt exchange offers launched in July 2010 discussed in Note 6 to Financial Statements.

The $251 million decrease in available liquidity was driven by a reduction of financing under the accounts receivable securitization program as discussed in Note 5 to Financial Statements. Cash from debt issued was largely offset by cash used for debt repayments and repurchases.

See Note 6 to Financial Statements for additional discussion of the credit facilities.

Pension and OPEB Plan Funding — Pension and OPEB plan funding is expected to total $45 million and $24 million, respectively, in 2010. Oncor is expected to fund approximately 88% of this amount consistent with its share of the pension liability. We made pension and OPEB contributions of $14 million and $12 million, respectively, in the six months ended June 30, 2010, including $22 million contributed by Oncor.

 

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Toggle Notes Interest Election — EFH Corp. and TCEH have the option every six months at their discretion, ending with the payment due November 2012, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. We elected to do so beginning with the May 2009 interest payment as an efficient and cost-effective method to further enhance liquidity, in light of the weaker economy and related lower electricity demand and the continuing uncertainty in the financial markets. Once EFH Corp. and/or TCEH make a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. and/or TCEH revoke the applicable election. Use of the PIK feature will be evaluated at each election period, taking into account market conditions and other relevant factors at such time.

EFH Corp. made its May 2010 interest payment and will make its November 2010 interest payment on the EFH Corp. Toggle Notes by using the PIK feature of those notes. During such applicable interest periods, the interest rate on these notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the notes by $162 million in May 2010 and will further increase the aggregate principal amount of the notes by a currently estimated $162 million in November 2010. The elections increased liquidity in May 2010 by an amount equal to $152 million and will further increase liquidity in November 2010 by an amount equal to a currently estimated $152 million, constituting the amounts of cash interest that otherwise would have been payable on the notes in May 2010 and November 2010, respectively.

Similarly, TCEH made its May 2010 interest payment and will make its November 2010 interest payment on the TCEH Toggle Notes by using the PIK feature of those notes. During such applicable interest periods, the interest rate on these notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by approximately $110 million in May 2010, including $3 million principal amount paid to EFH Corp. and eliminated in consolidation, and will further increase the aggregate principal amount of the notes by $116 million in November 2010, including $3 million principal amount paid to EFH Corp. and eliminated in consolidation. The elections increased liquidity in May 2010 by an amount equal to $103 million and will further increase liquidity in November 2010 by an amount equal to an estimated $108 million, constituting the amounts of cash interest that otherwise would have been payable on the notes in May 2010 and November 2010, respectively.

See Note 6 to Financial Statements for discussion of debt repurchase and exchange transactions in 2010 that resulted in redemption of portions of the outstanding principal of the EFH Corp. and TCEH Toggle Notes held by unaffiliated parties that are reflected in the amounts related to the May 2010 and November 2010 PIK elections. No effects of the ongoing debt exchange offers launched in July 2010 are reflected above.

 

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Liquidity Effects of Commodity Hedging and Trading Activities — Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility, an uncapped senior secured revolving credit facility, funds the cash collateral posting requirements for a significant portion of the positions in the long-term hedging program not otherwise secured by a first-lien in the assets of TCEH. The aggregate principal amount of this facility is determined by the exposure arising from higher forward market prices, regardless of the amount of such exposure, on a portfolio of certain natural gas hedging transaction volumes. Including those hedging transactions where margin deposits are covered by unlimited borrowings under the TCEH Commodity Collateral Posting Facility, at June 30, 2010, more than 95% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. See Note 6 to Financial Statements for more information about this facility.

As of June 30, 2010, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

 

•

$168 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $183 million posted as of December 31, 2009;

 

•

$525 million in cash has been received from counterparties, net of $5 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $516 million received, net of $4 million in cash posted, as of December 31, 2009;

 

•

$318 million in letters of credit have been posted with counterparties, as compared to $379 million posted as of December 31, 2009, and

 

•

$31 million in letters of credit have been received from counterparties, as compared to $44 million received as of December 31, 2009.

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 variance 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 either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or it is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, 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 liquidity in the event that it was not restricted. As of June 30, 2010, restricted cash collateral held totaled $6 million. See Note 16 to Financial Statements regarding restricted cash.

With the long-term hedging program, increases in natural gas prices generally result in increased cash collateral and letter of credit postings to counterparties. As of June 30, 2010, approximately 500 million MMBtu of positions related to the long-term hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped TCEH Commodity Collateral Posting Facility supports the collateral posting requirements related to substantially all of these transactions.

 

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Income Tax Refunds/Payments — Income tax payments, primarily amounts related to the Texas margin tax, are expected to total approximately $72 million in the next 12 months. Payments in the six months ended June 30, 2010 totaled $52 million.

Accounts Receivable Securitization Program — TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). As discussed in Note 1 to Financial Statements, in accordance with amended transfers and servicing accounting standards, the trade accounts receivable amounts under the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $158 million and $383 million at June 30, 2010 and December 31, 2009, respectively. See Note 5 to Financial Statements for a more complete description of the program including amendments to the program in June 2010, the impact of the program on the financial statements for the periods presented and the contingencies that could result in termination of the program and a reduction of liquidity should the underlying financing be settled.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of June 30, 2010, we were in compliance with all such covenants.

Covenants and Restrictions under Financing Arrangements — Each of the TCEH Senior Secured Facilities and the indentures governing substantially all of the debt we have issued in connection with, and subsequent to, the Merger contain covenants that could have a material impact on the liquidity and operations of EFH Corp. and its subsidiaries.

Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Senior Notes) for the twelve months ended June 30, 2010 totaled $5.116 billion for EFH Corp. See Exhibit 99(b), 99(c) and 99(d) for a reconciliation of net income to Adjusted EBITDA for EFH Corp., TCEH and Intermediate Holding, respectively, for the six and twelve months ended June 30, 2010 and 2009.

 

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The following table summarizes TCEH’s secured debt to adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp., Intermediate Holding and TCEH that are applicable under certain other covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the EFH Corp. Senior Notes, the EFH Corp. Senior Secured Notes and the EFIH 9.75% Notes as of June 30, 2010 and December 31, 2009 and the corresponding maintenance and other covenant threshold levels as of June 30, 2010:

 

		June 30, 2010		December 31, 2009		Threshold Level as of June 30, 2010
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to adjusted EBITDA ratio (a)		5.06 to 1.00		4.76 to 1.00		Must not exceed 7.00 to 1.00 (b)
Debt Incurrence Covenants:
EFH Corp. Senior Notes:
EFH Corp. fixed charge coverage ratio		1.3 to 1.0		1.2 to 1.0		At least 2.0 to 1.0
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0		At least 2.0 to 1.0
EFH Corp. Senior Secured Notes:
EFH Corp. fixed charge coverage ratio		1.3 to 1.0		1.2 to 1.0		At least 2.0 to 1.0
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0		At least 2.0 to 1.0
EFIH 9.75% Notes:
Intermediate Holding fixed charge coverage ratio (c)		95.1 to 1.0		53.8 to 1.0		At least 2.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0		At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0		At least 2.0 to 1.0
Restricted Payments/Limitations on Investments Covenants:
EFH Corp. Senior Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (d)		1.5 to 1.0		1.4 to 1.0		At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (d)		1.3 to 1.0		1.2 to 1.0		At least 2.0 to 1.0
EFH Corp. leverage ratio		9.0 to 1.0		9.4 to 1.0		Equal to or less than 7.0 to 1.0
EFH Corp. Senior Secured Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (d)		1.5 to 1.0		1.4 to 1.0		At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (d)		1.3 to 1.0		1.2 to 1.0		At least 2.0 to 1.0
EFH Corp. leverage ratio		9.0 to 1.0		9.4 to 1.0		Equal to or less than 7.0 to 1.0
EFIH 9.75% Notes:
General restrictions (non-EFH Corp. payments):
Intermediate Holding fixed charge coverage ratio (c) (e)		4.9 to 1.0		3.9 to 1.0		At least 2.0 to 1.0
General restrictions (EFH Corp. payments):
Intermediate Holding fixed charge coverage ratio (c) (e)		95.1 to 1.0		53.8 to 1.0		At least 2.0 to 1.0
Intermediate Holding leverage ratio		4.2 to 1.0		4.4 to 1.0		Equal to or less than 6.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0		At least 2.0 to 1.0
TCEH Senior Secured Facilities:
Payments to Sponsor Group:
TCEH total debt to adjusted EBITDA ratio		8.2 to 1.0		8.4 to 1.0		Equal to or less than 6.5 to 1.0

 

(a)

In accordance with the terms of the TCEH Senior Secured Facilities and as the result of the new Sandow and first Oak Grove generating units achieving average capacity factors of greater than or equal to 70% for the three months ended March 31, 2010, the maintenance covenant as of June 30, 2010 includes pro forma twelve months adjusted EBITDA for the units and the proportional amount of outstanding debt under the Delayed Draw Term Loan (see Note 6 to Financial Statements) applicable to the two units.

(b)	Threshold level will decrease to a maximum of 6.75 to 1.00 effective December 31, 2010. Calculation excludes debt that ranks junior to the TCEH Senior Secured Facilities.

(c)

Although Intermediate Holding currently meets the fixed charge coverage ratio threshold applicable to certain covenants contained in the indenture governing the EFIH 9.75% Notes, Intermediate Holding’s ability to use such thresholds to incur debt or make restricted payments/investments is currently limited by the covenants contained in the EFH Corp. Senior Notes and the EFH Corp. Senior Secured Notes.

(d)	The EFH Corp. fixed charge coverage ratio for non-Sponsor Group payments includes the results of Oncor Holdings and its subsidiaries. The EFH Corp. fixed charge coverage ratio for Sponsor Group payments excludes the results of Oncor Holdings and its subsidiaries.

(e)	The Intermediate Holding fixed charge coverage ratio for non-EFH Corp. payments includes the results of Oncor Holdings and its subsidiaries. The Intermediate Holding fixed charge coverage ratio for EFH Corp. payments excludes the results of Oncor Holdings and its subsidiaries.

 

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Material Credit Rating Covenants and Credit Worthiness Effects on Liquidity — As a result of TCEH’s non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, as of June 30, 2010, counterparties to those contracts could have required TCEH to post up to an aggregate of $18 million in additional collateral. This amount largely represents the below market terms of these contracts as of June 30, 2010; thus, this amount will vary depending on the value of these contracts on any given day.

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 TCEH’s below investment grade credit rating, 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. As of June 30, 2010, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $30 million, with $16 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of June 30, 2010, TCEH posted letters of credit in the amount of $84 million, which are subject to adjustments. See “Regulation and Rates – Certification of REPs.”

The RRC has rules in place to assure adequate credit worthiness of parties that have mining reclamation obligations. Under these rules, should the RRC determine that the credit worthiness of Luminant Generation Company LLC (a subsidiary of TCEH) is not sufficient to support its reclamation obligations, TCEH may be required to post cash or letter of credit collateral support in an amount currently estimated to be approximately $650 million to $850 million. The actual amount (if required) could vary depending upon numerous factors, including Luminant Generation Company LLC’s credit worthiness and the level of mining reclamation obligations.

ERCOT has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $36 million as of June 30, 2010 (which is subject to weekly adjustments based on settlement activity with ERCOT).

Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 5 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.

In the event that any or all of the additional collateral requirements discussed above are triggered, we believe we will have adequate liquidity to satisfy such requirements.

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 could or does result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.

A default by TCEH or any of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the accounts receivable securitization program and hedging obligations, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity of outstanding balances ($22.016 billion at June 30, 2010) under such facilities.

The indenture governing the TCEH Senior Notes contains a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of TCEH or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the TCEH Senior Notes.

 

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Under the terms of a TCEH rail car lease, which had $46 million in remaining lease payments as of June 30, 2010 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

Under the terms of a TCEH rail car lease, which had $52 million in remaining lease payments as of June 30, 2010 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

Each of the indentures governing the EFH Corp. Senior Notes and Senior Secured Notes contains a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFH Corp. or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFH Corp. Senior Notes and Senior Secured Notes.

The indenture governing the EFIH 9.75% Notes contains a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of Intermediate Holding or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFIH 9.75% Notes.

The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under the program. TXU Receivables Company and EFH Corporate Services Company (a direct subsidiary of EFH Corp.), as collection agent, in the aggregate have a cross default threshold of $50,000. If any of the aforementioned defaults on indebtedness of the applicable threshold were to occur, the program could terminate.

We 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 if we were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on the contract.

Each of TCEH’s natural gas hedging agreements that are secured with a lien on its assets on a pari passu basis with the TCEH Senior Secured Facilities contains a cross default provision. In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge agreement with TCEH and require all outstanding obligations under such agreement to be settled.

In the event of a default by TCEH relating to indebtedness in an amount equal to or greater than $200 million that results in the acceleration of such debt, then each counterparty under TCEH’s interest rate swap agreements with an aggregate derivative liability of $1.574 billion at June 30, 2010 would have the right to terminate its interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

A default by Oncor or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million may result in a cross default under its credit facility. Under this facility such a default may cause the maturity of outstanding balances ($948 million at June 30, 2010) under such facility to be accelerated.

Other arrangements, including leases, have cross default provisions, the triggering of which would not be expected to result in a significant effect on liquidity.

 

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Guarantees — See Note 7 to Financial Statements for details of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

See Notes 3 and 7 to Financial Statements regarding VIEs and guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 7 to Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to Financial Statements for a discussion of changes in accounting standards.

 

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REGULATION AND RATES

Regulatory Investigations and Reviews

See Note 7 to Financial Statements.

Certification of REPs

In April 2009, the PUCT finalized a rule relating to the Certification of Retail Electric Providers. The rule strengthens the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the potential insolvency of REPs. The rule, among other things, increases creditworthiness and financial reporting requirements for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the new financial requirements, TXU Energy filed an amended certification, which became effective in March 2010. As a result, TCEH posted letters of credit in March 2010 totaling $84 million with the PUCT securing its payment obligations to TDUs, and is no longer required to reserve liquidity for such purposes. Liquidity reserved at December 31, 2009 totaled $228 million.

Wholesale Market Design – Nodal Market

In August 2003, the PUCT adopted a rule that, when implemented, will alter the wholesale market design in the ERCOT market. The rule requires ERCOT to:

 

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use a stakeholder process to develop a new wholesale market model;

 

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operate a voluntary day-ahead energy market;

 

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directly assign all congestion rents to the resources that caused the congestion;

 

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use nodal energy prices for resources;

 

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provide information for energy trading hubs by aggregating nodes;

 

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use zonal prices for loads, and

 

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provide congestion revenue rights (CRRs) (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 nodes on the transmission grid instead of across the geographic zones. The implementation of a nodal market is being done in conjunction with transmission improvements designed to reduce current congestion. The implementation of a nodal market is scheduled for December 2010. We cannot predict the ultimate impact of the proposed nodal wholesale market design on our operations or financial results.

In 2010, ERCOT began conducting market testing activities in preparation for the December 2010 transition to the nodal market design. These testing activities have included certifying qualified scheduling entities (QSEs) to participate in the day-ahead and real-time markets, conducting market-wide tests of ERCOT’s nodal operation systems to deploy generation resources to maintain grid frequency, holding mock auctions related to CRRs and conducting simulations of day-ahead market operations with market participants. In addition to these operational market testing activities, ERCOT has provided simulated full financial settlement and calculation of simulated credit exposure and collateral requirements for each simulated operating day. We have participated in these activities and are currently fully certified for participating in both the day-ahead market and real-time operations. Additionally, all of our operational and mothballed generation assets and our QSEs have completed certification for operation in the nodal market. In the upcoming months, we will continue to actively participate in ERCOT’s market tests, including the upcoming 168-hour test that is planned to be completed by October 2010.

 

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Oncor Matters with the PUCT

Stipulation Approved by the PUCT — In April 2008, the PUCT entered an order, which became final in June 2008, approving the terms of a stipulation relating to the filing in 2007 by Oncor and Texas Holdings of a Merger-related Joint Report and Application with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. The stipulation required the filing of a rate case by Oncor no later than July 1, 2008 based on a test year ended December 31, 2007. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200^th District Court of Travis County, Texas. A hearing in the appeal was held in June 2010, and the District Court affirmed the PUCT order in its entirety. Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order with respect to the rate case in August 2009 as discussed in the 2009 Form 10-K. Oncor and four other parties appealed various portions of the rate case final order to state district court. The parties have agreed to a schedule that would result in a hearing in October 2010.

Transmission Rates (PUCT Docket Nos. 37882, 38460 and 38495) — In order to recover increases in its transmission costs, including incremental fees paid to other transmission service providers due to an increase in their rates, Oncor is allowed to request an update twice a year to the transmission cost recovery factor (TCRF) component of its retail delivery rates charged to REPs. In January 2010, an application was filed to increase the TCRF, which was administratively approved in February 2010 and became effective March 1, 2010. This application is expected to increase annualized revenues by $13 million. In July 2010, an application was filed to increase the TCRF, which is expected to be administratively approved and become effective in September 2010. This application is expected to increase Oncor’s annualized revenues by $15 million.

In July 2010, Oncor filed an application for an interim update of its wholesale transmission rate. Oncor expects PUCT approval of the new rate before the end of 2010. Following approval, Oncor’s annualized revenues are expected to increase by an estimated $43 million with $27 million of this increase recoverable through transmission rates charged to wholesale customers, and the remaining $16 million recoverable from REPs through the TCRF component of Oncor’s delivery rates.

Proposed PUCT Rulemaking — The PUCT has published proposed rule changes in two proceedings that would impact transmission rates. The first proceeding (PUCT Project No. 37909), which the PUCT is expected to consider by the end of September 2010, proposes changes to the TCRF rule to allow for more complete cost recovery of wholesale transmission charges incurred by distribution service providers. Currently, increased wholesale transmission charges are recoverable by distribution service providers, effective with the March 1 and September 1 TCRF updates, but distribution service providers cannot recover increased charges incurred prior to such updates. If the rule is approved as proposed, TCRF filings would still be effective March 1 and September 1, but distribution service providers would be allowed to include wholesale transmission charges based on the effective date of the wholesale transmission rate changes. In the second proceeding (PUCT Project No. 37519), the PUCT approved the proposal for adoption at its July 30, 2010 open meeting, making changes to the wholesale transmission rules to allow transmission service providers to update their wholesale transmission rates twice in a calendar year, as compared to once per year under the current rules, providing more timely recovery of incremental capital investment. Other changes included in this rule will (i) tie the effective date of the rule to the effective date of the TCRF rule in Project No. 37909, (ii) require the PUCT to consider the effects of reduced regulatory lag when setting rates in the next full rate case and (iii) provide for administrative approval of uncontested interim wholesale transmission rate applications.

Application for 2011 Energy Efficiency Cost Recovery Factor (PUCT Docket No. 38217) — In April and May 2010, Oncor filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2011. PUCT rules require Oncor to make an annual EECRF filing by May 1 for implementation at the beginning of the next calendar year. The requested 2011 EECRF, as adjusted, is $54 million, the same amount established for 2010, and would result in a $0.95 per month charge for residential customers, as compared to the 2010 residential charge of $0.89 per month. As allowed by the rule, the 2011 EECRF is designed to recover $45 million of Oncor’s costs for the 2011 programs, to be reduced by $2 million for the over-recovery of 2009 program costs, plus a performance bonus to Oncor of $11 million based on 2009 results. No party has requested a hearing, and the PUCT staff has recommended approval of Oncor’s application. Oncor anticipates that the PUCT will issue an order in the third quarter 2010.

 

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Competitive Renewable Energy Zones (CREZs) — In January 2009, the PUCT awarded approximately $1.3 billion of CREZ construction projects to Oncor (PUCT Docket Nos. 35665 and 37902). The projects involve the construction of transmission lines to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. A written order reflecting the PUCT’s decision was entered in March 2009, and an order on rehearing was issued by the PUCT in May 2009. The cost estimates for the CREZ construction projects are based upon cost analyses prepared by ERCOT in April 2008. Based on the selection of final routes for the three default and nine priority projects and identification of additional costs not included in the original ERCOT estimate (e.g., wind interconnection facilities and required modifications to existing facilities), Oncor estimates that the cost of these projects will exceed ERCOT estimates by approximately $220 million. Final routes for five subsequent projects have not yet been selected by the PUCT. As of June 30, 2010, Oncor’s cumulative CREZ-related capital expenditures totaled $217 million, including $103 million during the six months ended June 30, 2010. It is expected that the necessary permitting actions and other requirements and all construction activities for Oncor’s CREZ construction projects will be completed by the end of 2013.

In October 2009, the PUCT initiated a proceeding to determine whether there is sufficient financial commitment from generators of renewable energy to grant Certificates of Convenience and Necessity (CCNs) for transmission facilities located in two areas in the panhandle of Texas designated as CREZs. If the PUCT determines that there is not sufficient financial commitment from the generators for either CREZ, the PUCT may take action, including delaying the filing of CREZ CCN applications until such time as the PUCT finds sufficient financial commitment for that CREZ in accordance with the financial commitment provisions of the PUCT’s rules. Three of the CREZ transmission projects awarded to Oncor are located in the two CREZs that are the subject of the proceeding. The estimated cost of these three transmission projects is approximately $380 million. In July 2010, a stipulation and proposed order was filed that would allow these projects to proceed. The PUCT approved the proposed order at its July 30, 2010 open meeting.

In July 2009, the City of Garland, Texas filed an Original Petition and Application for Stay and Injunction in the 200^th District Court of Travis County, Texas seeking judicial review and a stay of the PUCT’s March 2009 written order selecting transmission service providers (including Oncor) to build CREZ transmission facilities. In January 2010, the district court issued an order reversing the PUCT’s order and remanding it to the PUCT for action consistent with the court’s opinion. The district court order did not contain a stay or injunction and severed the City of Garland’s requests for declaratory and injunctive relief. In February 2010, the PUCT issued orders that severed certain of the CREZ transmission projects awarded to Oncor and others from its consideration of the remand of the written order (PUCT Docket No. 37928) and suspended the schedule sequencing CREZ projects subsequent to CREZ priority projects (PUCT Docket No. 36802). In April 2010, the PUCT issued an order in Docket No. 36802 establishing the sequencing for CREZ projects subsequent to priority projects, which did not affect Oncor other than resulting in the schedule for Oncor to file CCN applications for its five CREZ subsequent projects between May and September 2010 as compared to the original March to May 2010 timeframe. That order excludes two CREZ subsequent projects that had been originally awarded to Lower Colorado River Authority, and the PUCT has opened Docket No. 38045 to award these two projects. In July 2010, the City of Garland and South Texas Electric Cooperative filed a participation agreement regarding these two projects. It is anticipated that the PUCT will award the projects in the third quarter of 2010.

Sunset Review — PURA, the PUCT, the RRC, ERCOT, the TCEQ and the Office of Public Utility Counsel (OPUC) will be subject to “sunset” review by the Texas Legislature in the 2011 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (the PUCT, the RRC, ERCOT, the TCEQ or the OPUC), along with an evaluation of the advisability of any changes to that agency’s authorizing legislation (PURA). A Sunset staff report on the PUCT offering various recommendations for consideration by the Sunset Commission was issued in April 2010, and the related Sunset public meeting was conducted in May 2010. The Sunset Commission met in July 2010 and adopted various recommendations regarding the PUCT, ERCOT and the OPUC. A Sunset staff report on the RRC is scheduled to be issued in October 2010, and the related Sunset public meeting is scheduled for November 2010. The Sunset Commission will submit its recommendations for the Texas Legislature’s consideration during the next session, which begins in January 2011. We cannot predict the outcome of the sunset review process.

 

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Summary

We cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions. Such actions or changes could significantly alter our basic financial position, results of operations or cash flows.

 

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk that we may experience a loss in value as a result of changes in market conditions affecting factors such as commodity prices and interest rates, that may be experienced in the ordinary course of business. Our exposure to market risk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to manage interest rate risk related to indebtedness, as well as exchange traded, over-the-counter contracts and other contractual arrangements to manage commodity price risk.

Risk Oversight

TCEH manages the commodity price, counterparty credit and commodity-related operational risk related to the unregulated energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groups that operate 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, transaction review and approval (including credit review), operational and market risk measurement, validation of transaction capture, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

We have a corporate risk management organization that is headed by the Chief Financial Officer, who also functions as the Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits and evaluates the risks inherent in our businesses.

Commodity Price Risk

TCEH is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. The company actively manages its portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. The company, 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, TCEH enters 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 include hedging, the structuring of long-term contractual arrangements and proprietary trading. The company continuously monitors the valuation of identified risks and adjusts positions based on current market conditions. The company 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 “Significant Activities and Events” above for a description of the program, including potential effects on reported results.

 

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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.

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, 2010			Year Ended December 31, 2009
Month-end average Trading VaR:		$	3		$	4
Month-end high Trading VaR:		$	4		$	7
Month-end low Trading VaR:		$	2		$	2

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 of five to 60 days.

 

		Six Months Ended June 30, 2010			Year Ended December 31, 2009
Month-end average MtM VaR:		$	501		$	1,050
Month-end high MtM VaR:		$	621		$	1,470
Month-end low MtM VaR:		$	420		$	638

Earnings at Risk (EaR) — This measurement estimates the potential reduction of pretax earnings for the periods 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). Transactions accounted for as cash flow hedges are also included for this measurement. A 95% confidence level and a five to 60 day holding period are assumed in determining EaR.

 

		Six Months Ended June 30, 2010			Year Ended December 31, 2009
Month-end average EaR:		$	542		$	1,088
Month-end high EaR:		$	662		$	1,511
Month-end low EaR:		$	421		$	676

The decreases in the risk measures (MtM VaR and EaR) above were primarily driven by changes in market volatility and underlying commodity prices.

 

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Interest Rate Risk

As of June 30, 2010, the potential reduction of annual pretax earnings due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled $41 million, taking into account the interest rate swaps discussed in Note 6 to Financial Statements.

Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty’s financial 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. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties’ financial strength, measurement of current and potential future exposures and 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 assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Additionally, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality 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 — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions arising from hedging and trading activities totaled $2.475 billion at June 30, 2010. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of June 30, 2010 include $880 million in retail trade accounts receivable. Cash deposits held as collateral for these receivables totaled $73 million at June 30, 2010. 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, market or operational conditions and changes in the financial condition of large business customers.

The remaining credit exposure arises from wholesale energy sales and purchases and hedging and trading activities, including interest rate hedging. Counterparties to these transactions 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, 2010, the exposure to credit risk from these counterparties totaled $1.595 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $253 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $1.342 billion did not change materially from December 31, 2009.

Of this $1.342 billion net exposure, essentially all is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and our internal credit evaluation process. Those customers and counterparties without a 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 a S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.

 

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The following table presents the distribution of credit exposure as of June 30, 2010 arising from wholesale energy sales and purchases and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from hedging and trading activities after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. See Note 11 to Financial Statements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.

 

													Gross Exposure by Maturity
		Exposure Before Credit Collateral				Credit Collateral			Net Exposure				2 years or less			Between 2-5  years			Greater than 5 years			Total
Investment grade		$	1,559			$	224		$	1,335			$	516		$	1,043		$	—		$	1,559
Noninvestment grade			36				29			7				36			—			—			36
Totals		$	1,595			$	253		$	1,342			$	552		$	1,043		$	—		$	1,595
Investment grade			97.7	%						99.5	%
Noninvestment grade			2.3	%						0.5	%

In addition to the exposures in the table above, contracts classified as “normal” purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform. Nonperformance could have a material adverse impact on future results of operations, financial condition and cash flows.

Significant (10% or greater) concentration of credit exposure exists with three counterparties, which represented 50%, 20% and 17% of the net $1.342 billion exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of our business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.

With respect to credit risk related to the long-term hedging program, essentially all of the transaction volumes are with counterparties with an A credit rating or better. However, there is current and potential credit concentration risk related to the limited number of counterparties that comprise the substantial majority of the program with such counterparties being in the banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. An event of default by one or more hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through the various ongoing risk management measures described above.

 

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain “forward-looking statements.” All statements, other than statements of historical facts, that are included in this report, 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, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as “intends,” “plans,” “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “should,” “projection,” “target,” “goal,” “objective” and “outlook”), 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 under Item 1A, “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:

 

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prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, FERC, the NERC, the TRE, the PUCT, the RRC, the NRC, the EPA, the TCEQ and the Commodity Futures Trading Commission, with respect to, among other things:

 

•

allowed prices;

 

•

allowed rates of return;

 

•

permitted capital structure;

 

•

industry, market and rate structure;

 

•

purchased power and recovery of investments;

 

•

operations of nuclear generating facilities;

 

•

operations of fossil-fueled generating facilities;

 

•

operations of mines;

 

•

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;

 

•

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

 

•

clearing over the counter derivatives through exchanges and posting of cash collateral therewith;

 

•

legal and administrative proceedings and settlements;

 

•

general industry trends;

 

•

economic conditions, including the current recessionary environment;

 

•

our ability to attract and retain profitable customers;

 

•

our ability to profitably serve our customers;

 

•

restrictions on competitive retail pricing;

 

•

changes in wholesale electricity prices or energy commodity prices;

 

•

changes in prices of transportation of natural gas, coal, crude oil and refined products;

 

•

unanticipated changes in market heat rates in the ERCOT electricity market;

 

•

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

 

•

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

 

•

unanticipated population growth or decline, or 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, 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 and the potential impact of disruptions in US and international credit markets;

 

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•

access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets;

 

•

financial restrictions placed on us by our credit facilities and indentures governing our debt instruments;

 

•

our ability to generate sufficient cash flow to make interest payments on our debt instruments;

 

•

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;

 

•

changes in electricity transmission that allow additional electricity generation to compete with our generation assets;

 

•

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 costs of providing employee benefits, including pension and OPEB, and future funding requirements related thereto;

 

•

changes in assumptions used to estimate future executive compensation payments;

 

•

hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;

 

•

significant changes in critical accounting policies;

 

•

actions by credit rating agencies;

 

•

our ability to effectively execute our operational strategy, and

 

•

our ability to implement cost reduction initiatives.

Any forward-looking statement speaks only as of the date on which it is made, and except as may be required by law, 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. You should not unduly rely on such forward-looking statements.

INDUSTRY AND MARKET INFORMATION

The industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT, the PUCT and NYMEX. We did not commission any of these publications or reports. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly, while we believe that such internal and external research is reliable, it has not been verified by any independent sources, and we make no assurances that the predictions contained therein are accurate.

 

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Item 4.

CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect as of the end of the current period included in this quarterly report. Based on the evaluation performed, our management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective. During the most recent fiscal quarter covered by this quarterly report, there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

 

Item 1.

LEGAL PROCEEDINGS

Reference is made to the discussion in Note 7 to Financial Statements regarding legal proceedings.

 

Item 1A.

RISK FACTORS

There have been no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A of the 2009 Form 10-K, except for the risk factors discussed below and the information disclosed elsewhere in this Form 10-Q that provides factual updates to risk factors contained in the 2009 Form 10-K.

Our substantial leverage could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry, expose us to interest rate risk to the extent of our variable rate debt and prevent us from meeting obligations under the various debt agreements governing our indebtedness.

We are highly leveraged. As of June 30, 2010, EFH Corp.’s consolidated principal amount of debt (short-term borrowings and long-term debt, including amounts due currently) totaled $38.620 billion (see Note 6 to Financial Statements). Our substantial leverage could have important consequences, including:

 

•

making it more difficult for us to make payments on our indebtedness;

 

•

requiring a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on indebtedness, therefore reducing our ability to use our cash flow to fund operations, capital expenditures and future business opportunities and execute our strategy;

 

•

increasing our vulnerability to adverse economic, industry or competitive developments;

 

•

exposing us to the risk of increased interest rates because, as of June 30, 2010, taking into consideration interest rate swap transactions, 11% of our total long-term debt portfolio was exposed to variable interest rates;

 

•

limiting our ability to make strategic acquisitions or causing us to make non-strategic divestitures;

 

•

limiting our ability to obtain additional financing for working capital, capital expenditures, product development, debt service requirements, acquisitions and general corporate or other purposes, or to refinance existing debt;

 

•

limiting our ability to adjust to changing market conditions, and

 

•

placing us at a competitive disadvantage compared to competitors who are less highly leveraged and who therefore, may be able to take advantage of opportunities that we cannot due to our substantial leverage.

 

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A substantial amount of this indebtedness is comprised of our indebtedness under the TCEH Senior Secured Facilities, substantially all of which matures in October 2014. We may not be able to refinance the TCEH Senior Secured Facilities or our other existing indebtedness because of our high levels of debt and debt incurrence restrictions under our debt agreements or because of generally adverse conditions in credit markets.

In addition, future transactions and initiatives that we continuously contemplate and may pursue may have significant effects on our business, capital structure, liquidity and/or results of operations. For example, in addition to the exchanges and repurchases of our debt that are described elsewhere in this report, we have and may continue to pursue, from time to time, transactions and initiatives of various types, including, without limitation, other exchange transactions, debt repurchases, equity or debt issuances, asset sales, joint ventures, recapitalizations, business combinations and other strategic transactions. There can be no guarantee that any of such transactions or initiatives would ultimately be successful or produce the desired outcome, which could ultimately affect us in a material and adverse manner. Moreover, the effects of any of these transactions or initiatives could be material and adverse to holders of our debt and could be disproportionate, and directionally different, with respect to one class or type of debt than with respect to others.

Our collateral requirements for hedging arrangements could be materially impacted if the rules implementing the Financial Reform Act broaden the scope of the Act’s provisions regarding the regulation of over-the-counter financial derivatives and make them applicable to us.

In July 2010, the US Congress enacted, and President Obama signed, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act). Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives market. While the legislation is broad and detailed, substantial portions of the legislation will require rulemaking by federal governmental agencies to either implement the standards set out in the legislation or to adopt new standards.

The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we use to hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However, end-users that are non-financial entities using the swap to hedge or mitigate commercial risk are exempt from these clearing requirements. The type of asset-backed OTC derivatives that we use to hedge commodity and interest rate risk should be exempt from the clearing requirements. In addition, existing swaps are grandfathered from the clearing requirements.

The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateral requirements are unclear as to whether an end-user or its counterparty (i.e., swap dealer) is required to post cash collateral, there is risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. However, the legislative history of the Financial Reform Act suggests that it was not Congress’ intent to require end-users (rather that such requirement apply to swap dealers) to post cash collateral with respect to swaps. If we were required to post cash collateral on our swap transactions, our liquidity would likely be materially impacted, and our ability to enter into OTC derivatives to hedge our commodity and interest rate risks would be significantly limited.

We cannot predict the outcome of the rulemaking to implement the OTC derivative market provisions of the Financial Reform Act. This rulemaking could negatively affect our ability to hedge our commodity and interest rate risks. The inability to hedge these risks would likely have a material adverse effect on our results of operations, financial condition or cash flows.

 

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Our financial condition and results of operations may be materially adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change.

In recent years, a growing concern has emerged about global climate change and how greenhouse gas (GHG) emissions, such as carbon dioxide, contribute to global climate change. Several bills addressing climate change have been introduced in the US Congress or discussed by the Obama Administration that are intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), incentives for the development of low-carbon technology and federal renewable portfolio standards. In addition, a number of federal court cases have been recently decided that could result in the future judicial regulation of GHG emissions.

The EPA recently issued a rule, known as the Prevention of Significant Deterioration (PSD) tailoring rule, that establishes new thresholds for regulating GHG emissions from stationary sources under the Clean Air Act. Beginning in January 2011, the rule will require any source subject to the PSD permitting program due to emissions of non-GHG pollutants that increases its GHG emissions by 75,000 tons per year (tpy) to have an operating permit under the Title V Operating Permit Program of the Clean Air Act and install the best available control technology in conjunction with construction activities or plant modifications. Beginning in July 2011, PSD permitting requirements will also apply to new projects with GHG emissions of at least 100,000 tpy and modifications to existing facilities that increase GHG emissions by at least 75,000 tpy (even if no non-GHG PSD thresholds are exceeded). The EPA also finalized regulations in 2009 that will require certain categories of GHG emitters to monitor and report their annual GHG emissions beginning in January 2011.

We produce GHG emissions from the combustion of fossil fuels at our generation facilities. For 2009, we estimate that our generation facilities produced 54 million short tons of carbon dioxide based on continuously monitored data reported to and approved by the EPA. The two new lignite-fueled units that achieved substantial completion (as defined in the EPC Agreement for the units) in 2009 and the one new lignite-fueled unit that achieved substantial completion (as defined in the EPC Agreement for the unit) in June 2010 will generate additional carbon dioxide emissions. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our financial condition and results of operations could be materially adversely affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes upon those that produce GHG emissions. For example, to the extent a cap-and-trade program is adopted, we may be required to incur material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with such a program. The EPA regulation of GHGs under the Clean Air Act, or judicially imposed limits on GHG emissions, may require us to make material expenditures to reduce our GHG emissions. If a significant number of our investors, customers or others refuse to do business with us because of our GHG emissions, it could have a material adverse effect on our results of operations, financial condition or cash flows.

 

Item 5.

OTHER INFORMATION

Mr. Paul Keglevic, EFH Corp.’s Chief Financial Officer, recently forfeited his rights to the deferred shares granted to him in July 2008. Additionally, on July 28, 2010, the Organization and Compensation Committee of the Board of Directors of EFH Corp. approved certain changes to Mr. Keglevic’s compensation arrangement. Pursuant to the new arrangement, Mr. Keglevic will receive 225,000 shares of EFH Corp.’s common stock if he is employed by EFH Corp. on September 30, 2012. If Mr. Keglevic’s employment with EFH Corp. terminates for any reason prior to September 30, 2012 (other than for “cause” or without “good reason”), he will also be entitled to receive the 225,000 shares. If Mr. Keglevic receives the 225,000 shares in accordance with the terms of his new arrangement, he has the right to sell the shares to EFH Corp. for $3,140,000, at any time during the period beginning on September 30, 2012 and ending on the sixtieth business day following his termination of employment (or, in the event Mr. Keglevic receives the shares upon his termination of employment, at any time during the period ending on the sixtieth business day following his termination of employment).

 

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Item 6.

Exhibits

(a) Exhibits filed or furnished as part of Part II are:

 

Exhibits		Previously Filed With File Number*		As Exhibit
(4)		Instruments Defining the Rights of Security Holders, Including Indentures Energy Future Holdings Corp.
4(a)						–		Second Supplemental Indenture, dated as of April 13, 2010, to Indenture, dated as of January 12, 2010, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
4(b)						–		Third Supplemental Indenture, dated as of April 14, 2010, to Indenture, dated as of January 12, 2010, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
4(c)						–		Fourth Supplemental Indenture, dated as of May 21, 2010, to Indenture, dated as of January 12, 2010, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
4(d)						–		Fifth Supplemental Indenture, dated as of July 2, 2010, to Indenture, dated as of January 12, 2010, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
4(e)						–		Sixth Supplemental Indenture, dated as of July 6, 2010, to Indenture, dated as of January 12, 2010, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
4(f)						–		Seventh Supplemental Indenture, dated as of July 7, 2010, to Indenture, dated as of January 12, 2010, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
4(g)		1-12833 Form 8-K (filed July 7, 2010)		99.1		–		Supplemental Indenture, dated as of July 1, 2010, to Indenture (For Unsecured Debt Securities Series P), dated as of November 1, 2004, between Energy Future Holding Corp. and The Bank of New York Mellon (formerly known as The Bank of New York)
4(h)						–		Registration Rights Letter Agreement, dated April 12, 2010, among Energy Future Holdings Corp., the Guarantors named therein and the initial purchasers named therein, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
4(i)						–		Registration Rights Letter Agreement, dated April 13, 2010, among Energy Future Holdings Corp., the Guarantors named therein and the initial purchasers named therein, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020

 

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4(j)						–		Registration Rights Letter Agreement, dated May 20, 2010, among Energy Future Holdings Corp., the Guarantors named therein and the initial purchasers named therein, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
4(k)						–		Registration Rights Letter Agreement, dated July 2, 2010, among Energy Future Holdings Corp., the Guarantors named therein and the initial purchasers named therein, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
4(l)						–		Registration Rights Letter Agreement, dated July 6, 2010, among Energy Future Holdings Corp., the Guarantors named therein and the initial purchasers named therein, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
4(m)						–		Registration Rights Letter Agreement, dated July 7, 2010, among Energy Future Holdings Corp., the Guarantors named therein and the initial purchasers named therein, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020
10		Material Contracts
10(a)						–		Amended and Restated Employment Agreement, effective January 1, 2010, by and between EFH Corporate Services Company, Energy Future Holdings Corp. and Robert C. Walters
10(b)						–		Amended and Restated Employment Agreement, effective January 1, 2010, by and between Luminant Holding Company LLC, Energy Future Holdings Corp. and Mark Allen McFarland
10(c)						–		Amended and Restated Employment Agreement, effective January 1, 2010, by and between TXU Energy Retail Company LLC, Energy Future Holdings Corp. and James A. Burke
10(d)						–		Amended and Restated Employment Agreement, effective January 1, 2010, by and between Luminant Holding Company LLC, Energy Future Holdings Corp. and David A. Campbell
10(e)						–		Employment Agreement, effective January 1, 2010, by and between EFH Corporate Services Company, Energy Future Holdings Corp. and Richard J. Landy
10(f)						–		Employment Agreement, effective January 1, 2010, by and between EFH Corporate Services Company, Energy Future Holdings Corp. and Joel D. Kaplan

 

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31		Rule 13a – 14(a)/15d – 14(a) Certifications
31(a)						–		Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)						–		Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32		Section 1350 Certifications
32(a)						–		Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b)						–		Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(99)		Additional Exhibits.
99(a)						–		Condensed Statement of Consolidated Income – Twelve Months Ended June 30, 2010.
99(b)						–		Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2010 and 2009.
99(c)						–		TCEH Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2010 and 2009.
99(d)						–		Energy Future Intermediate Holding Company LLC Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2010 and 2009.

 

*	Incorporated herein by reference.

 

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

Date: August 2, 2010

 

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