ONCOR ELECTRIC DELIVERY CO LLC - FORM 10-Q

ONCOR ELECTRIC DELIVERY CO LLC - FORM 10-Q - October 27, 2011

Attached files

Attached files

ONCOR ELECTRIC DELIVERY CO LLC Reports

file	filename
EXCEL - IDEA: XBRL DOCUMENT - ONCOR ELECTRIC DELIVERY CO LLC	Financial_Report.xls
EX-99 - CONDENSED STATEMENTS OF CONSOLIDATED INCOME - ONCOR ELECTRIC DELIVERY CO LLC	d237153dex99.htm
EX-32.(A) - SECTION 906 CEO CERTIFICATION - ONCOR ELECTRIC DELIVERY CO LLC	d237153dex32a.htm
EX-31.(A) - SECTION 302 CEO CERTIFICATION - ONCOR ELECTRIC DELIVERY CO LLC	d237153dex31a.htm
EX-32.(B) - SECTION 906 CFO CERTIFICATION - ONCOR ELECTRIC DELIVERY CO LLC	d237153dex32b.htm
EX-31.(B) - SECTION 302 CFO CERTIFICATION - ONCOR ELECTRIC DELIVERY CO LLC	d237153dex31b.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011

— OR —

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

Commission File Number 333-100240

Oncor Electric Delivery Company LLC

(Exact Name of Registrant as Specified in its Charter)


Delaware		75-2967830
(State of Organization)		(I.R.S. Employer Identification No.)

1616 Woodall Rodgers Fwy., Dallas, TX 75202		(214) 486-2000
(Address of Principal Executive Offices)		(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 x 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 x No ¨

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.

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

As of October 27, 2011, 80.03% of the outstanding membership interests in Oncor Electric Delivery Company LLC (Oncor) were directly held by Oncor Electric Delivery Holdings Company LLC and indirectly by Energy Future Holdings Corp., 19.75% of the outstanding membership interests were held by Texas Transmission Investment LLC and 0.22% of the outstanding membership interests were indirectly held by certain members of Oncor’s management and board of directors. None of the membership interests are publicly traded.

TABLE OF CONTENTS


		Page

GLOSSARY			ii

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)

	Condensed Statements of Consolidated Income — Three and Nine Months Ended September 30, 2011 and 2010		1

	Condensed Statements of Consolidated Comprehensive Income — Three and Nine Months Ended September 30, 2011 and 2010		1

	Condensed Statements of Consolidated Cash Flows — Nine Months Ended September 30, 2011 and 2010		2

	Condensed Consolidated Balance Sheets — September 30, 2011 and December 31, 2010		3

	Notes to Condensed Consolidated Financial Statements		4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		19

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		31

Item 4.	Controls and Procedures		33

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings		34

Item 1A.	Risk Factors		34

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		34

Item 3.	Defaults Upon Senior Securities		34

Item 4.	(Removed and Reserved)		34

Item 5.	Other Information		34

Item 6.	Exhibits		35

SIGNATURE			36

Oncor Electric Delivery Company LLC’s (Oncor) 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 Oncor website at http://www.oncor.com as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on Oncor’s website or available by hyperlink from the 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 Oncor 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 Oncor and its subsidiary occasionally make references to Oncor (or “we,” “our,” “us,” or “the company”) when describing actions, rights or obligations of its subsidiary. These references reflect the fact that the subsidiary is consolidated with Oncor for financial reporting purposes. However, these references should not be interpreted to imply that Oncor is actually undertaking the action or has the rights or obligations of its subsidiary or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or of any other affiliate.

GLOSSARY

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



2010 Form 10-K		Oncor’s Annual Report on Form 10-K for the year ended December 31, 2010

Bondco		Refers to Oncor Electric Delivery Transition Bond Company LLC, a wholly-owned consolidated bankruptcy-remote financing subsidiary of Oncor that has issued securitization (transition) bonds to recover certain regulatory assets and other costs.

CREZ		Competitive Renewable Energy Zone

Deed of Trust		Deed of Trust, Security Agreement and Fixture Filing, dated as of May 15, 2008, made by Oncor to and for the benefit of The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, formerly The Bank of New York), as collateral agent, as amended

EFH Corp.		Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include Oncor and TCEH.

EFH Retirement Plan		Refers to the defined benefit pension plan sponsored by EFH Corp., in which Oncor is a participating subsidiary.

EFIH		Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.

EPA		US Environmental Protection Agency

ERCOT		Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas

ERISA		Employee Retirement Income Security Act of 1974, as amended

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

GWh		gigawatt-hours

Investment LLC		Refers to Oncor Management Investment LLC, a limited liability company and minority membership interest owner (approximately 0.22%) of Oncor, whose managing member is Oncor and whose Class B Interests are owned by certain members of the management team and independent directors of Oncor.

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

Limited Liability Company Agreement		The Second Amended and Restated Limited Liability Company Agreement of Oncor, dated as of November 5, 2008, by and among Oncor Holdings, Texas Transmission and Investment LLC, as amended

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.



Moody’s		Moody’s Investors Services, Inc. (a credit rating agency)

NERC		North American Electric Reliability Corporation

Oncor		Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings, and/or its wholly-owned consolidated bankruptcy-remote financing subsidiary, Bondco, depending on context.

Oncor Holdings		Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIH and the direct majority owner (approximately 80.03%) of Oncor, and/or its subsidiaries, depending on context.

Oncor Plan		Refers to the Oncor Supplemental Retirement Plan.

Oncor Ring-Fenced Entities		Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.

OPEB		other postretirement employee benefits

OPEB plan		Refers to an EFH Corp.-sponsored plan, in which Oncor is a participating subsidiary, that offers certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the company.

OPUC		Texas Office of Public Utility Counsel

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.

REP		retail electric provider

S&P		Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc. (a credit rating agency)

SARs		Stock Appreciation Rights

SARs Plan		Refers to the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan.

SEC		US Securities and Exchange Commission

Sponsor Group		Refers collectively to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co., that have an ownership interest in Texas Holdings.

TCEH		Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of Energy Future Competitive Holdings Company and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context.

TCEQ		Texas Commission on Environmental Quality

TCRF		transmission cost recovery factor

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.

iii



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 EFH Corp.’s subsidiaries or any member of the Sponsor Group.

TRE		Refers to Texas Reliability Entity, Inc., 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.

US		United States of America

VIE		variable interest entity

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

ONCOR ELECTRIC DELIVERY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(millions of dollars)
Operating revenues:
Affiliated	$	309	$	317	$	798	$	839
Nonaffiliated		588		514		1,561		1,397

Total operating revenues		897		831		2,359		2,236


Operating expenses:
Wholesale transmission service		113		102		322		297
Operation and maintenance		168		154		477		460
Depreciation and amortization		190		176		540		507
Provision in lieu of income taxes		94		73		181		156
Taxes other than amounts related to income taxes		107		100		297		287

Total operating expenses		672		605		1,817		1,707


Operating income		225		226		542		529

Other income and deductions:
Other income (Note 10)		8		8		23		28
Other deductions (Note 10)		2		1		7		5
Nonoperating provision in lieu of income taxes		5		6		16		18

Interest income		7		9		25		29

Interest expense and related charges (Note 10)		89		87		265		259


Net income	$	144	$	149	$	302	$	304

See Notes to Financial Statements.

ONCOR ELECTRIC DELIVERY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2010		2011			2010
	(millions of dollars)
Net income	$	144		$	149	$	302		$	304
Other comprehensive income, net of tax effects:
Cash flow hedges — net decrease in fair value of derivatives (net of tax benefit of $17, —, $17 and —) (Note 1)		(30	)		—		(30	)		—

Comprehensive income	$	114		$	149	$	272		$	304

See Notes to Financial Statements.

ONCOR ELECTRIC DELIVERY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
	2011			2010
	(millions of dollars)
Cash flows — operating activities:
Net income	$	302		$	304
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		549			510
Provision in lieu of deferred income taxes — net		227			128
Amortization of investment tax credits		(3	)		(3	)
Other — net		1			—
Changes in operating assets and liabilities:
Deferred advanced metering system revenues (Note 3)		(9	)		11
Other operating assets and liabilities		(196	)		(227	)

Cash provided by operating activities		871			723


Cash flows — financing activities:
Issuance of long-term debt (Note 5)		—			475
Repayments of long-term debt (Note 5)		(76	)		(72	)
Net increase (decrease) in short-term borrowings (Note 4)		176			(188	)
Distributions to members (Note 7)		(80	)		(176	)
Decrease in income tax-related note receivable from TCEH (Note 9)		28			27
Debt discount, financing and reacquisition expenses — net		(2	)		(11	)

Cash provided by financing activities		46			55


Cash flows — investing activities:
Capital expenditures		(945	)		(782	)
Other		(3	)		(14	)

Cash used in investing activities		(948	)		(796	)


Net change in cash and cash equivalents		(31	)		(18	)

Cash and cash equivalents — beginning balance		33			28


Cash and cash equivalents — ending balance	$	2		$	10

See Notes to Financial Statements.

ONCOR ELECTRIC DELIVERY COMPANY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	At September 30, 2011			At December 31, 2010
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	33
Restricted cash — Bondco (Note 10)		68			53
Trade accounts receivable from nonaffiliates — net (Note 10)		329			254
Trade accounts and other receivables from affiliates (Note 9)		215			182
Amounts receivable from members related to income taxes (Note 9)		—			93
Materials and supplies inventories — at average cost		93			96
Prepayments and other current assets		76			77

Total current assets		783			788
Restricted cash — Bondco (Note 10)		16			16
Receivable from nuclear decommissioning trust (Note 9)		188			206
Investments and other property (Note 10)		72			78
Property, plant and equipment — net (Note 10)		10,247			9,676
Goodwill (Note 10)		4,064			4,064
Note receivable due from TCEH (Note 9)		148			178
Regulatory assets — net — Oncor (Note 3)		1,230			1,266
Regulatory assets — net — Bondco (Note 3)		445			516
Other noncurrent assets		92			58

Total assets	$	17,285		$	16,846


LIABILITIES AND MEMBERSHIP INTERESTS

Current liabilities:
Short-term borrowings (Note 4)	$	553		$	377
Long-term debt due currently — Oncor (Note 5)		376			—
Long-term debt due currently — Bondco (Note 5)		117			113
Trade accounts payable		164			125
Amounts payable to EFH Corp. related to income taxes (Note 9)		20			—
Accrued taxes other than amounts related to income		124			133
Accrued interest		60			108
Other current liabilities		163			109

Total current liabilities		1,577			965

Long-term debt, less amounts due currently — Oncor (Note 5)		4,410			4,783
Long-term debt, less amounts due currently — Bondco (Note 5)		472			550
Liability in lieu of deferred income taxes		2,025			1,827
Investment tax credits		29			32
Other noncurrent liabilities and deferred credits (Note 10)		1,592			1,701

Total liabilities		10,105			9,858


Commitments and Contingencies (Note 6)

Membership interests (Note 7):
Capital account — number of interests outstanding 2011 and 2010 — 635,000,000		7,212			6,990
Accumulated other comprehensive loss		(32	)		(2	)

Total membership interests		7,180			6,988

Total liabilities and membership interests	$	17,285		$	16,846

See Notes to Financial Statements.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. SIGNIFICANT ACCOUNTING POLICIES AND BUSINESS

Description of Business

References in this report to “we,” “our,” “us” and “the company” are to Oncor and/or its subsidiary as apparent in the context. See “Glossary” for definition of terms and abbreviations.

We are a regulated electricity transmission and distribution company principally engaged in providing delivery services to REPs, including subsidiaries of TCEH, that sell power in the north-central, eastern and western parts of Texas. Distribution revenues from TCEH represented 34% and 38% of total revenues for the nine months ended September 30, 2011 and 2010, respectively. We are a majority-owned subsidiary of Oncor Holdings, which is a direct, wholly-owned subsidiary of EFIH, a direct, wholly-owned subsidiary of EFH Corp. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. Oncor Holdings owns 80.03% of our membership interests, Texas Transmission owns 19.75% of our membership interests and certain members of our management team and board of directors indirectly own the remaining membership interests through Investment LLC. We are managed as an integrated business; consequently, there are no separate reportable business segments.

Our consolidated financial statements include our wholly-owned, bankruptcy-remote financing subsidiary, Bondco. This financing subsidiary was organized for the limited purpose of issuing certain transition bonds in 2003 and 2004. Bondco issued $1.3 billion principal amount of transition bonds to recover generation-related regulatory asset stranded costs and other qualified costs under an order issued by the PUCT in 2002.

Various “ring-fencing” measures have been taken to enhance our credit quality. These measures serve to mitigate our and Oncor Holdings’ credit exposure to the Texas Holdings Group and to reduce the risk that our assets and liabilities or those of Oncor Holdings would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities. Such measures include, among other things: our sale of a 19.75% equity interest to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; our 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, including TXU Energy and Luminant, 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. We do not bear any liability for debt or contractual obligations of the Texas Holdings Group, and vice versa. Accordingly, our operations are conducted, and our cash flows are managed, independently from the Texas Holdings Group.

Basis of Presentation

Our condensed consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in our 2010 Form 10-K. All adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in our 2010 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year due to seasonality. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Use of Estimates

Preparation of our financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including 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.

Derivative Instruments and Mark-to-Market Accounting

We have from time-to-time entered into derivative instruments to hedge interest rate risk. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, the fair value of the derivative is required to be recognized on the balance sheet as a derivative asset or liability and changes in the fair value recognized in net income, unless criteria for certain exceptions are met. This recognition is referred to as “mark-to-market” accounting.

Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for “hedge accounting,” which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. A cash flow hedge mitigates the risk associated with the variability of the future cash flows related to an asset or liability (e.g., debt with variable interest rate payments), while a fair value hedge mitigates risk associated with fixed future cash flows (e.g., debt with fixed interest rate payments). In accounting for cash flow hedges, derivative assets and liabilities are recorded on the balance sheet at fair value with an offset to other comprehensive income to the extent the hedges are effective. Amounts remain in accumulated other comprehensive income and are reclassified into net income as the related transactions (hedged items) settle and affect net income. If the hedged transaction becomes probable of not occurring, hedge accounting is discontinued and the amount recorded in other comprehensive income is immediately reclassified into net income. Fair value hedges are recorded as derivative assets or liabilities with an offset to net income, and the carrying value of the related asset or liability (hedged item) is adjusted for changes in fair value with an offset to net income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or loss associated with the hedge is amortized into income over the remaining life of the hedged item. To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedged item. Assessment of the hedge’s effectiveness is tested at least quarterly throughout its term to continue to qualify for hedge accounting. Hedge ineffectiveness, even if the hedge continues to be assessed as effective, is immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the change in value of the hedging instrument over the change in value of the hedged item.

At September 30, 2011, we had entered into an interest rate hedge transaction. The estimated fair value of the liability derivatives designated as cash flow hedging instruments totaled $47 million at September 30, 2011, and is reported on our condensed consolidated balance sheet in other current liabilities. Approximately $1 million of the amount reported in accumulated other comprehensive income at September 30, 2011, is expected to be reclassified into net income within twelve months. The fair value of our interest rate derivative is estimated at the lesser of either the call price or the market value as determined by quoted market prices, representing Level 1 valuations under accounting standards related to the determination of fair value.

Reconcilable Tariffs

The PUCT has designated certain tariffs (TCRF, energy efficiency and advanced meter surcharges and charges related to transition bonds) as reconcilable, which means the differences between amounts charged under these tariffs and the related incurred expenses are deferred as either regulatory assets or regulatory liabilities. Accordingly, at prescribed intervals, future tariffs are adjusted to either repay regulatory liabilities or collect regulatory assets.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

2. REGULATORY RATE REVIEWS

2011 Rate Review

In January 2011, we filed a rate review with the PUCT and 203 original jurisdiction cities based on a test year ended June 30, 2010 (PUCT Docket No. 38929). In April 2011, we filed, and the administrative law judges in the rate review granted, a motion requesting abatement of the procedural schedule on the grounds that we and the other parties had reached a Memorandum of Settlement that would settle and resolve all issues in the rate review. We filed a stipulation (including a proposed order and proposed tariffs) in May 2011 that incorporated the Memorandum of Settlement along with pleadings and other documentation (Stipulation) for the purpose of obtaining final approval of the settlement. The terms of the Stipulation include an approximate $137 million base rate increase and additional provisions to address franchise fees (discussed below) and other expenses. Approximately $93 million of the increase became effective July 1, 2011, and the remainder will become effective by January 1, 2012. Under the Stipulation, amortization of regulatory assets will increase by approximately $10 million annually beginning January 1, 2012. The Stipulation did not change our authorized regulatory capital structure of 60% debt and 40% equity or our authorized return on equity of 10.25%. Under the terms of the Stipulation, we cannot file another general base rate review prior to July 1, 2013, but are not restricted from filing wholesale transmission rate, TCRF, distribution-related investment or other rate updates and adjustments permitted by Texas state law and PUCT rules.

In response to concerns raised by PUCT Commissioners at a July 2011 PUCT open meeting regarding the Stipulation, we filed a modified stipulation that removed from the Stipulation a one-time payment to certain cities we serve for retrospective franchise fees (Modified Stipulation). Instead, pursuant to the terms of a separate agreement with certain cities we serve, we will make retrospective franchise fee payments to cities that accepted the terms of the separate agreement. If all cities accept, the payments will total approximately $22 million. Through September 30, 2011, franchise fee payments to cities under the separate agreement totaled $21 million. The payments are subject to refund from the cities or recovery from customers after final resolution of proceedings related to the appeals from our June 2008 rate review filing (discussed below). No other significant terms of the Stipulation were revised. In August 2011, the PUCT issued a final order approving the settlement terms contained in the Modified Stipulation.

Effective July 1, 2011, pursuant to the PUCT’s final order, we no longer recover the cost of wholesale transmission service through base rates, and all wholesale transmission service expenses incurred are reconcilable to revenues billed under the TCRF rider. For this purpose, all wholesale transmission service expenses consist of amounts charged under a PUCT-approved transmission tariff including our own wholesale transmission tariff.

We account for the difference between amounts charged under the TCRF rate and wholesale transmission service expense as a regulatory asset or regulatory liability (under- or over-recovered wholesale transmission service expense (see Note 1)). At September 30, 2011, approximately $25 million was deferred as over-recovered wholesale transmission service expense (see Note 3).

2008 Rate Review

In August 2009, the PUCT issued a final order with respect to our June 2008 rate review filing with the PUCT and 204 cities based on a test year ended December 31, 2007 (PUCT Docket No. 35717), and new rates were implemented in September 2009. In November 2009, the PUCT issued an order on Rehearing that established a new rate class but did not change the revenue requirements. We and four other parties appealed various portions of the rate case final order to a state district court, and oral argument was held in October 2010. In January 2011, the district court signed its judgment reversing the PUCT with respect to two issues: the PUCT’s disallowance of certain franchise fees and the PUCT’s decision that PURA no longer requires imposition of a rate discount for state colleges and universities. We filed an appeal with the Austin Court of Appeals in February 2011 with respect to the issues we appealed to the district court and did not prevail upon, as well as the district court’s decision to reverse the PUCT with respect to discounts for state colleges and universities. All briefing has been completed and the parties are waiting for the Court of Appeals to set a date for oral argument. We are unable to predict the outcome of the appeal.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

3. REGULATORY ASSETS AND LIABILITIES

Recognition of regulatory assets and liabilities and the amortization periods over which they are expected to be recovered or refunded through rate regulation reflect the decisions of the PUCT. Components of the regulatory assets and liabilities are provided in the table below. Amounts not earning a return through rate regulation are noted.


	Remaining Rate Recovery/Amortization Period At September 30, 2011	Carrying Amount
		September 30, 2011		December 31, 2010
Regulatory assets:
Generation-related regulatory assets securitized by transition bonds (a)(f)	5 years	$	562	$	647
Employee retirement costs	4 years		107		63
Employee retirement costs to be reviewed (b)(c)	To be determined		59		75
Employee retirement liability (a)(c)(d)	To be determined		842		910
Self-insurance reserve (primarily storm recovery costs) — net	5 years		227		117
Self-insurance reserve to be reviewed (b)(c)	To be determined		73		135
Securities reacquisition costs (pre-industry restructure)	6 years		50		55
Securities reacquisition costs (post-industry restructure) — net	Terms of related debt		1		1
Recoverable amounts in lieu of deferred income taxes — net	Life of related asset or liability		99		117
Rate case expenses (a)	Largely 3 years		3		6
Rate case expenses to be reviewed (b)(c)	To be determined		9		4
Advanced meter customer education costs (c)	9 years		9		8
Deferred conventional meter depreciation	9 years		96		60
Energy efficiency performance bonus (a)	Not applicable		3		11
Under-recovered wholesale transmission service expense (a)(c)	1 year		—		8

Total regulatory assets			2,140		2,217


Regulatory liabilities:
Nuclear decommissioning cost over-recovery (a)(c)(e)	Not applicable		188		206
Estimated removal costs — net	Life of utility plant		84		28
Committed spending for demand-side management initiatives (a)	2 years		34		53
Deferred advanced metering system revenues	9 years		59		68
Investment tax credit and protected excess deferred taxes	Various		33		39
Over-collection of transition bond revenues (a)(f)	5 years		42		33
Over-recovered wholesale transmission service expense (a)(c)	1 year		25		—
Energy efficiency programs (a)	Not applicable		—		8

Total regulatory liabilities			465		435


Net regulatory asset		$	1,675	$	1,782

(a)	Not earning a return in the regulatory rate-setting process.

(b)	Costs incurred since the period covered under the last rate review.

(c)	Recovery is specifically authorized by statute or by the PUCT, subject to reasonableness review.

(d)	Represents unfunded liabilities recorded in accordance with pension and OPEB accounting standards.

(e)	Offset by an intercompany receivable from TCEH. See Note 9.

(f)

Bondco net regulatory assets of $445 million at September 30, 2011 consisted of $487 million included in generation-related regulatory assets net of the regulatory liability for over-collection of transition bond revenues of $42 million. Bondco net regulatory assets of $516 million at December 31, 2010 consisted of $549 million included in generation-related regulatory assets net of the regulatory liability for over-collection of transition bond revenues of $33 million.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

4. BORROWINGS UNDER CREDIT FACILITIES

At September 30, 2011, we maintained a secured revolving credit facility, as amended on August 4, 2011. Pursuant to the August 2011 amendment we terminated the commitment of a subsidiary of Lehman Brothers Holdings Inc., a lender under the facility, which had filed for bankruptcy and had an approximately $122 million unfunded commitment (net of $10 million of its commitment funded under the credit facility). Following such amendment and until the credit facility’s amendment and restatement in October 2011 (as discussed below), the revolving credit facility had an aggregate borrowing capacity of $1.868 billion to be used for working capital and general corporate purposes, issuances of letters of credit and support for any commercial paper issuances.

At September 30, 2011, we had outstanding borrowings under the credit facility totaling $553 million with an interest rate of 0.52% and outstanding letters of credit totaling $6 million. At December 31, 2010, we had outstanding borrowings under the credit facility totaling $377 million with an interest rate of 0.53% and outstanding letters of credit totaling $6 million. All outstanding borrowings at September 30, 2011 bore interest at LIBOR plus 0.275%, letters of credit bear interest at 0.275%, and a facility fee was payable (at September 30, 2011 at a rate per annum equal to 0.100%) on the commitments under the facility, each based on our current credit ratings.

Subject to the limitations described below, incremental borrowing capacity available under the credit facility at September 30, 2011 and December 31, 2010 was $1.309 billion and $1.495 billion, respectively. The availability at December 31, 2010 excluded $122 million of unfunded commitments from a subsidiary of Lehman Brothers Holdings Inc. that filed for bankruptcy under Chapter 11 of the US Bankruptcy Code.

On October 11, 2011, we amended and restated in its entirety our then-existing $1.868 billion secured revolving credit facility. The restated credit facility provides for up to $2.0 billion aggregate principal amount of borrowings and for requests for increases of up to $500 million, in $100 million increments, provided certain conditions are met. The restated credit facility has a five-year term expiring in 2016 and gives us the option of requesting up to two additional one-year extensions, with such extensions subject to certain conditions and lender approval.

Borrowings under the restated credit facility are, as under the original credit facility, secured equally and ratably with all of our other secured indebtedness by a first priority lien on property we acquired or constructed for the transmission and distribution of electricity, which property is mortgaged under the Deed of Trust. Generally, our indentures and credit facility limit the incurrence of other secured indebtedness except for indebtedness secured equally and ratably with the indentures and credit facility and certain permitted exceptions. As described further in Note 7 to Financial Statements included in our 2010 Form 10-K and Note 5 below, the Deed of Trust permits us to secure indebtedness (including borrowings under our credit facility) with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the fair value of certain property additions that could be certified to the Deed of Trust collateral agent. At each of September 30, 2011 and October 11, 2011, the credit facility could be fully drawn.

Loans under the restated credit facility bear interest at per annum rates equal to, at our option, (i) LIBOR plus a spread ranging from 1.00% to 1.75% depending on certain credit ratings assigned to our senior secured non-credit enhanced long-term debt or (ii) an alternate base rate (the highest of (1) the prime rate of JPMorgan Chase, (2) the federal funds effective rate plus 0.50%, and (3) daily one-month LIBOR plus 1%). Based on our ratings as of October 11, 2011, our LIBOR-based borrowings bear interest at LIBOR plus 1.125%.

An unused commitment fee is payable quarterly in arrears and upon termination or commitment reduction at a rate per annum equal to 0.100% to 0.275% (such spread depending on certain credit ratings assigned to our senior secured debt) of the daily average unused commitments under the restated credit facility. Based on our ratings as of October 11, 2011, our unused commitment fee is 0.125%. Letter of credit fees on the stated amount of letters of credit issued under the restated credit facility are payable to the lenders quarterly in arrears and upon termination at a rate per annum equal to the spread over adjusted LIBOR. Customary fronting and administrative fees are also payable to letter of credit fronting banks.

The restated credit facility, similar to the original credit facility, contains customary covenants for facilities of this type, restricting, subject to certain exceptions, us and our subsidiaries from, among other things: incurring additional liens; entering into mergers and consolidations; and sales of substantial assets. In addition, the restated credit facility requires that we maintain a consolidated senior debt to capitalization ratio of no greater than 0.65 to 1.00 and observe certain customary reporting requirements and other affirmative covenants.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The restated credit facility also contains customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments, including certain changes in control that are not permitted transactions, cross-default provisions in the event we or any of our subsidiaries (other than Bondco) defaults on indebtedness in a principal amount in excess of $100 million or receives judgments for the payment of money in excess of $50 million that are not discharged within 60 days.

5. LONG-TERM DEBT

At September 30, 2011 and December 31, 2010, our long-term debt consisted of the following:


	September 30, 2011			December 31, 2010
Oncor (a):
6.375% Fixed Senior Notes due May 1, 2012	$	376		$	376
5.950% Fixed Senior Notes due September 1, 2013		524			524
6.375% Fixed Senior Notes due January 15, 2015		500			500
5.000% Fixed Senior Notes due September 30, 2017		324			324
6.800% Fixed Senior Notes due September 1, 2018		550			550
5.750% Fixed Senior Notes due September 30, 2020		126			126
7.000% Fixed Debentures due September 1, 2022		800			800
7.000% Fixed Senior Notes due May 1, 2032		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
7.500% Fixed Senior Notes due September 1, 2038		300			300
5.250% Fixed Senior Notes due September 30, 2040		475			475
Unamortized discount		(39	)		(42	)
Less amount due currently		(376	)		—

Total Oncor		4,410			4,783


Oncor Electric Delivery Transition Bond Company LLC (b):
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		56			101
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		145			145
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		100			131
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		290			290
Unamortized fair value discount related to transition bonds		(2	)		(4	)
Less amount due currently		(117	)		(113	)

Total Oncor Electric Delivery Transition Bond Company LLC		472			550

Total long-term debt	$	4,882		$	5,333

(a)	Secured by first priority lien on certain transmission and distribution assets equally and ratably with all of Oncor’s other secured indebtedness. See “Deed of Trust Amendment” in Note 7 to Financial Statements included in our 2010 Form 10-K for additional information.

(b)	The transition bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset.

Debt Repayments in 2011

Repayments of long-term debt in the nine months ended September 30, 2011 totaled $76 million in scheduled transition bond principal payments.

Fair Value of Long-Term Debt

The estimated fair value of our long-term debt (including current maturities) totaled $6.452 billion and $6.136 billion at September 30, 2011 and December 31, 2010, respectively, and the carrying amount totaled $5.375 billion and $5.446 billion, respectively. The fair value is estimated at the lesser of either the call price or the market value as determined by quoted market prices, representing Level 1 valuations under accounting standards related to the determination of fair value.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Deed of Trust

As described further in Note 7 to the Financial Statements included in our 2010 Form 10-K, the Deed of Trust permits us to secure indebtedness (including borrowings under our credit facility) with the lien of the Deed of Trust up to (i) the amount of available bond credits, and (ii) the aggregate of 85% of the fair value of certain property additions that could be certified to the Deed of Trust collateral agent.

At September 30, 2011, the amount of available bond credits was $1.177 billion and the amount of future debt that we could secure with property additions, subject to those property additions being certified to the Deed of Trust collateral agent, was $781 million.

6. COMMITMENTS AND CONTINGENCIES

Guarantees

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

We are the lessee under various operating leases that obligate us to guarantee the residual values of the leased assets. At September 30, 2011, both the aggregate maximum amount of residual values guaranteed and the estimated residual recoveries totaled approximately $6 million. These leased assets consist primarily of vehicles used in distribution activities. The average life of the residual value guarantees under the lease portfolio is approximately two years.

In June 2010, for the purpose of obtaining greater access to materials, we guaranteed the repayment of borrowings under a nonaffiliated party’s $20 million credit facility maturing on June 7, 2011. In June 2011, we extended the maturity of the guarantee to December 31, 2011. The nonaffiliated party’s borrowings under the credit facility are limited to inventory produced solely to satisfy the terms of a contract with us. We would be entitled to the related inventory upon repayment of the credit facility (or payment to the nonaffiliated party). At September 30, 2011, the nonaffiliated party had borrowings of approximately $2 million under the facility.

Legal/Regulatory Proceedings

In October 2010, the PUCT established Docket No. 38780 for the remand of Docket No. 20381, the 1999 wholesale transmission charge matrix case. A joint settlement agreement was entered into effective October 6, 2003. This settlement resolves disputes regarding wholesale transmission pricing and charges for the period of January 1997 through August 1999, the period prior to the September 1, 1999 effective date of the legislation that authorized 100% postage stamp pricing for ERCOT wholesale transmission. Since a series of appeals has become final, the 1999 matrix docket has been remanded to the PUCT to address two additional issues.

The first issue is the wholesale transmission transition mechanism for the period of September 1999 through December 1999. The disputed issue is whether the PUCT should have allowed the transition mechanism to continue for the last four months of 1999. The appealing parties (Texas Municipal Power Agency, the City of Denton, the City of Garland and GEUS (formerly known as Greenville Electric Utility System)) argued that the transition mechanism was not authorized in the September 1, 1999 100% postage stamp pricing legislation. Our transmission deficit position was mitigated by approximately $8 million in the last four months of 1999 through the transition mechanism. On October 5, 2011, certain parties filed a proposed settlement of this issue, subject to PUCT approval, in which we would pay approximately $9 million including interest through October 9, 2003. If the PUCT rules adversely and additional interest is added, we estimate our liability could be as high as $11 million. We believe any liability would be appropriate for future recovery through rates.

The second issue is the San Antonio City Public Service Board’s (CPSB) claim that the PUCT did not have the authority to reduce CPSB’s requested Transmission Cost of Service (TCOS) revenue requirement. CPSB’s initial

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

TCOS rate was in effect from 1997 through 2000. Since the period of January 1997 through August 1999 is incorporated in the joint settlement, CPSB’s remaining claim is for the period of September 1999 through December 2000. In January 2011, CPSB made a filing with the PUCT (PUCT Docket No. 39068), seeking an additional $22 million of TCOS revenue, including interest, for the 16-month period. If CPSB prevails, we estimate that we would be responsible for approximately $11 million of the request. We have intervened in the proceeding and, along with several other parties, have filed motions to dismiss CPSB’s request.

At this time, we cannot predict the outcome of these two matters.

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 upon our financial position, results of operations or cash flows. See Note 8 to Financial Statements included in our 2010 Form 10-K for additional information.

7. MEMBERSHIP INTERESTS

Cash Distributions

During 2011, our board of directors declared, and we paid, the following cash distributions to members:


Declaration Date	Payment Date	Amount
October 25, 2011	October 26, 2011	$	65
July 27, 2011	July 28, 2011	$	40
April 27, 2011	April 28, 2011	$	20
February 15, 2011	February 16, 2011	$	20

Distributions are limited to our cumulative net income and may not be paid except to the extent we maintain a required regulatory capital structure, as discussed below. At September 30, 2011, $247 million was eligible to be distributed to our members after taking into account these restrictions (described below).

For the period beginning October 11, 2007 and ending December 31, 2012, our cash distributions (other than distributions of the proceeds of any issuance of limited liability company units) are limited by the Limited Liability Company Agreement and a stipulation agreement with the PUCT to an amount not to exceed our cumulative net income determined in accordance with US GAAP, as adjusted by applicable orders of the PUCT. Such adjustments include the removal of noncash impacts of purchase accounting (to date, consists of removing the effect of the 2008 $860 million goodwill impairment charge and the cumulative amount of net accretion of fair value adjustments) and deducting two specific cash commitments (the $72 million ($46 million after tax) one-time refund to customers in September 2008 and funds spent as part of the $100 million commitment for additional energy efficiency initiatives of which $66 million ($43 million after tax) has been spent through September 30, 2011). The goodwill impairment charge and refund are described in Notes 2 and 3 to Financial Statements included in our 2010 Form 10-K. At September 30, 2011, $337 million was available for distribution to our members under the cumulative net income restriction.

Distributions are further limited by our required regulatory capital structure to 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. At September 30, 2011, our regulatory capitalization ratio was 58.2% debt and 41.8% equity. The PUCT has the authority to determine what types of debt and equity are included in a utility’s debt-to-equity ratio. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes transition bonds issued by Bondco. Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of purchase accounting (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization). At September 30, 2011, $247 million was available for distribution to our members under the capital structure restriction.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Membership Interests

At September 30, 2011, our ownership was as follows: 80.03% held by Oncor Holdings and indirectly by EFH Corp., 19.75% held by Texas Transmission and 0.22% held indirectly by certain members of our management team and board of directors.

The following table presents the changes to membership interests during the nine months ended September 30, 2011:


	Capital Accounts			Accumulated Other Comprehensive Loss			Total Membership Interests
Balance at December 31, 2010	$	6,990		$	(2	)	$	6,988
Net income		302			—			302
Distributions		(80	)		—			(80	)
Net effect of cash flow hedges		—			(30	)		(30	)

Balance at September 30, 2011	$	7,212		$	(32	)	$	7,180

The following table presents the changes to membership interests during the nine months ended September 30, 2010:


	Capital Accounts			Accumulated Other Comprehensive Loss			Total Membership Interests
Balance at December 31, 2009	$	6,849		$	(2	)	$	6,847
Net income		304			—			304
Distributions		(176	)		—			(176	)

Balance at September 30, 2010	$	6,977		$	(2	)	$	6,975

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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

We are a participating employer in the EFH Retirement Plan and also participate with EFH Corp. and other subsidiaries of EFH Corp. to offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees.

We also participated in an EFH Corp. supplemental retirement plan for certain employees, whose retirement benefits cannot be fully earned under the qualified EFH Retirement Plan. We ceased participation in the EFH Corp. supplemental retirement plan and implemented the Oncor Plan effective January 1, 2010. The assets held in the EFH Corp. supplemental retirement plan attributable to Oncor employees have been transferred to the Oncor Plan.

Our net direct and indirect allocated pension and OPEB costs related to EFH Corp.’s plans and net pension costs related to the Oncor Plan for the three and nine months ended September 30, 2011 and 2010 are comprised of the following:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Components of net allocated pension costs:
Service cost	$	5		$	4		$	15		$	14
Interest cost		27			26			83			80
Expected return on assets		(25	)		(24	)		(75	)		(72	)
Amortization of net loss		16			10			48			28

Net pension costs		23			16			71			50

Components of net OPEB costs:
Service cost		2			2			6			4
Interest cost		14			13			40			39
Expected return on assets		(4	)		(3	)		(10	)		(11	)
Transition obligation		1			1			1			1
Prior service cost		(1	)		(1	)		(1	)		(1	)
Amortization of net loss		7			5			19			15

Net OPEB costs		19			17			55			47

Total net pension and OPEB costs		42			33			126			97
Less amounts deferred principally as a regulatory asset or property		33			24			99			68

Net amounts recognized as expense	$	9		$	9		$	27		$	29

The discount rates reflected in net pension and OPEB costs in 2011 are 5.50% and 5.55%. The expected rates of return on pension and OPEB plan assets reflected in the 2011 cost amounts are 7.7% and 7.1%, respectively.

We made cash contributions to EFH Corp.’s pension and OPEB plans and the Oncor Plan of $172 million, $13 million and $2 million, respectively, during the nine months ended September 30, 2011, and expect to make additional cash contributions to EFH Corp.’s OPEB plan and the Oncor Plan of $5 million and $1 million, respectively, in the remainder of 2011.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

9. RELATED–PARTY TRANSACTIONS

The following represent significant related-party transactions of Oncor:

•

We record revenue from TCEH, principally for electricity delivery fees, which totaled $309 million and $317 million for the three months ended September 30, 2011 and 2010, respectively, and $798 million and $839 million for the nine months ended September 30, 2011 and 2010, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets at September 30, 2011 and December 31, 2010 reflect receivables from TCEH totaling $175 million and $143 million, respectively, primarily related to these electricity delivery fees.

•

We recognize interest income from TCEH with respect to our generation-related regulatory assets, which have been securitized through the issuance of transition bonds by Bondco. The interest income, which is received on a monthly basis, serves to offset our interest expense on the transition bonds. This interest income totaled $8 million and $9 million for the three months ended September 30, 2011 and 2010, respectively, and $24 million and $28 million for the nine months ended September 30, 2011 and 2010, respectively.

•

Incremental amounts payable related to income taxes as a result of delivery fee surcharges to customers related to transition bonds are reimbursed by TCEH. Our financial statements reflect a note receivable from TCEH of $188 million ($40 million reported as current in trade accounts and other receivables from affiliates) at September 30, 2011 and $217 million ($39 million reported as current in trade accounts and other receivables from affiliates) at December 31, 2010 related to these income taxes. We review economic conditions, TCEH’s credit ratings and historical payment activity to assess the overall collectability of these affiliated receivables. At September 30, 2011, there were no credit loss allowances related to the note receivable from TCEH.

•

EFH Corp. subsidiaries charge us for certain administrative services and shared facilities at cost. These costs, which are primarily reported in operation and maintenance expenses, totaled $10 million for each of the three months ended September 30, 2011 and 2010, and $28 million and $30 million for the nine months ended September 30, 2011 and 2010, respectively.

•

Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility (reported on TCEH’s balance sheet) is funded by a delivery fee surcharge we collect from REPs and remit monthly to TCEH. Delivery fee surcharges totaled $5 million for each of the three months ended September 30, 2011 and 2010, and $13 million and $12 million for the nine months ended September 30, 2011 and 2010, respectively. These trust fund assets are established with the intent to be sufficient to fund the estimated decommissioning liability (also reported on TCEH’s balance sheet). Income and expenses associated with the trust fund and the decommissioning liability recorded by TCEH are offset by a net change in our intercompany receivable/payable, which in turn results in a change in our reported net regulatory asset/liability. The regulatory liability of $188 million and $206 million at September 30, 2011 and December 31, 2010, respectively, represents the excess of the trust fund balance over the net decommissioning liability.

•

We have a 19.5% limited partnership interest, with a carrying value of less than $1 million and $1 million at September 30, 2011 and December 31, 2010, respectively, in an EFH Corp. subsidiary holding principally software-related assets. Equity losses related to this interest are reported in other deductions and totaled less than $1 million and $1 million for the three months ended September 30, 2011 and 2010, respectively, and $1 million and $2 million for the nine months ended September 30, 2011 and 2010, respectively. These losses primarily represent amortization of software assets held by the subsidiary.

•

Under the terms of a tax sharing agreement among us, Oncor Holdings, Texas Transmission, Investment LLC and EFH Corp., we are generally obligated to make payments to Texas Transmission, Investment LLC and EFH Corp., pro rata in accordance with their respective membership interests, in an aggregate amount that is substantially equal to the amount of federal income taxes that we would have been required to pay if we were filing our own corporate income tax return. In addition, consistent with the tax sharing agreement, we remit to EFH Corp. Texas margin tax payments, which are accounted for as income taxes and calculated as if we were filing our own return. Our results are included in the consolidated Texas state margin tax return filed by EFH Corp. At September 30, 2011, we had amounts receivable from members under the agreement totaling $27

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

million ($22 million from EFH Corp. and $5 million from Texas Transmission and Investment LLC), which is due in 2012 and reported as other noncurrent assets and a current tax payable to EFH Corp. of $20 million. At December 31, 2010, we had amounts receivable from members under the agreement totaling $93 million ($72 million from EFH Corp. and $21 million from Texas Transmission and Investment LLC). We received net income tax refunds from members totaling $114 million (including $25 million in federal income tax-related refunds from members other than EFH Corp.) in the nine months ended September 30, 2011 and made net income tax payments of $128 million (including $21 million in federal income tax-related payments to members other than EFH Corp.) in the nine months ended September 30, 2010.

•

At December 31, 2010, we held cash collateral of $4 million from TCEH related to interconnection agreements for generation units being developed by TCEH. The collateral is reported in the balance sheet in other current liabilities. In April 2011, we returned $4 million representing the balance of the collateral and paid approximately $1 million in interest pursuant to PUCT rules related to these interconnection agreements.

•

Our PUCT-approved tariffs include requirements to assure adequate credit worthiness of any REP to support the REP’s obligation to collect transition bond-related charges on behalf of Bondco. 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, at September 30, 2011 and December 31, 2010, TCEH had posted letters of credit in the amount of $13 million and $14 million, respectively, for our benefit.

•

We maintain a revolving credit facility with a syndicate of financial institutions and other lenders. At September 30, 2011, the syndicate included affiliates of GS Capital Partners (a member of the Sponsor Group). In October 2011, we amended and restated the credit facility (see Note 4 for information regarding the amendment and restatement) and neither GS Capital Partners nor its affiliates were members of the syndicate. Affiliates of GS Capital Partners have from time-to-time engaged in commercial banking transactions with us in the normal course of business.

•

Affiliates of the Sponsor Group have, and from time-to-time may in the future (1) sell, acquire or participate in the offerings of our debt or debt securities in open market transactions or through loan syndications, and (2) perform various financial advisory, dealer, commercial banking and investment banking services for us and certain of our affiliates for which they have received or will receive customary fees and expenses. See Note 14 to Financial Statements included in our 2010 Form 10-K for additional information.

See Notes 7 and 8 for information regarding distributions to members and the allocation of EFH Corp.’s pension and OPEB costs to Oncor, respectively.

10. SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Other income:
Accretion of adjustment (discount) to regulatory assets due to purchase accounting	$	7	$	8	$	22	$	26
Other		1		—		1		2

Total other income	$	8	$	8	$	23	$	28

Other deductions:
Professional fees	$	1	$	—	$	3	$	2
Other		1		1		4		3

Total other deductions	$	2	$	1	$	7	$	5

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Major Customers

Distribution revenues from TCEH represented 34% of total operating revenues for each of the three and nine months ended September 30, 2011 and 38% of total operating revenues for each of the three and nine months ended September 30, 2010. Revenues from subsidiaries of one nonaffiliated REP collectively represented 13% of total operating revenues for each of the three and nine months ended September 30, 2011, and 12% of total operating revenues for each of the three and nine months ended September 30, 2010. No other customer represented 10% or more of total operating revenues.

Interest Expense and Related Charges


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011			2010
Interest expense	$	88	$	84	$	263		$	253
Amortization of fair value debt discounts resulting from purchase accounting		—		1		—			2
Amortization of debt issuance costs and discounts		1		2		3			5
Allowance for funds used during construction – capitalized interest portion		—		—		(1	)		(1	)

Total interest expense and related charges	$	89	$	87	$	265		$	259

Restricted Cash

All restricted cash amounts reported on our balance sheet relate to the transition bonds.

Trade Accounts Receivable


	At September 30, 2011			At December 31, 2010
Gross trade accounts receivable	$	499		$	389
Trade accounts receivable from TCEH		(168	)		(133	)
Allowance for uncollectible accounts		(2	)		(2	)

Trade accounts receivable from nonaffiliates – net	$	329		$	254

Gross trade accounts receivable at September 30, 2011 and December 31, 2010 included unbilled revenues of $133 million and $126 million, respectively.

Investments and Other Property

Investments and other property reported on our balance sheet consist of the following:


	At September 30, 2011		At December 31, 2010
Assets related to employee benefit plans, including employee savings programs, net of distributions	$	69	$	74
Investments in unconsolidated affiliates		—		1
Land		3		3

Total investments and other property	$	72	$	78

Property, Plant and Equipment

At September 30, 2011 and December 31, 2010, property, plant and equipment of $10.2 billion and $9.7 billion, respectively, is stated net of accumulated depreciation and amortization of $5.1 billion and $4.8 billion, respectively.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Intangible Assets

Intangible assets other than goodwill reported on our balance sheet are comprised of the following:


	At September 30, 2011						At December 31, 2010
	Gross						Gross
	Carrying		Accumulated				Carrying		Accumulated
	Amount		Amortization		Net		Amount		Amortization		Net
Identifiable intangible assets subject to amortization included in property, plant and equipment:
Land easements	$	231	$	76	$	155	$	201	$	73	$	128
Capitalized software		368		169		199		338		142		196

Total	$	599	$	245	$	354	$	539	$	215	$	324

Aggregate amortization expense for intangible assets totaled $7 million and $10 million for the three months ended September 30, 2011 and 2010, respectively, and $30 million and $28 million for the nine months ended September 30, 2011 and 2010, respectively. The estimated aggregate amortization expense for each of the next five fiscal years from December 31, 2010 is as follows:


Year	Amortization Expense
2011	$	51
2012		37
2013		37
2014		37
2015		37

At both September 30, 2011 and December 31, 2010, goodwill totaling $4.1 billion was reported on our balance sheet. None of this goodwill is being deducted for tax purposes.

Other Noncurrent Liabilities and Deferred Credits

Other noncurrent liabilities and deferred credits balances at September 30, 2011 and December 31, 2010 consist of the following:


	September 30,		December 31,
	2011		2010
Retirement plan and other employee benefits	$	1,448	$	1,560
Uncertain tax positions (including accrued interest)		102		100
Other		42		41

Total other noncurrent liabilities and deferred credits	$	1,592	$	1,701

Supplemental Cash Flow Information


	Nine Months Ended September 30,
	2011			2010
Cash payments (receipts) related to:
Interest	$	311		$	284
Capitalized interest		(1	)		(1	)

Interest (net of amounts capitalized)		310			283
Amounts (refunded) paid in lieu of income taxes		(114	)		128
Noncash investing and financing activities:
Noncash construction expenditures (a)		103			58

(a)	Represents end-of-period accruals.

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

SARs Plan Accrual

In November 2008, we established the SARs Plan under which certain of our executive officers and key employees may be granted stock appreciation rights payable in cash, or in some circumstances, Oncor membership interests. Under the SARs Plan, dividends that are paid in respect of Oncor membership interests while the SARs are outstanding are credited to the SARs holder’s account as if the SARs were units, payable upon the earliest to occur of death, disability, separation from service, unforeseeable emergency, a change in control, or the exercise of the SARs. Prior to the period covered by this report on Form 10-Q, we had not accrued the liability under the SARs Plan related to the declared dividends. We have concluded that the liability related to the declared dividends should be accrued rather than recognized at a future liquidity event. As a result, for the three months ended September 30, 2011, we recorded compensation expense of approximately $6 million relating to dividends since the inception of the SARs Plan ($5 million related to periods prior to January 1, 2011), which management determined was not material. For accounting purposes, the liability is discounted based on an employee’s expected retirement date.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of Oncor’s financial condition and results of operations for the three and nine months ended September 30, 2011 and 2010 should be read in conjunction with the condensed 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 regulated electricity transmission and distribution company principally engaged in providing delivery services to REPs, including subsidiaries of TCEH, that sell power in the north-central, eastern and western parts of Texas. Distribution revenues from TCEH represented 34% and 38% of total revenues for the nine months ended September 30, 2011 and 2010, respectively. We are a majority-owned subsidiary of Oncor Holdings, which is a direct, wholly-owned subsidiary of EFIH, a direct, wholly-owned subsidiary of EFH Corp. Oncor Holdings owns approximately 80.03% of our outstanding membership interests, Texas Transmission owns 19.75% of our outstanding membership interests and certain members of our management team and board of directors indirectly own the remaining outstanding membership interests through Investment LLC. We are managed as an integrated business; consequently, there are no separate reportable business segments.

Significant Activities and Events

Credit Facility Amendments — On August 4, 2011, we amended our then-existing $2.0 billion secured revolving credit facility to terminate the commitment of a subsidiary of Lehman Brothers Holdings Inc., a lender under the facility, which had filed for bankruptcy and had an approximately $122 million unfunded commitment. On October 11, 2011, we amended and restated in its entirety our then-existing $1.868 billion secured revolving credit facility. The restated credit facility provides for up to $2.0 billion aggregate principal amount of borrowings and for requests for increases of up to $500 million, in $100 million increments, provided certain conditions are met. The restated credit facility has a five-year term expiring in 2016 and gives us the option of requesting up to two additional one-year extensions, with such extensions subject to certain conditions and lender approval. Borrowings under the restated credit facility are, as under the original credit facility, secured equally and ratably with all of our other secured indebtedness by a first priority lien on property we acquired or constructed for the transmission and distribution of electricity, which property is mortgaged under the Deed of Trust. See Note 4 to Financial Statements for additional information regarding the restated credit facility.

SARs Plan Accrual — In 2008, we established the SARs Plan under which certain of our executive officers and key employees may be granted stock appreciation rights payable in cash, or in some circumstances, Oncor membership interests. Under the SARs Plan, dividends that are paid in respect of Oncor membership interests while the SARs are outstanding are credited to the SARs holder’s account as if the SARs were units, payable upon the earliest to occur of death, disability, separation from service, unforeseeable emergency, a change in control, or the exercise of the SARs.

Prior to the period covered by this report on Form 10-Q, we had not accrued the liability under the SARs Plan related to the declared dividends. We have concluded that the liability related to the declared dividends should be accrued rather than recognized at a future liquidity event. As a result, for the three months ended September 30, 2011, we recorded compensation expense of approximately $6.0 million relating to dividends accrued on the outstanding SARs since the inception of the SARs Plan ($5.0 million related to periods prior to January 1, 2011), which management determined was not material. For accounting purposes, the liability is discounted based on an employee’s expected retirement date. The $6.9 million of liability relates to approximately $12.6 million of actual dividends accrued as of September 30, 2011 on the outstanding SARs under the SARs Plan, approximately $5.9 million of which are attributable to our named executive officers, including $2.9 million, $0.5 million, $0.5 million, $0.6 million and $0.6 million attributable to Messrs. Shapard, Davis, Clevenger, Jenkins and Ms. Jackson, respectively, who were our named executive officers for the year ended December 31, 2010. Had the dividends been accrued for the years ended December 31, 2010 and 2009, Brenda Pulis, our Senior Vice President, Transmission & Distribution System Operations & Measurement Services, would have been identified as a named executive officer in the 2010 Form 10-K and in the 2009 Form 10-K instead of Brenda L. Jackson, our Senior Vice President and Chief Customer Officer and Don J. Clevenger, our Senior Vice President, External Relations, respectively. Taking into account the approximately $0.8 million attributable to dividends accrued on her outstanding SARs, Ms. Pulis’s total compensation for the years ended December 31, 2010 and 2009 was $1.0 million and $1.1 million, respectively.

Technology Initiatives — We continue 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. Our plans provide for the full deployment of over three million advanced meters to all residential and most non-residential retail electricity customers in our service area by the end of 2012. 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.

At September 30, 2011, we had installed approximately 2,123,000 advanced digital meters, including approximately 609,000 during 2011. As the new meters are integrated, we report 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 through September 30, 2011, for the deployment of the advanced meter system totaled $477 million at including $117 million in 2011.

Matters with the PUCT — For information regarding significant matters with the PUCT, including CREZ-related construction projects and the rate review we filed with the PUCT in January 2011, see discussion below under “Regulation and Rates.”

RESULTS OF OPERATIONS

Operating Data


	Three Months Ended September 30,				%			Nine Months Ended September 30,				%
	2011		2010		Change			2011		2010		Change
Operating statistics:
Electric energy billed volumes (GWh):
Residential		16,098		14,133		13.9			35,382		33,610		5.3
Other (a)		20,365		19,346		5.3			53,244		51,145		4.1

Total electric energy billed volumes		36,463		33,479		8.9			88,626		84,755		4.6


Reliability statistics (b):
System Average Interruption Duration Index (SAIDI) (nonstorm)									108.4		97.9		10.7
System Average Interruption Frequency Index (SAIFI) (nonstorm)									1.3		1.1		18.2
Customer Average Interruption Duration Index (CAIDI) (nonstorm)									85.1		85.6		(0.6	)

Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters)									3,196		3,167		0.9

	Three Months Ended September 30,				$			Nine Months Ended September 30,				$
	2011		2010		Change			2011		2010		Change
Operating revenues:
Distribution base rates	$	548	$	645	$	(97	)	$	1,621	$	1,695	$	(74	)
Reconcilable rates (c)		220		69		151			353		189		164
Advanced metering surcharges		26		18		8			74		53		21
Third-party transmission revenues		87		80		7			260		240		20
Other miscellaneous revenues		16		19		(3	)		51		59		(8	)

Total operating revenues	$	897	$	831	$	66		$	2,359	$	2,236	$	123

(a)	Includes small business, large commercial and industrial and all other non-residential distribution points of delivery.

(b)

SAIDI is the average number of minutes electric service is interrupted per consumer in a year. SAIFI is the average number of electric service interruptions per consumer in a year. CAIDI is the average duration in minutes per electric service interruption in a year. The statistics presented are based on twelve months ended September 30, 2011 and 2010 data.

(c)	Includes transition charge revenue associated with the issuance of securitization bonds totaling $46 million and $43 million for the three months ended September 30, 2011 and 2010, respectively, and $118 million and $121 million for the nine months ended September 30, 2011 and 2010, respectively.

Financial Results — Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Effective July 1, 2011, pursuant to the PUCT’s order (see Note 2 to Financial Statements), we no longer recover the cost of wholesale transmission service expense through distribution base rates, but rather through reconcilable TCRF rates. Primarily due to this rate structure change, reconcilable revenues increased and distribution base rate revenues decreased $154 million in the three months ended September 30, 2011 compared to the same period in 2010. Now, TCRF revenue is recognized as wholesale transmission expense is incurred, thereby removing the impact of seasonal, extreme weather and other factors affecting consumption on revenue and pretax income. Under the current rate structure, revenue recognition for recovery of wholesale transmission expense is expected to be less in the high volume periods, such as the third quarter, and greater in low volume periods than it otherwise would have been under the previous rate structure. Approximately $39 million of third quarter 2011 TCRF billings did not impact pretax income, but it is expected that a significant portion of that amount will be recognized as revenue in the fourth quarter of 2011. The timing of billings to REPs has not changed and cash flows are not affected by the rate structure change. See Note 1 to Financial Statements for accounting treatment of reconcilable tariffs.

Total operating revenues increased $66 million, or 8%, to $897 million in 2011. The increase reflected:

•

an estimated $43 million impact of higher average consumption, primarily due to the effects of significantly warmer weather in the third quarter of 2011 as compared to 2010;

•

a $41 million increase due to higher distribution tariffs (see Note 2 to Financial Statements);

•

an $8 million increase in recognized revenues from the advanced metering deployment surcharge due to increased costs driven by ongoing meter installation and systems development;

•

an estimated $7 million effect of growth in points of delivery;

•

$7 million in higher transmission revenues reflecting rate increases to recover ongoing investment in the transmission system, and

•

a $2 million increase in other reconcilable revenues (energy efficiency surcharges and charges related to transition bonds), which are recognized as actual expenses are incurred;

partially offset by:

•

a $39 million deferral of billings to reconcile TCRF revenues with wholesale transmission expense for the third quarter of 2011, and

•

a $3 million decrease in REP discretionary services and other revenues.

Wholesale transmission service expense increased $11 million, or 11%, to $113 million, due to a 2% increase in volumes and higher fees paid to other transmission entities.

Operation and maintenance expense increased $14 million, or 9%, to $168 million in 2011. The increase included $8 million in higher employee-related costs (attributed to SARs expense), $2 million in higher support services, $1 million in higher transportation and materials costs, $1 million in higher vegetation management expenses and $1 million in higher costs related to advanced meters, which are reflected in revenues above, partially offset by a $1 million decrease in costs related to programs designed to improve customer electricity demand efficiencies (with a corresponding decrease in revenues).

Depreciation and amortization increased $14 million, or 8%, to $190 million in 2011. The increase reflected $11 million attributed to ongoing investments in property, plant and equipment (including $5 million related to advanced meters) and a $3 million increase in amortization of regulatory assets associated with transition bonds (with an offsetting increase in revenues).

Taxes other than amounts related to income taxes increased $7 million, or 7%, to $107 million in 2011. The increase was the result of a $5 million increase in local franchise fees and a $2 million increase in property taxes.

Other income totaled $8 million in both 2011 and 2010 and other deductions totaled $2 million in 2011 and $1 million in 2010. See Note 10 to Financial Statements.

Provision in lieu of income taxes totaled $99 million in 2011 (including $94 million related to operating income and $5 million related to nonoperating income) compared to $79 million (including $73 million related to operating income and $6 million related to nonoperating income) in 2010. The effective income tax rate on pretax income was 40.7% in 2011 and 34.6% in 2010. The increase in the effective tax rate was primarily driven by the reversal in 2010 of interest on uncertain tax positions.

Interest income decreased $2 million, or 22%, to $7 million in 2011. The decrease reflected lower reimbursement of transition bond interest from TCEH due to lower outstanding principal amounts.

Interest expense and related charges increased $2 million, or 2%, to $89 million in 2011. The increase was primarily attributable to higher average interest rates due to the refinancing of short-term borrowings with $475 million of senior notes issued in September 2010.

Net income decreased $5 million, or 3%, to $144 million in 2011. The decrease reflected the impact of the change in rate structure as well as higher operation and maintenance, depreciation and wholesale transmission service expenses and higher income taxes, partially offset by the effects on revenue of higher base rates and significantly warmer weather.

Financial Results — Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Effective July 1, 2011, pursuant to the PUCT’s order (see Note 2 to Financial Statements), we no longer recover the cost of wholesale transmission service expense through distribution base rates, but rather through reconcilable TCRF rates. Primarily due to this rate structure change, reconcilable revenues increased and distribution base rate revenues decreased $154 million in the nine months ended September 30, 2011 compared to the same period in 2010. Now, revenue is recognized as wholesale transmission expense is incurred, thereby removing the impact of seasonal, extreme weather and other factors affecting consumption on revenue and pretax income. Under the current rate structure, revenue recognition for recovery of wholesale transmission expense is expected to be less in the high volume periods, such as the third quarter, and greater in low volume periods than it otherwise would have been under the previous rate structure. Approximately $39 million of third quarter 2011 TCRF billings did not impact pretax income, but it is expected that a significant portion of that amount will be recognized as revenue in the fourth quarter of 2011. The timing of billings to REPs has not changed and cash flows are not affected by the rate structure change. See Note 1 to Financial Statements for accounting treatment of reconcilable tariffs.

Total operating revenues increased $123 million, or 6%, to $2,359 million in 2011. The increase reflected:

•

a $68 million increase due to higher distribution tariffs (see Note 2 to Financial Statements);

•

an estimated $51 million impact of higher average consumption, primarily due to the effects of warmer summer weather in 2011 as compared to 2010;

•

$21 million in higher transmission revenues reflecting rate increases to recover ongoing investment in the transmission system;

•

a $21 million increase in recognized revenues from the advanced metering deployment surcharge due to increased costs driven by ongoing meter installation and systems development, and

•

an estimated $15 million effect of growth in points of delivery;

partially offset by:

•

a $39 million deferral of billings to reconcile TCRF revenues with wholesale transmission expense for the third quarter of 2011;

•

an $8 million decrease in REP discretionary services and other revenues, and

•

a $6 million decrease in other reconcilable revenues (energy efficiency surcharges and charges related to transition bonds), which are recognized as actual expenses are incurred.

Wholesale transmission service expense increased $25 million, or 8%, to $322 million, due to a 2% increase in volumes and higher fees paid to other transmission entities.

Operation and maintenance expense increased $17 million, or 4%, to $477 million in 2011. The increase included $7 million in higher employee-related costs (attributed to SARs expense), $4 million in higher support services, $3 million in higher transportation and materials costs, $2 million in higher vegetation management expenses and $2 million in higher costs related to advanced meters, which are reflected in revenues above, partially offset by a $3 million decrease in costs related to programs designed to improve customer electricity demand efficiencies (with a corresponding decrease in revenues).

Depreciation and amortization increased $33 million, or 7%, to $540 million in 2011. The increase reflected $35 million attributable to ongoing investments in property, plant and equipment (including $16 million related to advanced meters), partially offset by $2 million in lower amortization of regulatory assets associated with transition bonds (with a corresponding decrease in revenues).

Taxes other than amounts related to income taxes increased $10 million, or 3%, to $297 million in 2011. The increase was the result of a $7 million increase in local franchise fees and a $3 million increase in property taxes.

Other income totaled $23 million in 2011 and $28 million in 2010 and other deductions totaled $7 million in 2011 and $5 million in 2010. See Note 10 to Financial Statements.

Provision in lieu of income taxes totaled $197 million in 2011 (including $181 million related to operating income and $16 million related to nonoperating income) compared to $174 million (including $156 million related to operating income and $18 million related to nonoperating income) in 2010. The effective income tax rate on pretax income was 39.5% in 2011 and 36.4% in 2010. The increase in the effective tax rate was primarily driven by the reversal in 2010 of interest on uncertain tax positions.

Interest income decreased $4 million, or 14%, to $25 million in 2011. The decrease reflected lower reimbursement of transition bond interest from TCEH due to lower outstanding principal amounts.

Interest expense and related charges increased $6 million, or 2%, to $265 million in 2011. The increase was driven by $4 million attributable to higher average interest rates due to the refinancing of short-term borrowings with $475 million of senior notes issued in September 2010 and $2 million attributable to higher average borrowings reflecting ongoing capital investments.

Net income decreased $2 million, or 1%, to $302 million in 2011. The decrease reflected the impact of the change in rate structure as well as higher depreciation, wholesale transmission service and operation and maintenance expenses and higher income taxes, partially offset by the effects on revenue of higher base revenue and warmer summer weather.

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows — Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Cash provided by operating activities totaled $871 million and $723 million for the nine months ended September 30, 2011 and 2010, respectively. The primary drivers of the $148 million increase included a $242 million effect of net tax refunds in 2011 compared to net tax payments in 2010 and a $95 million increase in transmission and distribution receipts due to higher rates and increased consumption attributed to the effects of warmer summer weather, partially offset by a $145 million increase in pension and OPEB contributions, a $27 million increase in interest payments due to the issuance of senior notes in September 2010 and the debt exchange transaction in October 2010 and a $23 million increase in materials and supplies inventory levels (primarily CREZ-related).

Cash provided by financing activities totaled $46 million and $55 million for the nine months ended September 30, 2011 and 2010, respectively. The $9 million decrease was driven by a $475 million reduction in the issuance of long-term debt, partially offset by a $364 million increase in short-term borrowings and a $96 million decrease in distributions to our members (see Note 7 to Financial Statements).

Cash used in investing activities, which consisted primarily of capital expenditures, totaled $948 million and $796 million for the nine months ended September 30, 2011 and 2010, respectively. The $163 million increase in capital expenditures was driven by an increase in spending for CREZ investments and infrastructure maintenance, partially offset by decreased spending on other transmission facilities to serve new projects, advanced metering deployment initiatives and general plant.

Depreciation and amortization expense reported in the condensed statements of consolidated cash flows was $9 million and $3 million more than the amounts reported in the condensed statements of consolidated income for the nine months ended September 30, 2011 and 2010, respectively. The differences represent amortization of regulatory assets, offset by the accretion of the adjustment (discount) to regulatory assets, net of the amortization of debt fair value discount, both due to purchase accounting, and reported in other income and interest expense and related charges, respectively, in the condensed statements of consolidated income.

Long-Term Debt Activity — Repayments of long-term debt in the nine months ended September 30, 2011 totaled $76 million in scheduled transition bond principal payments. See Note 5 to Financial Statements for additional information regarding long-term debt.

Available Liquidity/Credit Facility — Our primary source of liquidity, aside from operating cash flows, is our ability to borrow under our revolving credit facility. In August 2011 we amended our then-existing $2.0 billion secured revolving credit facility to terminate the commitment of a subsidiary of Lehman Brothers Holdings Inc., a lender under the facility, which had filed for bankruptcy and had an approximately $122 million unfunded commitment (net of $10 million of its commitment funded under the credit facility). As a result, at September 30, 2011, we had an approximately $1.868 billion aggregate borrowing capacity under such revolving credit facility. Subject to the limitations described below, incremental borrowing capacity available under our revolving credit facility totaled $1.309 billion and $1.495 billion at September 30, 2011 and December 31, 2010, respectively. The availability at December 31, 2010 excludes $122 million of commitments from the subsidiary of Lehman Brothers Holdings Inc. that were removed from the credit facility in August 2011. In October 2011, we amended and restated our existing secured revolving credit facility in its entirety. See Note 4 to Financial Statements for details regarding the restated credit facility.

The availability under our credit facility is limited by the amount of available bond credits and any property additions certified to the Deed of Trust Collateral Agent in connection with credit facility borrowings, as described below.

Cash and cash equivalents totaled $2 million and $33 million at September 30, 2011 and December 31, 2010, respectively. Available liquidity (cash and available credit facility capacity) at September 30, 2011 totaled $1.311 billion reflecting a decrease of $217 million from December 31, 2010. The decrease reflects ongoing capital investment in transmission and distribution infrastructure.

Under the terms of our revolving credit facility (both in its original form and as restated), the commitments of the lenders to make loans to us are several and not joint. Accordingly, if any lender fails to make loans to us, our available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the facility. See Note 4 to Financial Statements for additional information regarding the credit facility.

Liquidity Needs, Including Capital Expenditures — We expect our capital expenditures to total approximately $1.4 billion in 2011, $1.2 billion in 2012 and $1.0 billion in each of the years 2013 through 2016, including amounts related to CREZ construction and voltage support projects totaling approximately $580 million, $560 million, $390 million and $150 million in 2011, 2012, 2013 and 2014, respectively. These capital expenditures are expected to be used for investment in transmission and distribution infrastructure, which is consistent with our commitment to spend a minimum of $3.6 billion in capital expenditures (excluding amounts related to CREZ construction projects) over the five-year period ending December 31, 2012. See Note 3 to Financial Statements included in our 2010 Form 10-K for discussion of this and other commitments in the stipulation approved by the PUCT and “Regulation and Rates” below for discussion of the CREZ projects.

We expect cash flows from operations, combined with availability under the revolving credit facility, to provide sufficient liquidity to fund current obligations, projected working capital requirements, maturities of long-term debt and capital spending for at least the next twelve months. Should additional liquidity or capital requirements arise, we may need to access capital markets or generate equity capital through reductions or suspension of distributions to members. The inability to raise capital on favorable terms or failure of counterparties to perform under credit or other financial agreements, particularly during any uncertainty in the financial markets, could impact our ability to sustain and grow the businesses and would likely increase capital costs that may not be recoverable through rates. See “Regulation and Rates” below for discussion of the CREZ projects.

The revolving credit facility, both in its original form and as restated, contains a debt-to-capital ratio covenant that effectively limits our ability to incur indebtedness in the future. At September 30, 2011, we were in compliance with the covenant. The revolving credit facility and the senior notes and debentures issued by us are secured by the Deed of Trust, which permits us to secure other indebtedness with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the fair value of certain property additions that could be certified to the Deed of Trust collateral agent. At each of September 30, 2011 and October 11, 2011 (the date of the amendment and restatement of the credit facility), the credit facility could be fully drawn.

We also committed to the PUCT that we would maintain a regulatory capital structure 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. At September 30, 2011 and December 31, 2010, our regulatory capitalization ratios were 58.2% debt and 41.8% equity and 59.7% % debt and 40.3% equity, respectively. See Note 7 to Financial Statements for discussion of the debt-to-equity ratio.

Distributions — During 2011, our board of directors declared, and we paid, the following cash distributions to members:


Declaration Date	Payment Date	Amount
October 25, 2011	October 26, 2011	$	65
July 27, 2011	July 28, 2011	$	40
April 27, 2011	April 28, 2011	$	20
February 15, 2011	February 16, 2011	$	20

See Note 7 to Financial Statements for discussion of distribution restriction provisions.

Pension and OPEB Plan Funding — We expect to make cash contributions to EFH Corp.’s pension and OPEB plans and the Oncor Plan of $172 million, $18 million and $3 million, respectively, in 2011. In the nine months ended September 30, 2011, our contributions to EFH Corp.’s pension and OPEB plans and the Oncor Plan totaled $172 million, $13 million and $2 million, respectively.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — Our revolving credit facility contains a financial covenant that requires maintenance of a consolidated senior debt-to-capitalization ratio of no greater than 0.65 to 1.00. For purposes of this ratio, debt is calculated as indebtedness defined in the credit facility (principally, the sum of long-term debt, any capital leases, short-term debt and debt due currently in accordance with US GAAP). The debt calculation excludes transition bonds issued by Bondco, but includes the unamortized fair value discount related to Bondco. Capitalization is calculated as membership interests determined in accordance with US GAAP. At September 30, 2011, we were in compliance with such covenant.

Impact on Liquidity of Credit Ratings — The rating agencies assign credit ratings to certain of our debt securities. Our access to capital markets and cost of debt could be directly affected by our credit ratings. Any adverse action with respect to our credit ratings could generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease. In particular, a decline in credit ratings would increase the cost of our revolving credit facility (as discussed below), other short-term debt issuances and additional or replacement credit facilities. In the event any adverse action with respect to our credit ratings takes place and causes borrowing costs to increase, we may not be able to recover such increased costs if they exceed our PUCT-approved cost of debt determined in our 2008 general rate case or subsequent rate cases.

Many of our large suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions with us. Accordingly, if our credit ratings decline, the costs to operate our business could increase because counterparties could require the posting of collateral in the form of cash-related instruments, or counterparties could decline to do business with us.

The credit ratings assigned for debt securities issued by us at September 30, 2011 are presented below. All three rating agencies have placed our ratings on “stable outlook.”


		Senior Secured
S&P		A-
Moody’s		Baa1
Fitch		BBB+

As described in Note 5 to Financial Statements, all of our long-term debt is currently secured by a first priority lien on certain of our transmission and distribution assets and is considered senior secured debt.

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

Material Credit Rating Covenants — Our revolving credit facility contains terms pursuant to which the interest rates charged under the agreement may be adjusted depending on credit ratings. Prior to the amendment and restatement of our credit facility on October 11, 2011, borrowings under the revolving credit facility ranged from LIBOR plus 0.275% to LIBOR plus 0.800% per annum, depending on certain credit ratings. Borrowings under the restated facility bear interest at per annum rates equal to, at our option, (i) LIBOR plus a spread ranging from 1.00% to 1.75% depending on credit ratings assigned to our senior secured non-credit enhanced long-term debt or (ii) an alternate base rate (the highest of (1) the prime rate of JPMorgan Chase, (2) the federal funds effective rate plus 0.50%, and (3) daily one-month LIBOR plus 1%). Based on our ratings as of October 11, 2011, our LIBOR-based borrowings will bear interest at LIBOR plus 1.125%. A decline in credit ratings would increase the cost of our restated revolving credit facility, other short-term debt issuances and any additional credit facilities.

Material Cross Default Provisions — Certain financing arrangements contain provisions that may result in an event of default if there was a failure under other financing arrangements to meet payment terms or to observe other covenants that could result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.

As of September 30, 2011, a default by us or our subsidiary in respect of indebtedness in a principal amount in excess of $50 million may have resulted in a cross default under our revolving credit facility and the acceleration of outstanding balance. Under the restated revolving credit facility, a default by us or our subsidiary in respect of indebtedness in a principal amount in excess of $100 million or any judgments for the payment of money in excess of $50 million that are not discharged within 60 days may cause the maturity of outstanding balances ($559 million at September 30, 2011, including $6 million in letters of credit) under such facility to be accelerated.

Guarantees — See Note 6 to Financial Statements for details of guarantees.

OFF-BALANCE SHEET ARRANGEMENTS

At September 30, 2011, we did not have any material off-balance sheet arrangements with special purpose entities or VIEs.

COMMITMENTS AND CONTINGENCIES

See Note 6 to Financial Statements for details of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

There have been no recently issued accounting standards effective after September 30, 2011 that are expected to materially impact us.

REGULATION AND RATES

Sunset Review and Other State Legislation

PURA, the PUCT, ERCOT, the TCEQ and the OPUC were 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, ERCOT, the TCEQ and the OPUC), along with an evaluation of the advisability of any changes to that agency’s authorizing legislation (e.g., PURA). During the 2011 legislative session, the Texas Legislature extended the life of the PUCT until 2013, at which time the agency will undergo a limited purpose sunset review, continued ERCOT until the subsequent PUCT sunset review and continued the OPUC and the TCEQ for 12 years.

During the 2011 legislative session, the Texas Legislature passed Senate Bill 1693, which directs the PUCT to adopt a rule that will allow utilities to recover distribution-related investments on an interim basis without the need for a full rate case. At its September 15, 2011 open meeting, the PUCT approved the periodic rate adjustment rule, which allows utilities to file, under certain circumstances, up to four periodic rate adjustments for these distribution investments between rate cases. No other legislation passed during the 2011 legislative session is expected to have a substantial impact on our financial position, results of operations or cash flows.

Matters with the PUCT

2011 Rate Review Filing — In January 2011, we filed a rate review with the PUCT and 203 original jurisdiction cities based on a test year ended June 30, 2010 (PUCT Docket No. 38929). In April 2011, we filed, and the administrative law judges in the rate review granted, a motion requesting abatement of the procedural schedule on the grounds that we and the other parties had reached a Memorandum of Settlement that would settle and resolve all issues in the rate review. We filed a stipulation (including a proposed order and proposed tariffs) in May 2011 that incorporated the Memorandum of Settlement along with pleadings and other documentation (Stipulation) for the purpose of obtaining final approval of the settlement. The terms of the Stipulation include an approximate $137 million base rate increase and additional provisions to address franchise fees (discussed below) and other expenses. Approximately $93 million of the increase became effective July 1, 2011, and the remainder will become effective by January 1, 2012. Under the Stipulation, amortization of regulatory assets will increase by approximately $10 million annually beginning January 1, 2012. The Stipulation did not change our authorized regulatory capital structure of 60% debt and 40% equity or our authorized return on equity of 10.25%. Under the terms of the Stipulation, we cannot file another general base rate review prior to July 1, 2013, but are not restricted from filing wholesale transmission rate, TCRF, distribution-related investment or other rate updates and adjustments permitted by Texas state law and PUCT rules.

In response to concerns raised by PUCT Commissioners at a July 2011 PUCT open meeting regarding the Stipulation, we filed a modified stipulation that removed from the Stipulation a one-time payment to certain cities we serve for retrospective franchise fees (Modified Stipulation). Instead, pursuant to the terms of a separate agreement with certain cities we serve, we will make retrospective franchise fee payments to cities that accept the terms of the separate agreement. If all cities accept, the payments will total approximately $22 million. Through September 30, 2011, franchise fee payments to cities under the separate agreement totaled $21 million. The payments are subject to refund from the cities or recovery from customers after final resolution of proceedings related to the appeals from our June 2008 rate review filing (discussed below). No other significant terms of the Stipulation were revised. In August 2011, the PUCT issued a final order approving the settlement terms contained in the Modified Stipulation.

2008 Rate Review Filing — In August 2009, the PUCT issued a final order with respect to our June 2008 rate review filing with the PUCT and 204 cities based on a test year ended December 31, 2007 (PUCT Docket No. 35717), and new rates were implemented in September 2009. In November 2009, the PUCT issued an order on Rehearing that established a new rate class but did not change the revenue requirements. We and four other parties appealed various portions of the rate case final order to a state district court, and oral argument was held in October 2010. In January 2011, the district court signed its judgment reversing the PUCT with respect to two issues: the PUCT’s disallowance of certain franchise fees and the PUCT’s decision that PURA no longer requires imposition of a rate discount for state colleges and universities. We filed an appeal with the Austin Court of Appeals in February 2011 with respect to the issues we appealed to the district court and did not prevail upon, as well as the district court’s decision to reverse the PUCT with respect to discounts for state colleges and universities. All briefing has been completed and the parties are waiting for the Court of Appeals to set a date for oral argument. We are unable to predict the outcome of the appeal.

Competitive Renewable Energy Zones (CREZs) — In January 2009, the PUCT awarded us CREZ construction projects (PUCT Docket Nos. 35665 and 37902) requiring 14 related Certificate of Convenience and Necessity (CCN) amendment proceedings before the PUCT for 17 of those projects. All 17 projects and 14 CCN amendments have been approved by the PUCT. The projects involve the construction of transmission lines and stations 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. In addition to these projects, ERCOT completed a study in December 2010 that will result in us and other transmission service providers building additional facilities to provide further voltage support to the transmission grid as a result of CREZ. We currently estimate, based on these additional voltage support facilities and the approved routes and stations for our awarded CREZ projects, that CREZ construction costs will total approximately $2.0 billion. CREZ-related costs could change based on finalization of costs for the additional voltage support facilities and final detailed designs of subsequent project routes. At September 30, 2011, our cumulative CREZ-related capital expenditures totaled $689 million, including $373 million during 2011. We expect that all necessary permitting actions and other requirements and all line and station construction activities for our CREZ construction projects will be completed by the end of 2013 with additional voltage support projects completed by early 2014.

Transmission Interim Rate Update Application (PUCT Docket No. 39644) — In August 2011, we filed an application for an interim update of our wholesale transmission rate. In September 2011, the PUCT Staff recommended approval of the application and the PUCT approved the new rate on October 27, 2011. Annualized revenues are expected to increase by an estimated $35 million with $22 million of this increase recoverable through transmission costs charged to wholesale customers and the remaining $13 million recoverable from REPs through the TCRF component of our delivery rates.

Transmission Cost Recovery and TCRF Rates (PUCT Docket Nos. 38938 and 39456) — In order to recover our wholesale transmission costs, including fees paid to other transmission service providers, we update the TCRF component of our retail delivery rates charged to REPs twice a year. In December 2010, we filed an application to increase the TCRF, which was administratively approved in January 2011 and became effective March 1, 2011. This application is expected to increase annualized revenues by approximately $33 million. In June 2011, we filed an application to increase the TCRF, which became effective September 1, 2011. This application is expected to increase annualized revenues by approximately $48 million. Effective July 1, 2011, charges billed under the TCRF rate became reconcilable (see Note 2 to Financial Statements). The difference between amounts charged under the TCRF rate and the related wholesale transmission service expense is deferred and included in the determination of future TCRF rates (see Note 1 to Financial Statements).

Application for Reconciliation of Advanced Meter Surcharge (PUCT Docket No. 39552) — In July 2011, we filed an application with the PUCT for reconciliation of all costs incurred and investments made through December 31, 2010, in the deployment of our AMS pursuant to our AMS Deployment Plan approved in Docket No. 35718. The order in Docket No. 35718 included a requirement that we file a reconciliation proceeding two years after the implementation of the AMS surcharge. Through the end of 2010, we have spent approximately $357 million in executing the approved AMS Deployment Plan and we billed customers approximately $171 million through the AMS surcharge. We are not seeking a change in the AMS surcharge or the AMS Deployment Plan in this proceeding. On October 7, 2011, we and the other parties to the case filed a proposed order and stipulation, which would resolve all issues in the case. We anticipate that the proceeding will be concluded by the end of 2011.

Application for 2012 Energy Efficiency Cost Recovery Factor (PUCT Docket No. 39375) — In May 2011, we filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2012. PUCT rules require us to make an annual EECRF filing by May 1 (or the first business day in May) for implementation at the beginning of the next calendar year. The requested 2012 EECRF is $54 million as compared to $51 million established for 2011, and would result in a monthly charge for residential customers of $0.99 as compared to the 2011 residential charge of $0.91 per month. On September 14, 2011, we and the other parties to the case filed a proposed order and stipulation, which would resolve all issues in the case. As agreed in the stipulation, the 2012 EECRF is designed to recover $49 million of our costs for the 2012 programs and an $8 million performance bonus based on 2010 results, partially offset by a $3 million reduction for over-recovery of 2010 costs. We anticipate that the PUCT will issue an order by the end of 2011.

Remand of 1999 Wholesale Transmission Matrix Case (PUCT Docket No. 38780) — In October 2010, the PUCT established Docket No. 38780 for the remand of Docket No. 20381, the 1999 wholesale transmission charge matrix case. A joint settlement agreement was entered into effective October 6, 2003. This settlement resolves disputes regarding wholesale transmission pricing and charges for the period of January 1997 through August 1999, the period prior to the September 1, 1999 effective date of the legislation that authorized 100% postage stamp pricing for ERCOT wholesale transmission. Since a series of appeals has become final, the 1999 matrix docket has been remanded to the PUCT to address two additional issues. If the appealing parties prevail and the PUCT rules adversely with respect to the two additional issues, we believe our liabilities, totaling up to approximately $22 million, would be appropriate for recovery through rates. At this time, we cannot predict the outcome of these matters. See Note 6 to Financial Statements for a discussion of this proceeding.

Stipulation Approved by the PUCT — In April 2008, the PUCT entered an order (PUCT Docket No. 34077), which became final in June 2008, approving the terms of a stipulation relating to a filing in 2007 by us and Texas Holdings with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. The filing reported an ownership change involving Texas Holdings’ purchase of EFH Corp. Among other things, the stipulation required us to file a rate case no later than July 1, 2008 based on a test year ended December 31, 2007, which we filed in June 2008 as discussed above. 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 on the appeal was held in June 2010, and the District Court affirmed the PUCT order in its entirety. Nucor Steel appealed that ruling to the Third District Court of Appeals in Austin, Texas in July 2010. Oral argument was held before the court on March 9, 2011. There is no deadline for the court to act. While we are unable to predict the outcome of the appeal, we do not expect the appeal to affect the major provisions of the stipulation.

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 such as interest rates that may be experienced in the ordinary course of business. From time to time, we may transact in financial instruments to hedge interest rate risk related to our debt. All of our long-term debt at September 30, 2011 and December 31, 2010 carried fixed interest rates.

Except as discussed below, the information required hereunder is not significantly different from the information set forth in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” included in our 2010 Form 10-K and is therefore not presented herein.

Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. Our customers consist primarily of REPs. As a prerequisite for obtaining and maintaining certification, a REP must meet the financial resource standards established by the PUCT. Meeting these standards does not guarantee that a REP will be able to perform its obligations. REP certificates granted by the PUCT are subject to suspension and revocation for significant violation of PURA and PUCT rules. Significant violations include failure to timely remit payments for invoiced charges to a transmission and distribution utility pursuant to the terms of tariffs approved by the PUCT. We believe PUCT rules that allow for the recovery of uncollectible amounts due from nonaffiliated REPs significantly reduce our credit risk.

Our exposure to credit risk associated with accounts receivable totaled $175 million from affiliates, substantially all of which consisted of trade accounts receivable from TCEH, and $331 million from nonaffiliated customers at September 30, 2011. The nonaffiliated customer receivable amount is before the allowance for uncollectible accounts, which totaled $2 million at September 30, 2011. The nonaffiliated exposure consists almost entirely of noninvestment grade trade accounts receivable, of which $262 million represented trade accounts receivable from REPs. At September 30, 2011, subsidiaries of one nonaffiliated REP collectively represented approximately 13% of the nonaffiliated trade receivable amount. No other nonaffiliated parties represented 10% or more of the total exposure. We view our exposure to this customer to be within an acceptable level of risk tolerance considering PUCT rules and regulations; however, this concentration increases the risk that a default would have a material effect on cash flows.

At September 30, 2011, we were exposed to credit risk associated with the note receivable from TCEH totaling $188 million ($40 million reported as current in trade accounts and other receivables from affiliates) and amounts receivable from members under the tax sharing agreement totaling $27 million ($22 million from EFH Corp.).

See Note 9 to Financial Statements for additional information.

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 facilities, market and industry developments and the growth of our business 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 discussion under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2010 Form 10-K and Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report and the following important factors, among others, that could cause actual results to differ materially from those projected in such forward-looking statements:

•

prevailing governmental policies and regulatory actions, including those of the US Congress, the Texas Legislature, the Governor of Texas, the FERC, the PUCT, the NERC, the TRE, the EPA, and the TCEQ, with respect to:

•

allowed rate of return;

•

permitted capital structure;

•

industry, market and rate structure;

•

recovery of investments;

•

acquisition and disposal of assets and facilities;

•

operation and construction of facilities;

•

changes in tax laws and policies, and

•

changes in and compliance with environmental, reliability and safety laws and policies;

•

legal and administrative proceedings and settlements;

•

weather conditions and other natural phenomena;

•

acts of sabotage, wars or terrorist activities;

•

economic conditions, including the impact of a recessionary environment;

•

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

•

changes in business strategy, development plans or vendor relationships;

•

unanticipated changes in interest rates or rates of inflation;

•

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

•

inability of various counterparties to meet their financial obligations to us, including failure of counterparties to perform under agreements;

•

general industry trends;

•

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

•

changes in technology used by and services offered by us;

•

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

•

changes in assumptions used to estimate costs of providing employee benefits, including pension and OPEB, and future funding requirements related thereto;

•

significant changes in critical accounting policies material to us;

•

commercial bank and financial market conditions, access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in the capital markets and the potential impact of disruptions in US credit markets;

•

circumstances which may contribute to future impairment of goodwill, intangible or other long-lived assets;

•

financial restrictions under our revolving credit facility and indentures governing our debt instruments;

•

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

•

actions by credit rating agencies, and

•

our ability to effectively execute our operational strategy.

Any forward-looking statement speaks only at 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. As such, you should not unduly rely on such forward-looking statements.

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 at the end of the current period included in this 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 report, no changes in internal controls over financial reporting have occurred that have materially affected, or are 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 6 to Financial Statements regarding legal and regulatory proceedings.

ITEM 1A.

RISK FACTORS

We believe that there have been no material changes to the risks disclosed in the 2010 Form 10-K, including under the heading “Risk Factors” in Item 1A of the 2010 Form 10-K, except for information disclosed elsewhere in this Form 10-Q that provides factual updates to risks contained in the 2010 Form 10-K. The risks disclosed in the 2010 Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.

(REMOVED AND RESERVED)

ITEM 5.

OTHER INFORMATION

None.

ITEM 6.

EXHIBITS

(a) Exhibits provided as part of Part II are:


Exhibits	Previously Filed With File Number	As Exhibit

(10)	Material Contracts.

10(a)	333-100240 Form 8-K (filed October 11, 2011)	10.1	—	Amended and Restated Revolving Credit Agreement, dated as of October 11, 2011, among Oncor Electric Delivery Company LLC, as borrower, the lenders listed therein, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., as swingline lender, and JPMorgan Chase Bank, N.A., Barclays Bank PLC, The Royal Bank of Scotland plc, Bank of America, N.A. and Citibank, N.A., as fronting banks for letters of credit issued thereunder

10(b)	333-100240 Form 10-Q (filed July 29, 2011)	10(a)	—	Oncor Electric Delivery Company LLC Third Amended and Restated Executive Annual Incentive Plan

(31)	Rule 13a - 14(a)/15d - 14(a) Certifications.

31(a)			—	Certification of Robert S. Shapard, chairman of the board and chief executive of Oncor Electric Delivery Company LLC, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31(b)			—	Certification of David M. Davis, senior vice president and chief financial officer of Oncor Electric Delivery Company LLC, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

(32)	Section 1350 Certifications.

32(a)			—	Certification of Robert S. Shapard, chairman of the board and chief executive of Oncor Electric Delivery Company LLC, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32(b)			—	Certification of David M. Davis, senior vice president and chief financial officer of Oncor Electric Delivery Company LLC, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(99)	Additional Exhibits

99			—	Condensed Statements of Consolidated Income – Twelve Months Ended September 30, 2011
	XBRL Data Files

101.INS			—	XBRL Instance Document*

101.SCH			—	XBRL Taxonomy Extension Schema Document*

101.CAL			—	XBRL Taxonomy Extension Calculation Linkbase Document*

101.DEF			—	XBRL Taxonomy Extension Definition Linkbase Document*

101.LAB			—	XBRL Taxonomy Extension Labels Linkbase Document*

101.PRE			—	XBRL Taxonomy Extension Presentation Linkbase Document*

*	Furnished herewith.

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.


ONCOR ELECTRIC DELIVERY COMPANY LLC

By:		/s/ David M. Davis
		David M. Davis
		Senior Vice President and Chief Financial Officer

Date: October 27, 2011

EXHIBIT INDEX


Exhibits	Previously Filed With File Number	As Exhibit

(10)	Material Contracts.

10(a)	333-100240 Form 8-K (filed October 11, 2011)	10.1	—	Amended and Restated Revolving Credit Agreement, dated as of October 11, 2011, among Oncor Electric Delivery Company LLC, as borrower, the lenders listed therein, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., as swingline lender, and JPMorgan Chase Bank, N.A., Barclays Bank PLC, The Royal Bank of Scotland plc, Bank of America, N.A. and Citibank, N.A., as fronting banks for letters of credit issued thereunder

10(b)	333-100240 Form 10-Q (filed July 29, 2011)	10(a)	—	Oncor Electric Delivery Company LLC Third Amended and Restated Executive Annual Incentive Plan

(31)	Rule 13a - 14(a)/15d - 14(a) Certifications.

31(a)			—	Certification of Robert S. Shapard, chairman of the board and chief executive of Oncor Electric Delivery Company LLC, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31(b)			—	Certification of David M. Davis, senior vice president and chief financial officer of Oncor Electric Delivery Company LLC, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

(32)	Section 1350 Certifications.

32(a)			—	Certification of Robert S. Shapard, chairman of the board and chief executive of Oncor Electric Delivery Company LLC, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32(b)			—	Certification of David M. Davis, senior vice president and chief financial officer of Oncor Electric Delivery Company LLC, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(99)	Additional Exhibits

99			—	Condensed Statements of Consolidated Income – Twelve Months Ended September 30, 2011
	XBRL Data Files

101.INS			—	XBRL Instance Document*

101.SCH			—	XBRL Taxonomy Extension Schema Document*

101.CAL			—	XBRL Taxonomy Extension Calculation Linkbase Document*

101.DEF			—	XBRL Taxonomy Extension Definition Linkbase Document*

101.LAB			—	XBRL Taxonomy Extension Labels Linkbase Document*

101.PRE			—	XBRL Taxonomy Extension Presentation Linkbase Document*

*	Furnished herewith.

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Smaller reporting company ¨