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, 2012

— 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.

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

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

At October 29, 2012, 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, 2012 and 2011		1
	Condensed Statements of Consolidated Comprehensive Income — Three and Nine Months Ended September 30, 2012 and 2011		2
	Condensed Statements of Consolidated Cash Flows — Nine Months Ended September 30, 2012 and 2011		3
	Condensed Consolidated Balance Sheets — September 30, 2012 and December 31, 2011		4
	Notes to Condensed Consolidated Financial Statements		5
Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		21
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		34
Item 4.	CONTROLS AND PROCEDURES		36
PART II.	OTHER INFORMATION
Item 1.	LEGAL PROCEEDINGS		37
Item 1A.	RISK FACTORS		37
Item 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		37
Item 3.	DEFAULTS UPON SENIOR SECURITIES		37
Item 4.	MINE SAFETY DISCLOSURES		37
Item 5.	OTHER INFORMATION		37
Item 6.	EXHIBITS		38
SIGNATURE			39

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 quarterly report on Form 10-Q. The representations and warranties contained in any agreement that we have filed as an exhibit to this quarterly report on Form 10-Q or that we have or may publicly file in the future may contain representations and warranties made by and to the parties thereto as of specific dates. Such representations and warranties may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent the parties’ risk allocation in the particular transaction, or may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes.

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.

i

GLOSSARY

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

2011 Form 10-K	Oncor’s Annual Report on Form 10-K for the year ended December 31, 2011
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
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.

ii

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, also referred to herein as the “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)
SEC	US Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
Sponsor Group	Refers collectively to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Management, 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 an entity indirectly owned by a private investment group led by OMERS Administration Corporation, acting through its infrastructure investment entity, Borealis Infrastructure Management Inc., and the Government of Singapore Investment Corporation, acting through its private equity and infrastructure arm, GIC Special Investments Pte Ltd. 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

iv

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,
	2012		2011		2012		2011
	(millions of dollars)
Operating revenues:
Affiliated	$	281	$	309	$	746	$	798
Nonaffiliated		644		588		1,790		1,561
Total operating revenues		925		897		2,536		2,359
Operating expenses:
Wholesale transmission service		123		113		378		322
Operation and maintenance		169		168		495		477
Depreciation and amortization		201		190		577		540
Provision in lieu of income taxes (Note 9)		89		94		198		181
Taxes other than amounts related to income taxes		113		107		313		297
Total operating expenses		695		672		1,961		1,817
Operating income		230		225		575		542
Other income and deductions:
Other income (Note 10)		6		8		20		23
Other deductions (Note 10)		1		2		4		7
Nonoperating provision in lieu of income taxes		3		5		15		16
Interest income		3		7		24		25
Interest expense and related charges (Note 10)		96		89		279		265
Net income	$	139	$	144	$	321	$	302

See Notes to Financial Statements.

1

ONCOR ELECTRIC DELIVERY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
	(millions of dollars)
Net income	$	139	$	144		$	321	$	302
Other comprehensive income:
Cash flow hedges:
Net decrease in fair value of derivatives (net of tax benefit of —, $17, — and $17) (Note 1)		—		(30	)		—		(30	)
Derivative value net loss recognized in net income (net of tax)		1		—			3		—
Comprehensive income	$	140	$	114		$	324	$	272

See Notes to Financial Statements.

2

ONCOR ELECTRIC DELIVERY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2012			2011
	(millions of dollars)
Cash flows — operating activities:
Net income	$	321		$	302
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		600			549
Provision in lieu of deferred income taxes – net		191			227
Amortization of investment tax credits		(3	)		(3	)
Other – net		(1	)		1
Deferred revenues (Note 1)		(96	)		24
Changes in other operating assets and liabilities		(197	)		(229	)
Cash provided by operating activities		815			871
Cash flows — financing activities:
Issuances of long-term debt (Note 5)		900			—
Repayments of long-term debt (Note 5)		(979	)		(76	)
Net increase in short-term borrowings (Note 4)		392			176
Distributions to members (Note 7)		(155	)		(80	)
Decrease in note receivable from TCEH (Note 9)		20			28
Sale of related-party agreements (Note 9)		159			—
Debt discount, financing and reacquisition expenses – net		(45	)		(2	)
Other – net		(1	)		—
Cash provided by financing activities		291			46
Cash flows — investing activities:
Capital expenditures		(1,113	)		(945	)
Other – net		4			(3	)
Cash used in investing activities		(1,109	)		(948	)
Net change in cash and cash equivalents		(3	)		(31	)
Cash and cash equivalents — beginning balance		12			33
Cash and cash equivalents — ending balance	$	9		$	2

See Notes to Financial Statements.

3

ONCOR ELECTRIC DELIVERY COMPANY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2012			December 31, 2011
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	9		$	12
Restricted cash — Bondco (Note 10)		64			57
Trade accounts receivable from nonaffiliates – net (Note 10)		375			303
Trade accounts and other receivables from affiliates (Note 9)		154			179
Amounts receivable from members related to income taxes (Note 9)		—			5
Materials and supplies inventories — at average cost		72			71
Prepayments and other current assets		80			80
Total current assets		754			707
Restricted cash — Bondco (Note 10)		16			16
Receivable from TCEH related to nuclear plant decommissioning (Note 9)		286			225
Investments and other property (Note 10)		78			73
Property, plant and equipment – net (Note 10)		11,191			10,569
Goodwill (Note 10)		4,064			4,064
Note receivable due from TCEH (Note 9)		—			138
Regulatory assets – net — Oncor (Note 3)		1,185			1,078
Regulatory assets — net — Bondco (Note 3)		357			427
Other noncurrent assets		78			74
Total assets	$	18,009		$	17,371
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Short-term borrowings (Note 4)	$	784		$	392
Long-term debt due currently — Oncor (Note 5)		—			376
Long-term debt due currently — Bondco (Note 5)		123			118
Trade accounts payable		111			197
Amounts payable to members related to income taxes (Note 9)		12			—
Accrued taxes other than amounts related to income		130			151
Accrued interest		91			108
Other current liabilities		110			112
Total current liabilities		1,361			1,454
Long-term debt, less amounts due currently — Oncor (Note 5)		5,090			4,711
Long-term debt, less amounts due currently — Bondco (Note 5)		350			433
Liability in lieu of deferred income taxes (Note 9)		2,171			2,018
Investment tax credits		25			28
Other noncurrent liabilities and deferred credits (Note 10)		1,664			1,546
Total liabilities		10,661			10,190
Commitments and Contingencies (Note 6)
Membership interests (Note 7):
Capital account — number of interests outstanding 2012 and 2011 – 635,000,000		7,376			7,212
Accumulated other comprehensive loss		(28	)		(31	)
Total membership interests		7,348			7,181
Total liabilities and membership interests	$	18,009		$	17,371

See Notes to Financial Statements.

4

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

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. Revenues from TCEH represented 29% and 34% of total revenues for the nine months ended September 30, 2012 and 2011, 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, a VIE. 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 the separateness between the Oncor Ring-Fenced Entities and the Texas Holdings Group and 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 2011 Form 10-K. 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 2011 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.

5

From time to time, certain prior period amounts are reclassified to conform to the current period presentation. As disclosed in the condensed statements of consolidated cash flows included in this report, the amount previously reported as changes in deferred advanced metering system revenues for the nine months ended September 30, 2011 is included in and reported as deferred revenues to conform to the current period presentation. In addition to deferred advanced metering system revenues, other reconcilable revenues (TCRF and energy efficiency surcharges), which were previously reported as changes in other operating assets and liabilities, are included in and reported as deferred revenues.

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.

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 each derivative is recognized on the balance sheet as a derivative asset or liability and changes in the fair value are 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.

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 billed 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.

Adoption of New Accounting Standard

In May 2011, the Financial Accounting Standards Board (FASB) issued “Accounting Standards Update 2011-05” relating to the presentation of Comprehensive Income within financial statements. Effective January 1, 2012, we adopted the new standard. Adoption of the new standard did not affect our reported results of operations, financial condition or cash flows.

6

2. REGULATORY MATTERS

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 and the other parties 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 became effective January 1, 2012. Under the Stipulation, amortization of regulatory assets increased by approximately $24 million ($14 million of which will be recognized as tax expense) 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 and 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, through September 30, 2012, we have made approximately $22 million in retrospective franchise fee payments to cities that accepted the terms of the separate agreement. 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 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, 2012, approximately $51 million was deferred as under-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 review 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 Texas Third Court of Appeals (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. Oral argument before the Austin Court of Appeals was completed in April 2012. There is no deadline for the court to act. We are unable to predict the outcome of the appeal.

7

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. Among other things, the stipulation required us to file a rate review no later than July 1, 2008 based on a test year ended December 31, 2007, which we filed in June 2008. The PUCT issued a final order with respect to the rate review in August 2009. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200^th District Court of Travis County, Texas (District Court). 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 Austin Court of Appeals in July 2010. In March 2012, the Austin Court of Appeals affirmed the District Court’s ruling, which is now final.

8

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, 2012	Carrying Amount
		September 30, 2012		December 31, 2011
Regulatory assets:
Generation-related regulatory assets securitized by transition bonds (a)(f)	4 years	$	441	$	531
Employee retirement costs	8 years		91		103
Employee retirement costs to be reviewed (b)(c)	To be determined		96		74
Employee retirement liability (a)(c)(d)	To be determined		808		707
Self-insurance reserve (primarily storm recovery costs) — net	8 years		198		221
Self-insurance reserve to be reviewed (b)(c)	To be determined		121		71
Securities reacquisition costs (pre-industry restructure)	5 years		43		48
Securities reacquisition costs (post-industry restructure) — net	Terms of related debt		29		2
Recoverable amounts in lieu of deferred income taxes — net	Life of related asset or liability		80		104
Rate review expenses (a)	Largely 3 years		7		11
Rate review expenses to be reviewed (b)(c)	To be determined		1		1
Advanced meter customer education costs (c)	8 years		10		9
Deferred conventional meter depreciation	8 years		142		107
Energy efficiency performance bonus (a)	1 year		11		8
Under-recovered wholesale transmission service expense (a)(c)	1 year		51		—
Wholesale transmission settlement costs	Not applicable		—		9
Other regulatory assets	Not applicable		—		1
Total regulatory assets			2,129		2,007
Regulatory liabilities:
Nuclear decommissioning cost over-recovery (a)(c)(e)	Not applicable		286		225
Estimated net removal costs	Life of utility plant		212		115
Committed spending for demand-side management initiatives (a)	1 year		6		25
Deferred advanced metering system revenues	8 years		13		52
Investment tax credit and protected excess deferred taxes	Various		29		33
Over-collection of transition bond revenues (a)(f)	4 years		38		37
Over-recovered wholesale transmission service expense (a)(c)	1 year		—		13
Energy efficiency programs (a)	Not applicable		3		2
Total regulatory liabilities			587		502
Net regulatory asset		$	1,542	$	1,505

(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 $357 million at September 30, 2012 consisted of $395 million included in generation-related regulatory assets net of the regulatory liability for over-collection of transition bond revenues of $38 million. Bondco net regulatory assets of $427 million at December 31, 2011 consisted of $464 million included in generation-related regulatory assets net of the regulatory liability for over-collection of transition bond revenues of $37 million.

9

4. BORROWINGS UNDER CREDIT FACILITIES

At September 30, 2012, we had a $2.4 billion secured revolving credit facility (reflecting a May 2012 $400 million increase as discussed below) to be used for working capital and general corporate purposes, issuances of letters of credit and support for any commercial paper issuances. The revolving credit facility expires in October 2016, and we have the option of requesting up to two one-year extensions, with such extensions subject to certain conditions and lender approval. Pursuant to the terms of our revolving credit facility, we requested and received a $400 million increase in commitments under the revolving credit facility effective May 15, 2012. The terms of the revolving credit facility allow us to request an additional increase in our borrowing capacity of $100 million, provided certain conditions are met, including lender approval.

Borrowings under the revolving credit facility are classified as short-term on the balance sheet and are 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. The property is mortgaged under the Deed of Trust.

At September 30, 2012, we had outstanding borrowings under the revolving credit facility totaling $784 million with an interest rate of 1.47% and outstanding letters of credit totaling $6 million. At December 31, 2011, we had outstanding borrowings under the revolving credit facility totaling $392 million with an interest rate of 1.40% and outstanding letters of credit totaling $6 million. At September 30, 2012, all outstanding borrowings bore interest at LIBOR plus 1.25%, letters of credit bore interest at 1.25%, and a commitment fee (at a rate of 0.175% per annum) was payable on the unfunded commitments under the facility, each based on our current credit ratings. Amounts borrowed under the facility, once repaid, can be borrowed again from time to time.

Subject to the limitations described below, borrowing capacity available under the credit facility at September 30, 2012 and December 31, 2011 was $1.610 billion and $1.602 billion, respectively. Generally, our indentures and revolving credit facility limit the incurrence of other secured indebtedness except for indebtedness secured equally and ratably with the indentures and revolving credit facility and certain permitted exceptions. As described further in Note 7 to Financial Statements included in our 2011 Form 10-K, the Deed of Trust permits us to secure indebtedness (including borrowings under our revolving 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 lower of the fair value or cost of certain property additions that could be certified to the Deed of Trust collateral agent. At September 30, 2012, the available bond credits were approximately $2.141 billion and the amount of additional potential indebtedness that could be secured by property additions, subject to a certification process, was $475 million. At September 30, 2012, the available borrowing capacity of the revolving credit facility could be fully drawn.

10

5. LONG-TERM DEBT

At September 30, 2012 and December 31, 2011, our long-term debt consisted of the following:

	September 30, 2012			December 31, 2011
Oncor (a):
6.375% Fixed Senior Notes due May 1, 2012	$	—		$	376
5.950% Fixed Senior Notes due September 1, 2013		—			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
4.100% Fixed Senior Notes due June 1, 2022		400			—
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
4.550% Fixed Senior Notes due December 1, 2041		300			300
5.300% Fixed Senior Notes due June 1, 2042		500			—
Unamortized discount		(35	)		(38	)
Less amounts due currently		—			(376	)
Total Oncor		5,090			4,711
Oncor Electric Delivery Transition Bond Company LLC (b):
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		10			56
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		30			63
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	)		(3	)
Less amount due currently		(123	)		(118	)
Total Oncor Electric Delivery Transition Bond Company LLC		350			433
Total long-term debt	$	5,440		$	5,144

(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 2011 Form 10-K for additional information.

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

Debt-Related Activity in 2012

Debt Repayments

Repayments of long-term debt in 2012 totaled $979 million and represent $376 million principal amount of 6.375% senior secured notes paid at the scheduled maturity date of May 1, 2012, the redemption of $524 million principal amount of 5.950% senior secured notes due September 1, 2013 (2013 Notes) as discussed below and $79 million principal amount of transition bonds paid at scheduled maturity dates.

In June 2012, pursuant to the terms of the indenture and officer’s certificate governing the 2013 Notes, we redeemed all of the 2013 Notes. We paid a redemption price equal to 100% of the principal amount of the 2013 Notes plus a make-whole amount of $33 million. For accounting purposes, the make-whole amount has been deferred as a regulatory asset and will be amortized to interest expense until September 1, 2013, the original maturity date of the 2013 Notes (see Note 3).

11

Issuance of New Senior Secured Notes

In May 2012, we issued $400 million aggregate principal amount of 4.100% senior secured notes maturing in June 2022 (2022 Notes) and $500 million aggregate principal amount of 5.300% senior secured notes maturing in June 2042 (2042 Notes, and collectively with the 2022 Notes, the Notes). We used the proceeds (net of the initial purchasers’ discount, fees and expenses) of approximately $890 million from the sale of the Notes to repay borrowings under our revolving credit facility, redeem the 2013 Notes (as discussed above) and for other general corporate purposes. The Notes are secured equally and ratably with all of our other secured indebtedness pursuant to the Deed of Trust by a first priority lien on property acquired or constructed for the transmission and distribution of electricity.

Interest on the Notes is payable in cash semiannually in arrears on June 1 and December 1 of each year, beginning on December 1, 2012. We may at our option at any time and from time to time redeem all or part of the Notes at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a make-whole premium. The Notes also contain customary events of default, including failure to pay principal or interest on the Notes when due.

The Notes were issued in a private placement, and in August 2012 we offered holders of the Notes the opportunity to exchange their respective Notes for notes that have terms identical in all material respects to the Notes (Exchange Notes), except that the Exchange Notes do not contain terms with respect to transfer restrictions, registration rights and payment of additional interest for failure to observe certain obligations in a certain registration rights agreement. The Exchange Notes were registered on a Form S-4, which was declared effective in July 2012.

Interest Rate Hedge Transaction

In August 2011, we entered into an interest rate hedge transaction hedging the variability of treasury bond rates used to determine interest rates on an anticipated issuance of senior secured notes (see Note 7 to Financial Statements included in our 2011 Form 10-K for information regarding the debt issuance). The hedges were terminated in November 2011 upon the issuance of the senior secured notes. We recognized the $46 million ($29 million after tax) loss related to the fair value of the hedge transaction in accumulated other comprehensive income, which is expected to be reclassified into net income over the life of the senior secured notes issued.

Fair Value of Long-Term Debt

At September 30, 2012 and December 31, 2011, the estimated fair value of our long-term debt (including current maturities) totaled $6.471 billion and $6.705 billion, respectively, and the carrying amount totaled $5.563 billion and $5.638 billion, respectively. The fair values are estimated based upon market values as determined by quoted market prices, representing Level 1 valuations under accounting standards related to the determination of fair value.

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, 2012, both the aggregate maximum amount of residual values guaranteed and the estimated residual recoveries totaled $7 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 1.7 years.

For the purpose of obtaining greater access to materials, we have guaranteed the repayment of borrowings under a nonaffiliated party’s $5 million credit facility maturing on December 31, 2012. 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, 2012, the nonaffiliated party had no outstanding borrowings under the facility.

12

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. After a series of appeals became final, the 1999 matrix docket was 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. In October 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. The PUCT approved the settlement in January 2012. No appeals were filed prior to the appeals deadline, and the PUCT order became final in February 2012. We made the payment in accordance with the settlement in February 2012. We believe recovery of the settlement payment through future rates is probable.

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 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, of which we would be responsible for approximately $11 million. In late 2011, we intervened in the proceeding and, along with several other parties, filed motions to dismiss CPSB’s request. In January 2012, the PUCT upheld an administrative law judge’s earlier decision to dismiss CPSB’s request. No appeals were filed prior to the appeals deadline, and the PUCT order became final in February 2012.

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 2011 Form 10-K for additional information concerning our legal and regulatory proceedings.

7. MEMBERSHIP INTERESTS

Cash Distributions

On October 24, 2012, our board of directors declared a cash distribution of $70 million to be paid to our members on October 30, 2012. During the nine months ended September 30, 2012, our board of directors declared, and we paid, the following cash distributions to members:

Declaration Date	Payment Date	Amount
July 25, 2012	July 31, 2012	$	50
April 25, 2012	May 1, 2012	$	60
February 14, 2012	February 21, 2012	$	45

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, 2012, $218 million was eligible to be distributed to our members after taking into account these restrictions.

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

13

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 and deducting two specific cash commitments. To date, the noncash impact consists of removing the effect of an $860 million goodwill impairment charge in 2008 and the cumulative amount of net accretion of fair value adjustments. The two specific cash commitments are the $72 million ($46 million after tax) one-time refund to customers in September 2008 and the funds spent as part of the $100 million commitment for additional energy efficiency initiatives of which $94 million ($61 million after tax) has been spent through September 30, 2012. The goodwill impairment charge and refund are described in Notes 2 and 3 to Financial Statements included in our 2011 Form 10-K. At September 30, 2012, $468 million of membership interests was available for distribution 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, 2012, our regulatory capitalization ratio was 58.5% debt and 41.5% 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, 2012, $218 million was available for distribution to our members under the capital structure restriction.

Membership Interests

At September 30, 2012, 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 tables present the changes to membership interests during the nine months ended September 30, 2012 and 2011, respectively:

	Capital Accounts			Accumulated Other Comprehensive Gain (Loss)			Total Membership Interests
Balance at December 31, 2011	$	7,212		$	(31	)	$	7,181
Net income		321			—			321
Distributions		(155	)		—			(155	)
Sale of related-party agreements (net of tax) (Note 9)		(2	)		—			(2	)
Net effects of cash flow hedges (net of tax)		—			3			3
Balance at September 30, 2012	$	7,376		$	(28	)	$	7,348
	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 effects of cash flow hedges (net of tax benefit of —, $17 and $17)		—			(30	)		(30	)
Balance at September 30, 2011	$	7,212		$	(32	)	$	7,180

14

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

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 participate in the Oncor Plan, which is a supplemental retirement plan for certain employees whose retirement benefits cannot be fully earned under the qualified EFH Retirement Plan.

Our net pension and OPEB costs related to the EFH Retirement Plan, the OPEB Plan and the Oncor Plan for the three and nine months ended September 30, 2012 and 2011 were comprised of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Components of net allocated pension costs:
Service cost	$	6		$	5		$	17		$	15
Interest cost		26			27			80			83
Expected return on assets		(28	)		(25	)		(80	)		(75	)
Amortization of net loss		21			16			58			48
Net pension costs		25			23			75			71
Components of net OPEB costs:
Service cost		2			2			4			6
Interest cost		10			14			29			40
Expected return on assets		(3	)		(4	)		(9	)		(10	)
Amortization of net transition obligation		—			1			1			1
Amortization of prior service cost		(5	)		(1	)		(15	)		(1	)
Amortization of net loss		3			7			10			19
Net OPEB costs		7			19			20			55
Total net pension and OPEB costs		32			42			95			126
Amounts deferred principally as a regulatory asset or property		(23	)		(33	)		(68	)		(99	)
Net amounts recognized as expense	$	9		$	9		$	27		$	27

The discount rate reflected in net pension costs for January through July 2012 is 5.00% and for August and September 2012 is 4.15% (see discussion below). The discount rate reflected in net OPEB costs in 2012 is 4.95%. The expected rates of return on pension and OPEB plan assets reflected in the 2012 cost amounts are 7.4% and 6.8%, respectively.

We made cash contributions to the EFH Retirement Plan, the OPEB Plan and the Oncor Plan of $89 million, $8 million and $2 million, respectively, during the nine months ended September 30, 2012, and expect to make additional cash contributions of zero, $3 million and $1 million, respectively, in the remainder of 2012.

In August 2012, EFH Corp. approved certain amendments to the EFH Retirement Plan. These amendments will result in:

• the splitting off of assets and liabilities under the plan associated with our employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (and discontinued businesses) to a new plan that is expected to be sponsored and administered by us;

• maintaining assets and liabilities under the plan associated with active collective bargaining unit employees of EFH Corp.’s competitive subsidiaries under the current plan;

• the splitting off of assets and liabilities under the plan associated with all other plan participants to a terminating plan, and freezing benefits and vesting all accrued plan benefits for these participants, and

• the termination of, distributions of benefits under, and settlement of all of EFH Corp.’s liabilities under the terminating plan.

15

EFH Corp. has informed us that it intends to make cash contributions (currently estimated to aggregate approximately $240 million) to settle the terminating plan obligations and fully fund the EFH Corp. competitive business portion of liabilities (including discontinued businesses) under the new plan expected to be sponsored by us. Of the estimated $240 million cash contribution, EFH Corp. paid $150 million in October 2012 and expects to contribute the remainder in the fourth quarter of 2012.

As a result of the amendments, our plan asset values and obligations were remeasured as of July 31, 2012, resulting in the projected benefit obligation, after consideration of the curtailment of benefits related to the terminating plan participants, increasing by $260 million, the fair value of assets increasing by $105 million and regulatory assets increasing by $155 million as compared to December 31, 2011 values. Assumptions used in the remeasurement included a decrease in the discount rate to 4.15% from 5.00% and no change in the expected return on assets of 7.4% assumed at December 31, 2011. The remeasurement did not materially affect reported pension expense for the three months ended September 30, 2012. Another remeasurement will be performed in the fourth quarter of 2012 upon the splitting off of assets and liabilities, which is not expected to have a material impact on our reported results of operations or financial condition.

In July 2012, the US Congress enacted legislation that includes, among other things, pension funding stabilization provisions. These provisions are expected to reduce required minimum pension plan contributions in the near term, but have no impact on long-term funding levels absent a sustained low interest rate environment. As a result of the new legislation and the effect of the amendments on the EFH Retirement Plan, we estimate our aggregate pension funding for the year 2013 and the 2014 to 2016 period to total $10 million and $330 million, respectively.

9. RELATED–PARTY TRANSACTIONS

The following represent our significant related-party transactions:

• We record revenue from TCEH, principally for electricity delivery fees, which totaled $281 million and $309 million for the three months ended September 30, 2012 and 2011, respectively, and $746 million and $798 million for the nine months ended September 30, 2012 and 2011, respectively. These fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets at September 30, 2012 and December 31, 2011 reflect receivables from TCEH totaling $154 million and $138 million, respectively, primarily related to these electricity delivery fees.

• We recognized interest income from TCEH under an agreement related to our generation-related regulatory assets, which have been securitized through the issuance of transition bonds by Bondco. This interest income, which served to offset our interest expense on the transition bonds, totaled $2 million and $8 million for the three months ended September 30, 2012 and 2011, respectively, and $16 million and $24 million for the nine months ended September 30, 2012 and 2011, respectively. See discussion below regarding the sale to EFIH of this interest reimbursement agreement.

Incremental amounts payable related to income taxes as a result of delivery fee surcharges to customers related to transition bonds were reimbursed by TCEH. Prior to the August 2012 sale to EFIH disclosed below, our financial statements reflected a note receivable from TCEH that totaled $179 million ($41 million reported as current in trade accounts and other receivables from affiliates) at December 31, 2011 related to these income taxes.

In August 2012, we sold to EFIH all future interest reimbursements and the remaining $159 million obligation under the note with TCEH. As a result, EFIH paid, and we received, an aggregate $159 million to assign the agreements. The sale of the related-party agreements was reported as a $2 million (after tax) decrease in total membership interests for the three months ended September 30, 2012 in accordance with accounting rules for related-party matters.

16

• 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-month periods ended September 30, 2012 and 2011 and $27 million and $28 million for the nine months ended September 30, 2012 and 2011, respectively.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility 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-month periods ended September 30, 2012 and 2011, respectively, and $12 million and $13 million for the nine months ended September 30, 2012 and 2011, respectively. These trust fund assets are established with the intent to be sufficient to fund the estimated decommissioning liability (both reported on TCEH’s balance sheet). Income and expenses associated with the trust fund and the decommissioning liability are offset by a net change in our intercompany receivable/payable to TCEH, which in turn results in a change in our reported net regulatory asset/liability. The regulatory liability of $286 million and $225 million at September 30, 2012 and December 31, 2011, respectively, represents the excess of the trust fund balance over the net decommissioning liability (see Note 3).

• We are not a member of EFH Corp.’s consolidated tax group, but EFH Corp.’s consolidated federal income tax return includes EFH Corp.’s portion of our results due to EFH Corp.’s equity ownership in us. 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. EFH Corp. also includes our results in its consolidated Texas state margin tax return, and 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. See discussion in Note 1 to Financial Statements in our 2011 Form 10-K under “Income Taxes.” Under the “in lieu of” tax concept, all in lieu of tax assets and tax liabilities represent amounts that will eventually be settled with our members. At September 30, 2012, we had amounts receivable from Texas Transmission and Investment LLC under the agreement totaling $5 million, which is due in 2012, and a current state income tax payable to EFH Corp. of $17 million. At December 31, 2011, we had amounts receivable from members under the agreement totaling $27 million ($22 million from EFH Corp. and $5 million from Texas Transmission and Investment LLC), which is due in 2012, and a current state income tax payable to EFH Corp. of $22 million, which is reported as a net current tax receivable from members of $5 million. We made net income tax payments totaling $4 million to members in the nine months ended September 30, 2012 (net of a $21 million federal income tax-related refund received from EFH Corp.) and 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.

• 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, 2012 and December 31, 2011, TCEH had posted letters of credit in the amount of $11 million and $12 million, respectively, for our benefit.

• 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 2011 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, respectively.

17

10. SUPPLEMENTARY FINANCIAL INFORMATION

Major Customers

Revenues from TCEH represented 30% and 34% of total operating revenues for the three months ended September 30, 2012 and 2011, respectively, and 29% and 34% of total operating revenues for the nine months ended September 30, 2012 and 2011, respectively. Revenues from REP subsidiaries of a nonaffiliated entity collectively represented 16% and 17% of total operating revenues for the three months ended September 30, 2012 and 2011, respectively, and 15% and 16% of total operating revenues for the nine months ended September 30, 2012 and 2011, respectively. No other customer represented 10% or more of total operating revenues.

Other Income and Deductions

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Other income:
Accretion of fair value adjustment (discount) to regulatory assets due to purchase accounting	$	6	$	7	$	18	$	22
Other		—		1		2		1
Total other income	$	6	$	8	$	20	$	23
Other deductions:
Professional fees	$	—	$	1	$	2	$	3
Other		1		1		2		4
Total other deductions	$	1	$	2	$	4	$	7

Interest Expense and Related Charges

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Interest expense	$	90		$	88	$	275		$	263
Amortization of debt issuance costs and discounts		8			1		11			3
Allowance for funds used during construction – capitalized interest portion		(2	)		—		(7	)		(1	)
Total interest expense and related charges	$	96		$	89	$	279		$	265

Restricted Cash

All restricted cash amounts reported on our balance sheet at September 30, 2012 and December 31, 2011 relate to the transition bonds.

Trade Accounts Receivable

	September 30, 2012			December 31, 2011
Gross trade accounts receivable	$	535		$	436
Trade accounts receivable from TCEH		(158	)		(131	)
Allowance for uncollectible accounts		(2	)		(2	)
Trade accounts receivable from nonaffiliates – net	$	375		$	303

Gross trade accounts receivable at September 30, 2012 and December 31, 2011 included unbilled revenues of $143 million and $127 million, respectively. At September 30, 2012 and December 31, 2011, REP subsidiaries of a nonaffiliated entity collectively represented approximately 14% and 10% of the nonaffiliated trade accounts receivable amount, respectively.

18

Investments and Other Property

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

	September 30, 2012		December 31, 2011
Assets related to employee benefit plans, including employee savings programs, net of distributions	$	75	$	70
Land		3		3
Total investments and other property	$	78	$	73

Property, Plant and Equipment

Property, plant and equipment reported on our balance sheet consisted of the following:

	September 30, 2012		December 31, 2011
Total assets in service	$	15,771	$	15,227
Less accumulated depreciation		5,406		5,203
Net of accumulated depreciation		10,365		10,024
Construction work in progress		811		530
Held for future use		15		15
Property, plant and equipment – net	$	11,191	$	10,569

Intangible Assets

Intangible assets (other than goodwill) reported on our balance sheet consisted of the following:

	September 30, 2012						December 31, 2011
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Identifiable intangible assets subject to amortization included in property, plant and equipment:
Land easements	$	264	$	79	$	185	$	248	$	77	$	171
Capitalized software		399		206		193		378		181		197
Total intangible assets	$	663	$	285	$	378	$	626	$	258	$	368

Aggregate amortization expense for intangible assets totaled $13 million and $7 million for the three months ended September 30, 2012 and 2011, respectively, and $39 million and $30 million for the nine months ended September 30, 2012 and 2011, respectively. The estimated aggregate amortization expense for each of the next five fiscal years from December 31, 2011 is as follows:

Year	Amortization Expense
2012	$	53
2013		55
2014		55
2015		55
2016		52

At both September 30, 2012 and December 31, 2011, goodwill totaling $4.1 billion was reported on our balance sheet. None of this goodwill is being deducted for tax purposes.

19

Other Noncurrent Liabilities and Deferred Credits

Other noncurrent liabilities and deferred credits balances consisted of the following:

	September 30, 2012		December 31, 2011
Retirement plan and other employee benefits	$	1,441	$	1,340
Uncertain tax positions (including accrued interest)		168		147
Other		55		59
Total other noncurrent liabilities and deferred credits	$	1,664	$	1,546

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2012			2011
Cash payments (receipts) related to:
Interest	$	291		$	311
Capitalized interest		(7	)		(1	)
Interest (net of amounts capitalized)	$	284		$	310
Amounts in lieu of income taxes	$	4		$	(114	)
Noncash investing and financing activities:
Noncash construction expenditures (a)	$	78		$	103

(a) Represents end-of-period accruals.

20

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations for the three and nine months ended September 30, 2012 and 2011 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. Revenues from TCEH represented 29% and 34% of total revenues for the nine months ended September 30, 2012 and 2011, 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.

Various “ring-fencing” measures have been taken to enhance the separateness between the Oncor Ring-Fenced Entities and the Texas Holdings Group and 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.

Significant Activities and Events

Sale of Related-Party Agreements — Until August 2012, we were party to two agreements with TCEH related to certain generation-related regulatory assets that were securitized through the issuance of transition bonds by Bondco. One agreement provided for the reimbursement to us by TCEH of our interest expense on the transition bonds, which we recognized as interest income when received. The second agreement consisted of a noninterest bearing note receivable from TCEH to reimburse us for incremental income taxes payable as a result of delivery fee surcharges to customers related to transition bonds.

In August 2012, we sold both agreements to EFIH for an aggregate amount of $159 million. At the time of sale, the remaining principal balance on the note was $159 million, and the remaining interest reimbursements to be received through 2016 totaled $51 million. As a result of the sale of the agreements to EFIH, future interest income is expected to be $6 million, $20 million and $20 million less than it otherwise would have been in the fourth quarter of 2012, the year 2013 and the period 2014 to 2016, respectively. In accordance with accounting rules for related-party matters, we reported the transaction as a decrease in total membership interests totaling $2 million (after tax) for the three months ended September 30, 2012. See Note 9 to Financial Statements for additional information related to the sale to EFIH of our interest and tax reimbursement agreements with TCEH.

21

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 producing electricity service reliability improvements and providing 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. 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, 2012, we had installed approximately 3,104,000 advanced digital meters, including approximately 802,000 during the nine months ended September 30, 2012. 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 for the deployment of the advanced meter system totaled $642 million at September 30, 2012, including $124 million during the nine months ended September 30, 2012. We expect to complete the installation of the advanced meters by the end of 2012.

Revolving Credit Facility and Debt-Related Activities — See Notes 4 and 5 for information regarding a $400 million increase in commitments under the revolving credit facility in May 2012, issuances of $900 million principal amount of senior notes in May 2012 and early redemption of $524 million principal amount of senior secured notes in June 2012.

Matters with the PUCT — For information regarding significant matters with the PUCT, including CREZ-related construction projects, see discussion below under “Regulation and Rates.”

22

RESULTS OF OPERATIONS

Operating Data

	Three Months  Ended September 30,				% Change			Nine Months  Ended September 30,				% Change
	2012		2011					2012		2011
Operating statistics:
Electric energy billed volumes (GWh):
Residential		14,259		16,098		(11.4	)		32,278		35,382		(8.8	)
Other (a)		19,834		20,365		(2.6	)		53,188		53,244		(0.1	)
Total electric energy billed volumes		34,093		36,463		(6.5	)		85,466		88,626		(3.6	)
Reliability statistics (b):
System Average Interruption Duration Index (SAIDI) (nonstorm)									99.0		108.4		(8.7	)
System Average Interruption Frequency Index (SAIFI) (nonstorm)									1.3		1.3		—
Customer Average Interruption Duration Index (CAIDI) (nonstorm)									78.8		85.1		(7.4	)
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of active meters)									3,232		3,196		1.1

	Three Months  Ended September 30,				$ Change			Nine Months  Ended September 30,				$ Change
	2012		2011					2012		2011
Operating revenues:
Distribution base rates	$	526	$	543	$	(17	)	$	1,382	$	1,593	$	(211	)
Reconcilable rates (c)		235		225		10			697		381		316
Advanced metering surcharges		37		26		11			104		74		30
Third-party transmission		100		87		13			296		260		36
Other miscellaneous (d)		27		16		11			57		51		6
Total operating revenues	$	925	$	897	$	28		$	2,536	$	2,359	$	177

(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, 2012 and 2011 data.

(c) Includes TCRF revenues and energy efficiency surcharges. Also includes transition charge revenue associated with the issuance of transition bonds totaling $42 million and $46 million for the three months ended September 30, 2012 and 2011, respectively, and $111 million and $118 million for the nine months ended September 30, 2012 and 2011, respectively.

(d) Includes non-reconcilable rate review expense surcharges, disconnect/reconnect fees, other discretionary revenues for services requested by REPs and other miscellaneous revenues.

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. Now, TCRF revenue is recognized as wholesale transmission expense is incurred, thereby removing the impact of seasonal and 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. In the three and nine months ended September 30, 2012, we recognized $19 million less and $71 million more, respectively, in TCRF revenues than otherwise would have been recognized under the previous rate structure. 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 and Note 2 to Financial Statements for a discussion of the PUCT order.

23

Financial Results — Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

Total operating revenues increased $28 million, or 3%, to $925 million in 2012. The increase reflected:

• $13 million in higher transmission revenues reflecting rate increases to recover ongoing investment in the transmission system;

• an $11 million increase in recognized revenues from the advanced metering deployment surcharge due to increased costs driven by ongoing meter installation and systems development;

• an $11 million increase in miscellaneous revenues, primarily related to recognition of a performance bonus for our energy efficiency achievements in 2011, and

• a $10 million increase in reconcilable rate revenues (those in which recognized revenues equal incurred expenses) consisting of a $28 million increase in TCRF revenues driven by an increase in wholesale transmission expense ($10 million of which was from third parties), a $1 million increase in energy efficiency surcharges (offset in operation and maintenance expense) and a $1 million increase in rate case surcharges, partially offset by a $16 million impact from the rate structure change described above (with a corresponding amount recognized in base rate revenues below) and a $4 million decrease in charges related to transition bonds (offset by a decrease in amortization expense);

partially offset by:

• a $17 million decrease in distribution base rate revenues consisting of a $48 million impact of lower average consumption, primarily due to the effects of milder weather in 2012 as compared to 2011, partially offset by a $16 million impact from reclassifying all TCRF revenues as reconcilable rate revenues resulting from the rate structure change described above (with a corresponding amount recognized in reconcilable rate revenues above), $10 million in higher distribution tariffs (see Note 3 to Financial Statements) and an estimated $5 million effect of growth in points of delivery.

Wholesale transmission service expense increased $10 million, or 9%, to $123 million, due to higher fees paid to other transmission entities and a 2% increase in volumes.

Operation and maintenance expense increased $1 million to $169 million in 2012. The increase included $5 million in higher outside services costs, $3 million in higher amortization of regulatory assets and $1 million in higher vegetation management expenses, partially offset by $5 million in lower employee benefit costs and a $3 million decrease in other miscellaneous expenses. Operation and maintenance expense also reflects fluctuations in other expenses that are offset by corresponding revenues, including a $1 million increase in costs related to programs designed to improve customer electricity efficiency. Amortization of regulatory assets reported in operation and maintenance expense totaled $14 million and $11 million for the three months ended September 30, 2012 and 2011, respectively.

Depreciation and amortization increased $11 million, or 6%, to $201 million in 2012. The increase reflected $15 million attributed to ongoing investments in property, plant and equipment (including $8 million related to advanced meters), partially offset by $4 million in lower amortization of regulatory assets associated with transition bonds (with an offsetting decrease in revenues).

Taxes other than amounts related to income taxes increased $6 million, or 6%, to $113 million in 2012. The change was the result of a $4 million increase in property taxes and a $2 million increase in local franchise fees.

Other income totaled $6 million in 2012 and $8 million in 2011. The 2012 and 2011 amounts included accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting. See Note 10 to Financial Statements.

24

Other deductions totaled $1 million and $2 million in 2012 and 2011, respectively. See Note 10 to Financial Statements.

Provision in lieu of income taxes totaled $92 million in 2012 (including $89 million related to operating income and $3 million related to nonoperating income) compared to $99 million (including $94 million related to operating income and $5 million related to nonoperating income) in 2011. The effective income tax rate on pretax income was 39.8% in 2012 and 40.7% in 2011. The decrease in the rate was driven by the effect of return to provision adjustments and non-taxable gains on benefit plans, partially offset by the non-deductible amortization of the regulatory asset resulting from a change in deductibility of the Medicare Part D subsidy as a result of the Patient Protection and Affordable Care Act of 2010.

Interest income totaled $3 million in 2012 and $7 million in 2011. The decrease was driven by lower reimbursement of transition bond interest from TCEH due to our sale of the TCEH interest agreement to EFIH in August 2012. See Note 9 to Financial Statements for discussion of the sale.

Interest expense and related charges increased $7 million, or 8%, to $96 million in 2012. The change was driven by $7 million in higher amortization of debt issuance costs and discounts and a $6 million increase attributable to higher average borrowings reflecting ongoing capital investments, partially offset by a $4 million decrease attributable to lower average interest rates and a $2 million decrease attributable to higher capitalized interest.

Net income decreased $5 million, or 3%, to $139 million in 2012. The decrease reflected the effects on revenue of milder weather, higher depreciation and higher interest expense, partially offset by increased revenue from higher transmission and distribution rates and lower income taxes.

Financial Results — Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Total operating revenues increased $177 million, or 8%, to $2,536 million in 2012. The increase reflected:

• a $316 million increase in reconcilable rate revenues (those in which recognized revenues equal incurred expenses) consisting of a $223 million impact from the rate structure change described above (with a corresponding amount recognized in base rate revenues below), a $93 million increase in TCRF revenues driven by an increase in wholesale transmission expense ($56 million of which was from third parties), a $5 million increase in energy efficiency surcharges (mostly offset in operation and maintenance expense) and a $2 million increase in rate case surcharges, partially offset by a $7 million decrease in charges related to transition bonds (offset by a decrease in amortization expense);

• $36 million in higher transmission revenues reflecting rate increases to recover ongoing investment in the transmission system;

• a $30 million increase in recognized revenues from the advanced metering deployment surcharge due to increased costs driven by ongoing meter installation and systems development, and

• a $6 million increase in miscellaneous revenues, primarily related to recognition of a performance bonus for our energy efficiency achievements in 2011, partially offset by lower REP discretionary services as a result of the continuing deployment of advanced meters;

partially offset by:

• a $211 million decrease in distribution base rate revenues consisting of a $223 million impact from reclassifying all TCRF revenues as reconcilable rate revenues resulting from the rate structure change described above (with a corresponding amount recognized in reconcilable rate revenues above) and a $69 million impact of lower average consumption, primarily due to the effects of milder weather in 2012 as compared to 2011, partially offset by $68 million in higher distribution tariffs (see Note 3 to Financial Statements) and an estimated $13 million effect of growth in points of delivery.

25

Wholesale transmission service expense increased $56 million, or 17%, to $378 million, due to higher fees paid to other transmission entities, a $9 million settlement of a wholesale transmission pricing issue and a 2% increase in volumes.

Operation and maintenance expense increased $18 million, or 4%, to $495 million in 2012. The increase included $10 million in higher amortization of regulatory assets, $7 million in higher outside services costs and $2 million in higher vegetation management expenses, partially offset by $2 million in lower employee benefit costs and a $4 million decrease in other miscellaneous expenses. Operation and maintenance expense also reflects fluctuations in other expenses that are offset by corresponding revenues, including a $4 million increase in costs related to programs designed to improve customer electricity demand efficiencies and a $1 million increase in costs related to advanced meters. Amortization of regulatory assets reported in operation and maintenance expense totaled $41 million and $31 million for the nine months ended September 30, 2012 and 2011, respectively.

Depreciation and amortization increased $37 million, or 7%, to $577 million in 2012. The increase reflected $44 million attributed to ongoing investments in property, plant and equipment (including $21 million related to advanced meters), partially offset by $7 million in lower amortization of regulatory assets associated with transition bonds (with an offsetting decrease in revenues).

Taxes other than amounts related to income taxes increased $16 million, or 5%, to $313 million in 2012. The change was the result of a $10 million increase in property taxes and a $6 million increase in local franchise fees.

Other income totaled $20 million in 2012 and $23 million in 2011. The 2012 and 2011 amounts included accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting. See Note 10 to Financial Statements.

Other deductions totaled $4 million in 2012 and $7 million in 2011. See Note 10 to Financial Statements.

Provision in lieu of income taxes totaled $213 million in 2012 (including $198 million related to operating income and $15 million related to nonoperating income) compared to $197 million (including $181 million related to operating income and $16 million related to nonoperating income) in 2011. The effective income tax rate on pretax income was 39.9% in 2012 and 39.5% in 2011. The increase in the rate was driven by non-deductible amortization of the regulatory asset resulting from a change in deductibility of the Medicare Part D subsidy as a result of the Patient Protection and Affordable Care Act of 2010, mostly offset by the effect of return to provision adjustments.

Interest income decreased $1 million, or 4%, to $24 million in 2012. The change reflected $7 million in lower reimbursement of transition bond interest from TCEH due to lower remaining principal amounts and our sale of the TCEH interest agreement to EFIH in August 2012, partially offset by a $6 million increase in interest income related to a sales tax refund. See Note 9 to Financial Statements for discussion of the sale.

Interest expense and related charges increased $14 million, or 5%, to $279 million in 2012. The change was driven by an $18 million increase attributable to higher average borrowings reflecting ongoing capital investments and $8 million in higher amortization of debt issuance costs and discounts, partially offset by a $7 million decrease attributable to lower average interest rates and a $5 million decrease attributable to higher capitalized interest.

Net income increased $19 million, or 6%, to $321 million in 2012. The change reflected increased revenue from higher transmission and distribution rates, partially offset by the effects on revenue of milder weather, higher depreciation, higher operation and maintenance expenses, higher interest expense and higher income taxes.

26

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows — Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Cash provided by operating activities totaled $815 million and $871 million for the nine months ended September 30, 2012 and 2011, respectively. The $56 million decrease was driven by a $118 million effect of net income tax payments in 2012 compared to net income tax refunds in 2011, a $44 million decrease in accounts payable levels, a $13 million increase in ad valorem tax payments primarily due to the timing of such payments and a $9 million increase in payments associated with the wholesale transmission cost settlement (see Note 6 to Financial Statements). These decreases in cash were partially offset by an $88 million decrease in pension and OPEB contributions, a $22 million decrease in cash interest payments due to refinancing activities and a $21 million decrease in cash purchases of materials and supplies.

Cash provided by financing activities totaled $291 million and $46 million for the nine months ended September 30, 2012 and 2011, respectively. The 2012 activity reflected a $392 million increase in cash resulting from an increase in short-term borrowings, a $159 million increase reflecting the sale to EFIH of our interest and tax agreements with TCEH (see Note 9 to Financial Statements) and payments received on the related note receivable from TCEH, partially offset by $155 million of cash distributions to our members (a $75 million increase from 2011 (see Note 7 to Financial Statements)), $79 million in cash principal payments on transition bonds (a $3 million increase from 2011 (see Note 5 to Financial Statements)) and $45 million in debt discount, financing and reacquisition expenses.

Cash used in investing activities, which consisted primarily of capital expenditures, totaled $1,109 million and $948 million for the nine months ended September 30, 2012 and 2011, respectively. The $161 million, or 17%, increase was driven by an increase in capital expenditures for CREZ investments, distribution facilities to serve new customers, infrastructure maintenance and information technology initiatives.

Depreciation and amortization expense reported in the condensed statements of consolidated cash flows was $23 million and $9 million more than the amounts reported in the condensed statements of consolidated income for the nine months ended September 30, 2012 and 2011, respectively. The differences represent 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. In addition, the differences represent regulatory asset amortization, which is reported in operation and maintenance expense in the condensed statements of consolidated income.

Long-Term Debt Activity — Repayments of long-term debt in 2012 totaled $979 million, consisting of $376 million principal amount of 6.375% senior secured notes paid at the scheduled maturity date of May 1, 2012, $524 million principal amount of the 2013 Notes redeemed on June 18, 2012 and $79 million principal amount of transition bonds paid at scheduled maturity dates.

Issuances of long-term debt in 2012 included $400 million aggregate principal amount of 4.100% senior secured notes maturing in June 2022 and $500 million aggregate principal amount of 5.300% senior secured notes maturing in June 2042. We used the proceeds (net of the initial purchasers’ discount, fees and expenses) of approximately $890 million from the sale of the notes to repay borrowings under our revolving credit facility, redeem the 2013 Notes (discussed above) and for other general corporate purposes.

See Note 5 to Financial Statements for additional information regarding these transactions and other 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. At September 30, 2012, we had a $2.4 billion secured revolving credit facility, reflecting a $400 million increase in commitments under the revolving credit facility effective May 15, 2012 (see Note 4 to Financial Statements). Subject to the limitations described below, available borrowing capacity under our revolving credit facility totaled $1.610 billion and $1.602 billion at September 30, 2012 and December 31, 2011, respectively. We may request an additional increase in our borrowing capacity of $100 million in the aggregate, provided certain conditions are met, including lender approval. The revolving credit facility expires in October 2016. We may request up to two one-year extensions, provided certain conditions are met, including lender approval.

27

The revolving credit facility contains a senior debt-to-capitalization ratio covenant that effectively limits our ability to incur indebtedness in the future. At September 30, 2012, we were in compliance with the covenant. See “Financial Covenants, Credit Rating Provisions and Cross Default Provisions” below for additional information on this covenant and the calculation of this ratio. 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 lower of the fair value or cost of certain property additions that could be certified to the Deed of Trust collateral agent. Accordingly, the availability under our revolving 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 the revolving credit facility borrowings. In addition, our outstanding senior notes and debentures are secured by the Deed of Trust. To the extent we continue to issue debt securities secured by the Deed of Trust, those debt securities would also be limited by the amount of available bond credits and any property additions that could be certified to the Deed of Trust collateral agent. At September 30, 2012, the available bond credits totaled $2.141 billion and the amount of additional potential indebtedness that could be secured by property additions, subject to the completion of a certification process, totaled $475 million. At September 30, 2012, the available borrowing capacity of the revolving 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, 2012 and December 31, 2011, our regulatory capitalization ratios were 58.5% debt and 41.5% equity and 59.7% debt and 40.3% equity, respectively. See Note 7 to Financial Statements for discussion of the debt-to-equity ratio.

Cash and cash equivalents totaled $9 million and $12 million at September 30, 2012 and December 31, 2011, respectively. Available liquidity (cash and available credit facility capacity) at September 30, 2012 totaled $1.619 billion reflecting an increase of $5 million from December 31, 2011. The change reflects the increase in available credit facility commitments and the seasonal nature of our cash flow, partially offset by ongoing capital investment in transmission and distribution infrastructure.

Under the terms of our revolving credit facility, 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 $1.2 billion in 2012, and approximately $1.0 billion in each of the years 2013 through 2016, including amounts related to CREZ construction and voltage support projects totaling approximately $560 million, $390 million and $150 million in 2012, 2013 and 2014, respectively. These capital expenditures are expected to be used for investment in transmission and distribution infrastructure. We have satisfied our commitment to the PUCT 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 in our 2011 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, generate equity capital or preserve equity through reductions or suspension of distributions to members. In addition, we may also consider new debt issuances, repurchases, exchange offers and other transactions in order to refinance or manage our long-term debt. 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 business and would likely increase capital costs that may not be recoverable through rates.

28

Distributions — On October 24, 2012, our board of directors declared a cash distribution of $70 million to be paid to our members on October 30, 2012. During the nine months ended September 30, 2012, our board of directors declared, and we paid, the following cash distributions to members:

Declaration Date	Payment Date	Amount
July 25, 2012	July 31, 2012	$	50
April 25, 2012	May 1, 2012	$	60
February 14, 2012	February 21, 2012	$	45

See Note 7 to Financial Statements for discussion of distribution restrictions.

Pension and OPEB Plan Funding — Pending regulatory guidance on new legislation discussed immediately below, we expect to make cash contributions to the EFH Retirement Plan, the OPEB Plan and the Oncor Plan of $89 million, $11 million and $3 million, respectively, in 2012. In the nine months ended September 30, 2012, our contributions to the EFH Retirement Plan, the OPEB Plan and the Oncor Plan totaled $89 million, $8 million and $2 million, respectively.

See Note 8 to Financial Statements for discussion of the amendments adopted by EFH Corp. in August 2012 that will result in the split off of the majority of the assets and liabilities of the EFH Retirement Plan into two new plans, one of which is expected to be sponsored by us. EFH Corp. has informed us that it intends to settle the terminating obligations and fully fund the EFH Corp. competitive business portion of liabilities (including discontinued businesses) under our new plan with cash contributions currently estimated to aggregate approximately $240 million in the fourth quarter of 2012, of which $150 million was contributed by EFH Corp. in October 2012.

In July 2012, the US Congress enacted legislation that includes, among other things, pension funding stabilization provisions. These provisions are expected to reduce required minimum pension plan contributions in the near term, but have no impact on long-term funding levels absent a sustained low interest rate environment. As a result of the new legislation and the effect of the amendments on the EFH Retirement Plan, we estimate our aggregate pension funding for the year 2013 and the 2014 to 2016 period to total $10 million and $330 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 revolving 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 plus indebtedness described above. At September 30, 2012, we were in compliance with this covenant with a debt-to-capitalization ratio of 0.45 to 1.00.

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). 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 most recent rate review or subsequent rate reviews.

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.

29

In August 2012, Moody’s changed our senior secured credit rating from Baa1 to Baa2. The downgrade in our credit rating was primarily driven by Moody’s view of the risks to which we are exposed by EFH Corp. (our ultimate parent) and TCEH, and increased debt at EFIH. Our ratings outlook with Moody’s remains on “negative outlook” and remains on “stable outlook” with S&P and Fitch. Presented below are the credit ratings assigned for our debt securities at September 30, 2012.

	Senior Secured
S&P	A-
Moody’s	Baa2
Fitch	BBB+

As described in Note 5 to Financial Statements, our long-term debt, excluding Bondco’s non-recourse debt, is currently secured pursuant to the Deed of Trust 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. Borrowings under the revolving 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 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 1.00%) plus a spread ranging from 0.00% to 0.75% depending on credit ratings assigned to our senior secured non-credit enhanced long-term debt. Based on our current ratings, our borrowings are generally LIBOR-based and will bear interest at LIBOR plus 1.25%. A decline in credit ratings would increase the cost of our revolving credit facility and likely increase the cost of any debt issuances and 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.

Under our 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 ($784 million in short-term borrowings and $6 million in letters of credit at September 30, 2012) under such facility to be accelerated. Additionally, under the Deed of Trust, an event of default under either our revolving credit facility or our indentures would permit our lenders and the holders of our senior secured notes to exercise their remedies under the Deed of Trust.

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

OFF-BALANCE SHEET ARRANGEMENTS

At September 30, 2012, 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, 2012 that are expected to materially impact us.

30

REGULATION AND RATES

Sunset Review and Other State Legislation

The PUCT is subject to a limited purpose “sunset” review by the Texas Legislature in the 2013 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).

Matters with the PUCT

2011 Rate Review Filing (PUCT Docket No. 38929) — 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. In April 2011, we and the other parties reached a Memorandum of Settlement that would settle and resolve all issues in the rate review. We filed a stipulation 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 became effective January 1, 2012. Under the Stipulation, amortization of regulatory assets increased by approximately $24 million ($14 million of which will be recognized as tax expense) 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 we are not restricted from filing wholesale transmission rate, TCRF, distribution-related investment and 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, through September 30, 2012, we have made $22 million in retrospective franchise fee payments to cities that accepted the terms of the separate agreement. 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 (PUCT Docket No. 35717) — 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, and new rates were implemented in September 2009. The final order approved a total annual revenue requirement for us of $2.64 billion. New rates were calculated for all customer classes using 2007 test year billing metrics and the approved class cost allocation and rate design. The PUCT staff estimated that the final order resulted in an approximate $115 million increase in base rate revenues over our 2007 adjusted test year revenues, before recovery of rate review expenses. Prior to implementing the new rates in September 2009, we had already begun recovering $45 million of the $115 million increase as a result of approved transmission cost recovery factor and energy efficiency cost recovery factor filings, such as those discussed below.

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 review 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. Oral argument before the Austin Court of Appeals was completed in April 2012. There is no deadline for the court to act. We are unable to predict the outcome of the appeal.

31

Competitive Renewable Energy Zones (CREZs) — In 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, 2012, our cumulative CREZ-related capital expenditures totaled $1.360 billion, including $461 million during the nine months ended September 30, 2012. 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 Cost Recovery and TCRF Rates (PUCT Docket Nos. 40451 and 39940) — In order to reflect increases or decreases in our transmission costs, including fees paid to other transmission service providers due to changes in their rates, we are allowed to request an update twice a year to the TCRF component of our retail delivery rates charged to REPs. In June 2012, we filed an application to increase the TCRF, which became effective September 1, 2012. This application was designed to increase billings for the period September 2012 through February 2013 by approximately $129 million. In November 2011, we filed an application with the PUCT to update the TCRF, which was approved in January 2012 and became effective March 1, 2012. This application was designed to reduce billings for the period March 2012 through August 2012 by approximately $41 million reflecting over-recoveries due to hot weather in the summer of 2011. Effective July 1, 2011, charges billed under the TCRF rate became reconcilable (see Note 2 to Financial Statements). The difference between amounts billed 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).

Transmission Interim Rate Update Application (PUCT Docket Nos. 40603 and 40142) — In July 2012, we filed an application for an interim update of our wholesale transmission rate. The new rate was approved by the PUCT and became effective in August 2012. Annualized revenues are expected to increase by an estimated $30 million with approximately $19 million of this increase recoverable through transmission costs charged to wholesale customers and $11 million recoverable from REPs through the TCRF component of our delivery rates. In January 2012, we filed an application for an interim update of our wholesale transmission rate. The new rate was approved by the PUCT and became effective in March 2012. Annualized revenues are expected to increase by an estimated $2 million with approximately 65% of this increase recoverable through transmission costs charged to wholesale customers and the remaining 35% recoverable from REPs through the TCRF component of our delivery rates.

Application for 2013 Energy Efficiency Cost Recovery Factor (PUCT Docket No. 40361) — In May 2012, we filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2013. PUCT rules require us to make an annual EECRF filing by the first business day in May for implementation at the beginning of the next calendar year. The requested 2013 EECRF is $73 million as compared to $54 million established for 2012, and would result in a monthly charge for residential customers of $1.23 as compared to the 2012 residential charge of $0.99 per month effective December 31, 2012. In August 2012, the PUCT issued a final order approving the 2013 EECRF, which is designed to recover $62 million of our costs for the 2013 program year, a $9 million performance bonus based on 2011 results and a $2 million increase for under-recovery of 2011 costs.

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 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 PUCT ruled on both issues in January 2012. No appeals were filed prior to the appeals deadlines, and the PUCT orders became final in February 2012. See Note 6 to Financial Statements for a discussion of this proceeding.

32

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. Among other things, the stipulation required us to file a rate review no later than July 1, 2008 based on a test year ended December 31, 2007, which we filed in June 2008. The PUCT issued a final order with respect to the rate review in August 2009. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200^th District Court of Travis County, Texas (District Court). 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 Austin Court of Appeals in July 2010. Oral argument was held before the Austin Court of Appeals in March 2011. In March 2012, the Austin Court of Appeals affirmed the District Court’s ruling, which is now final.

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.

33

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. We may transact in financial instruments to hedge interest rate risk related to our debt, but there are currently no such hedges in place. All of our long-term debt at September 30, 2012 and December 31, 2011 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 2011 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 $154 million from affiliates, substantially all of which consisted of trade accounts receivable from TCEH, and $377 million from nonaffiliated customers at September 30, 2012. The nonaffiliated customer receivable amount is before the allowance for uncollectible accounts, which totaled $2 million at September 30, 2012. The nonaffiliate exposure includes trade accounts receivable from REPs totaling $289 million, which are almost entirely noninvestment grade. At September 30, 2012, REP subsidiaries of a nonaffiliated entity collectively represented approximately 14% of the nonaffiliated trade receivable amount. No other nonaffiliated parties represented 10% or more of the total exposure. We view our exposure to these customers 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.

See Note 9 to Financial Statements for additional information.

34

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 discussions of risk factors under “Item 1A. Risk Factors” in our 2011 Form 10-K, our Quarterly Reports on Form 10-Q and the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2011 Form 10-K and 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, including the exercise of equitable powers by courts;

• weather conditions and other natural phenomena;

• acts of sabotage, wars or terrorist or cyber security threats or 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.

35

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 quarterly report. Based on the evaluation performed, our management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective. During the most recent fiscal quarter covered by this 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.

36

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

In addition to the other information set forth in this report, you should carefully consider the factors discussed in “Part I, Item 1A. Risk Factors” in our 2011 Form 10-K and “Part II, Item 1A. Risk Factors” in our Quarterly Reports on Form 10-Q, which could materially affect our business, financial condition or future results. The risks described in such reports are not the only risks we face.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Pursuant to our Limited Liability Company Agreement, Texas Transmission has the right to designate two directors (each, a Minority Member Director) to serve on our board of directors. On October 24, 2012, Texas Transmission notified us of its removal of Richard C. Byers as a Minority Member Director and its appointment of Rheal R. Ranger as a Minority Member Director in place of Mr. Byers, effective immediately. It is expected that Mr. Ranger will also replace Mr. Byers on the audit committee of the board of directors. There were no disagreements with Oncor that led to Mr. Byers’s removal from our board of directors.

Mr. Ranger, 54, currently serves as Executive Vice President with Borealis Infrastructure Management Inc. (Borealis), the infrastructure investment arm of Canada’s OMERS pension plan, a position he has held since January 2012. In such role he is responsible for leading and managing Borealis’s transaction team out of its recently opened US office in New York. Prior to assuming this role, he was Borealis’s Executive Vice-President and Chief Financial Officer, a position that he fulfilled since joining Borealis in June 2004. Mr. Ranger has extensive experience in structuring multi-layered investment structures in different regulatory and tax jurisdictions and has actively participated in a number of Borealis’s acquisitions and asset management activities. From 1987 to 2004, he served in various executive management positions (including CFO and CEO) within the Standard Broadcasting group of companies, one of Canada’s largest broadcast companies, and from 1982 to 1987 he served as a Tax Manager with Arthur Andersen, a large international accounting firm.

37

ITEM 6. EXHIBITS

(a) Exhibits provided as part of Part II are:
Exhibits	Previously Filed With File Number	As Exhibit
(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 Statement of Consolidated Income – Twelve Months Ended September 30, 2012.
	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

38

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 (Principal Financial Officer and Duly Authorized Officer)

Date: October 29, 2012

39

EXHIBIT INDEX

Exhibits	Previously Filed With File Number	As Exhibit
(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 Statement of Consolidated Income – Twelve Months Ended September 30, 2012.
	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