Oncor Electric Delivery 10-Q 2013 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

____________________

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2013

― 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.   Yesü 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  ü 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 filerü (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 ü

As of October 31, 2013, 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		2
PART I.   FINANCIAL INFORMATION		4
Item 1.   Financial Statements (Unaudited)		4
Condensed Statements of Consolidated Income — Three and Nine Months Ended September 30, 2013 and 2012		4
Condensed Statements of Consolidated Comprehensive Income — Three and Nine Months Ended September 30, 2013 and 2012		4
Condensed Statements of Consolidated Cash Flows — Nine Months Ended September 30, 2013 and 2012		5
Condensed Consolidated Balance Sheets — September 30, 2013 and December 31, 2012		6
Notes to Condensed Consolidated Financial Statements		7
Item 2.     Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 3.    Quantitative and Qualitative Disclosures About Market Risk		32
Item 4.    Controls and Procedures		34
PART II.     OTHER INFORMATION		35
Item 1.    Legal Proceedings		35
Item 1A   Risk Factors		35
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds		35
Item 3.    Defaults Upon Senior Securities		35
Item 4.    MINE SAFETY DISCLOSURES		35
Item 5.    Other Information		35
Item 6.    Exhibits		36
SIGNATURE		37

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.

1

GLOSSARY

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
2012 Form 10-K	Oncor’s Annual Report on Form 10-K for the year ended December 31, 2012
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 a defined benefit pension plan sponsored by EFH Corp., in which Oncor participates.
EFIH	Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.
ERCOT	Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
Fitch	Fitch Ratings, Ltd. (a credit rating agency)
GAAP	generally accepted accounting principles
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.
IRS	US Internal Revenue Service
LIBOR	London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
Luminant	Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.
Moody’s	Moody’s Investor Services, Inc. (a credit rating agency)
Oncor	Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings, and/or its wholly-owned consolidated bankruptcy-remote financing subsidiary, Bondco, depending on context.
Oncor Holdings	Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIH and the direct majority owner (approximately 80.03%) of Oncor, and/or its subsidiaries, depending on context.
Oncor Retirement Plan	Refers to the defined benefit pension plan sponsored by Oncor.
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 participates) 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.

2

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
Sponsor Group	Refers collectively to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), TPG Global, LLC (together with its affiliates, TPG) 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.  Its major subsidiaries include Luminant and TXU Energy.
TCOS	transmission cost of service
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.
Texas margin tax	A privilege tax imposed on taxable entities chartered/organized or doing business in the State of Texas that, for accounting purposes, is reported as an income tax.  Also referred to as “Texas franchise tax” and/or “Texas gross margin tax.”
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.
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

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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,
	2013		2012		2013		2012
	(millions of dollars)
Operating revenues:
Nonaffiliates	$	693	$	644	$	1,912	$	1,790
Affiliates		273		281		728		746
Total operating revenues		966		925		2,640		2,536
Operating expenses:
Wholesale transmission service		146		123		417		378
Operation and maintenance		169		169		502		495
Depreciation and amortization		207		201		608		577
Provision in lieu of income taxes (Note 9)		93		89		190		198
Taxes other than amounts related to income taxes		112		113		315		313
Total operating expenses		727		695		2,032		1,961
Operating income		239		230		608		575
Other income and deductions:
Other income (Note 10)		4		6		14		20
Other deductions (Note 10)		2		1		11		4
Nonoperating provision in lieu of income taxes (Note 9)		1		3		1		15
Interest income		-		3		2		24
Interest expense and related charges (Note 10)		94		96		283		279
Net income	$	146	$	139	$	329	$	321

See Notes to Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
		(millions of dollars)
Net income	$	146	$	139	$	329	$	321
Other comprehensive income (loss):
Cash flow hedges — derivative value net loss   recognized in net income (net of tax benefit)		1		1		3		3
Defined benefit pension plans (net of tax benefit)		-		-		(1)		-
Total other comprehensive income		1		1		2		3
Comprehensive income	$	147	$	140	$	331	$	324

See Notes to Financial Statements.

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ONCOR ELECTRIC DELIVERY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2013		2012
	(millions of dollars)
Cash flows — operating activities:
Net income	$	329	$	321
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		634		600
Provision in lieu of deferred income taxes – net		143		191
Amortization of investment tax credits		(3)		(3)
Other – net		-		(1)
Changes in operating assets and liabilities:
Deferred revenues (Note 3)		(19)		(96)
Changes in other operating assets and liabilities		(174)		(197)
Cash provided by operating activities		910		815
Cash flows — financing activities:
Issuance of long-term debt (Note 5)		100		900
Repayments of long-term debt (Note 5)		(84)		(979)
Net increase in short-term borrowings (Note 4)		125		392
Distributions to members (Note 7)		(215)		(155)
Decrease in note receivable from TCEH (Note 9)		-		20
Sale of related-party agreements (Note 9)		-		159
Debt discount, premium, financing and reacquisition expenses – net		2		(45)
Other – net		-		(1)
Cash (used in) provided by financing activities		(72)		291
Cash flows — investing activities:
Capital expenditures		(870)		(1,113)
Other – net		4		4
Cash used in investing activities		(866)		(1,109)
Net change in cash and cash equivalents		(28)		(3)
Cash and cash equivalents — beginning balance		45		12
Cash and cash equivalents — ending balance	$	17	$	9

See Notes to Financial Statements.

5

ONCOR ELECTRIC DELIVERY COMPANY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	At September 30,		At December 31,
	2013		2012
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	17	$	45
Restricted cash — Bondco (Note 10)		61		55
Trade accounts receivable from nonaffiliates – net (Note 10)		404		338
Trade accounts and other receivables from affiliates (Note 9)		158		53
Materials and supplies inventories — at average cost		67		73
Prepayments and other current assets		79		79
Total current assets		786		643
Restricted cash — Bondco (Note 10)		16		16
Investments and other property (Note 10)		85		83
Property, plant and equipment – net (Note 10)		11,794		11,318
Goodwill (Note 10)		4,064		4,064
Regulatory assets – net ― Oncor (Note 3)		1,259		1,453
Regulatory assets –- net ― Bondco (Note 3)		253		335
Other noncurrent assets		70		78
Total assets	$	18,327	$	17,990
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Short-term borrowings (Note 4)	$	860	$	735
Long-term debt due currently ― Bondco (Note 5)		129		125
Trade accounts payable		100		121
Amounts payable to members related to income taxes (Note 9)		30		22
Accrued taxes other than amounts related to income		134		153
Accrued interest		65		95
Other current liabilities		111		109
Total current liabilities		1,429		1,360
Long-term debt, less amounts due currently ― Oncor (Note 5)		5,200		5,090
Long-term debt, less amounts due currently ― Bondco (Note 5)		222		310
Liability in lieu of deferred income taxes (Note 9)		2,374		2,180
Investment tax credits		22		24
Other noncurrent liabilities and deferred credits (Note 10)		1,661		1,722
Total liabilities		10,908		10,686
Commitments and contingencies (Note 6)
Membership interests (Note 7):
Capital account ― number of interests outstanding 2013 and 2012 – 635,000,000		7,448		7,335
Accumulated other comprehensive loss		(29)		(31)
Total membership interests		7,419		7,304
Total liabilities and membership interests	$	18,327	$	17,990

See Notes to Financial Statements.

6

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 28% and 29% of our total operating revenues for the nine months ended September 30, 2013 and 2012, respectively.  We are a direct, 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 variable interest entity.  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 in our 2012 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 in our 2012 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.

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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 costs 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.

8

2.    REGULATORY MATTERS

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.  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.

See Note 2 to Financial Statements in our 2012 Form 10-K for additional information regarding regulatory matters. 

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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	Carrying Amount At
	September 30, 2013	September 30, 2013		December 31, 2012
Regulatory assets:
Generation-related regulatory assets securitized   by transition bonds (a)(e)	3 years	$	315	$	409
Employee retirement costs	6 years		75		87
Employee retirement costs to be reviewed (b)(c)	To be determined		214		186
Employee retirement liability (a)(c)(d)	To be determined		682		738
Self-insurance reserve (primarily storm recovery   costs) ― net	6 years		166		190
Self-insurance reserve to be reviewed (b)(c)	To be determined		148		128
Securities reacquisition costs (pre-industry restructure)	3 years		34		41
Securities reacquisition costs   (post-industry restructure) ― net	Terms of related debt		5		22
Recoverable amounts in lieu of deferred   income taxes ― net	Life of related asset or liability		45		71
Rate review expenses (a)	Largely 2 years		6		6
Advanced meter customer education costs	6 years		9		10
Deferred conventional meter and metering   facilities depreciation	Largely 7 years		152		152
Deferred advanced metering system costs	6 years		49		2
Energy efficiency performance bonus (a)	1 year		2		9
Under-recovered wholesale transmission   service expense ― net (a)	1 year		32		40
Energy efficiency programs (a)	Not applicable		-		1
Other regulatory assets	Various		1		1
Total regulatory assets			1,935		2,093
Regulatory liabilities:
Estimated net removal costs	Life of utility plant		349		244
Investment tax credit and protected excess   deferred taxes	Various		23		28
Over-collection of transition bond revenues (a)(e)	3 years		38		33
Energy efficiency programs (a)	Not applicable		13		-
Total regulatory liabilities			423		305
Net regulatory asset		$	1,512	$	1,788

____________

(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) Bondco net regulatory assets of $253 million at September 30, 2013 consisted of $291 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 $335 million at December 31, 2012 consisted of $368 million included in generation-related regulatory assets net of the regulatory liability for over-collection of transition bond revenues of $33 million.

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4.BORROWINGS UNDER CREDIT FACILITIES

At September 30, 2013, we had a $2.4 billion secured revolving credit facility 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.  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, 2013, we had outstanding borrowings under the revolving credit facility totaling $860 million with an interest rate of 1.68% and outstanding letters of credit totaling $6 million.  At December 31, 2012, we had outstanding borrowings under the revolving credit facility totaling $735 million with an interest rate of 1.46% and outstanding letters of credit totaling $6 million.

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.  At September 30, 2013, all outstanding borrowings bore interest at LIBOR plus 1.50%.  Amounts borrowed under the facility, once repaid, can be borrowed again from time to time.

An unused commitment fee is payable quarterly in arrears and upon termination or commitment reduction at a rate equal to 0.100% to 0.275% (such spread depending on certain credit ratings assigned to our senior secured debt) of the daily unused commitments under the revolving credit facility.  Letter of credit fees on the stated amount of letters of credit issued under the revolving credit facility are payable to the lenders quarterly in arrears and upon termination at a rate per annum equal to the spread over adjusted LIBOR.  Customary fronting and administrative fees are also payable to letter of credit fronting banks.  At September 30, 2013, letters of credit bore interest at 1.50%, and a commitment fee (at a rate of 0.225% per annum) was payable on the unfunded commitments under the facility, each based on our current credit ratings.

Subject to the limitations described below, borrowing capacity available under the credit facility at September 30, 2013 and December 31, 2012 was $1.534 billion and $1.659 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 6 to Financial Statements in our 2012 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 have been certified to the Deed of Trust collateral agent.  At September 30, 2013, the available bond credits were approximately $2.061 billion and the amount of additional potential indebtedness that could be secured by property additions, subject to a certification process, was $1.112  billion.  At September 30, 2013, the available borrowing capacity of the revolving credit facility could be fully drawn.

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5.    LONG-TERM DEBT

At September 30, 2013 and December 31, 2012, our long-term debt consisted of the following:

	September 30,		December 31,
	2013		2012
Oncor (a):
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		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		400		300
5.300% Fixed Senior Notes due June 1, 2042		500		500
Unamortized discount		(25)		(35)
Long-term debt, less amounts due currently — Oncor		5,200		5,090
Bondco (b):
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		-		10
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		106		145
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		246		281
Unamortized fair value discount related to transition bonds		(1)		(1)
Less amount due currently		(129)		(125)
Long-term debt, less amounts due currently — Bondco		222		310
Total long-term debt, less amounts due currently	$	5,422	$	5,400

__________

(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” in Note 6 to Financial Statements in our 2012 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 2013

Debt Repayments

Repayments of long-term debt in the nine months ended September 30, 2013 totaled $84 million and represent transition bond principal payments at scheduled maturity dates.

Issuance of New Senior Secured Notes

In May 2013, we completed the sale of $100 million aggregate principal amount of 4.550% senior secured notes maturing in December 2041 (Additional 2041 Notes).  The Additional 2041 Notes were an additional issuance of our 4.550% senior secured notes maturing in December 2041,  $300 million of which were previously issued in November 2011 (2041 Notes).  The Additional 2041 Notes were issued as part of the same series as the 2041 Notes.  We used the net proceeds of approximately $107 million from the sale of the Additional 2041 Notes to repay borrowings under our revolving credit facility and for general corporate purposes.  The Additional 2041 Notes and 2041 Notes are secured by the first priority lien (see Note 4), and are secured equally and ratably with all of our other secured indebtedness. 

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Interest on the Additional 2041 Notes is payable in cash semiannually in arrears on June 1 and December 1 of each year, beginning on June 1, 2013.  We may at our option redeem the notes, in whole or in part, at any time, 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 Additional 2041 Notes were issued in a private placement, and in July 2013 we completed an offering with the holders of the Additional 2041 Notes to exchange their respective Additional 2041 Notes for notes that have terms identical in all material respects to the Additional 2041 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 June 2013.

Fair Value of Long-Term Debt

At September 30, 2013 and December 31, 2012, the estimated fair value of our long-term debt (including current maturities) totaled $6.321 billion and $6.568 billion, respectively, and the carrying amount totaled $5.551 billion and $5.525 billion, respectively.  The fair value is estimated based upon the market value as determined by quoted market prices, representing Level 1 valuations under accounting standards related to the determination of fair value.

6.    COMMITMENTS AND CONTINGENCIES

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, 2013, 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 2.0 years.

For the purpose of obtaining greater access to materials, we previously guaranteed the repayment of borrowings under a nonaffiliated party’s $7 million credit facility.  The facility matured on March 31, 2013 and was not extended. 

We are involved in various 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 7 to Financial Statements in our 2012 Form 10-K for additional information regarding our legal and regulatory proceedings.

7.    MEMBERSHIP INTERESTS

Cash Distributions

On October 29, 2013, our board of directors declared a cash distribution of $95  million, which was paid to our members on October 31, 2013.  During the nine months ended September 30, 2013, our board of directors declared, and we paid the following cash distributions to our members:

Declaration Date	Payment Date	Amount
July 31, 2013	August 1, 2013	$	95
May 1, 2013	May 2, 2013	$	70
February 13, 2013	February 15, 2013	$	50

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Distributions are 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, 2013, our regulatory capitalization ratio was 58.7% debt and 41.3% 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, 2013, $187 million was available for distribution to our members under the capital structure restriction. 

The following tables present the changes to membership interests during the nine months ended September 30, 2013 and 2012:

	Capital Accounts		Accumulated Other Comprehensive Income (Loss)		Total Membership Interests
Balance at December 31, 2012	$	7,335	$	(31)	$	7,304
Net income		329		-		329
Distributions		(215)		-		(215)
Net effects of cash flow hedges (net of tax)		-		2		2
Other		(1)		-		(1)
Balance at September 30, 2013	$	7,448	$	(29)	$	7,419
	Capital Accounts		Accumulated Other Comprehensive Income (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

Accumulated Other Comprehensive Income (Loss)

The following table presents the changes to accumulated other comprehensive income (loss) for the nine months ended September 30, 2013. 

	Cash Flow Hedges – Interest Rate Swap		Defined Benefit Pension and OPEB Plans		Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2012	$	(28)	$	(3)	$	(31)
Defined benefit pension plans (net of tax)		-		(1)		(1)
Amounts reclassified from accumulated other comprehensive   income (loss) and reported in:
Interest expense and related charges		3		-		3
Total amount reclassified from accumulated other comprehensive   income (loss) during the period		3		-		3
Balance at September 30, 2013	$	(25)	$	(4)	$	(29)

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8.    PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS PLANS 

We participate in two defined pension plans, the Oncor Retirement Plan and 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 have supplemental pension plans for certain employees whose retirement benefits cannot be fully earned under the qualified retirement plans.  See Note 9 to Financial Statements in our 2012 Form 10-K for additional information regarding our pension plans and the OPEB Plan.

Our net costs related to pension plans and the OPEB Plan for the three and nine months ended September 30, 2013 and 2012 were comprised of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Components of net allocated pension costs:
Service cost	$	6	$	6	$	18	$	17
Interest cost		31		26		92		80
Expected return on assets		(31)		(28)		(91)		(80)
Amortization of net loss		17		21		52		58
Net pension costs		23		25		71		75
Components of net OPEB costs:
Service cost		1		2		4		4
Interest cost		9		10		28		29
Expected return on assets		(3)		(3)		(9)		(9)
Amortization of net transition obligation		-		-		-		1
Amortization of prior service cost		(5)		(5)		(15)		(15)
Amortization of net loss		7		3		19		10
Net OPEB costs		9		7		27		20
Total net pension and OPEB costs		32		32		98		95
Less amounts deferred principally as property or a
regulatory asset		(23)		(23)		(71)		(68)
Net amounts recognized as expense	$	9	$	9	$	27	$	27

The discount rates reflected in net pension and OPEB costs in 2013 are 4.10%,  4.30% and 4.10% for the Oncor Retirement Plan, the EFH Retirement Plan and the OPEB Plan, respectively.  The expected return on pension and OPEB plan assets reflected in the 2013 cost amounts are 6.16%,  5.40% and 6.70% for the Oncor Retirement Plan,  the EFH Retirement Plan and the OPEB Plan, respectively.

We made cash contributions to the pension plans and OPEB Plan of $8 million and $9 million, respectively, during the nine months ended September 30, 2013, and we expect to make additional cash contributions of $2 million and $3 million, respectively, during the remainder of 2013.

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9.    RELATED-PARTY TRANSACTIONS

The following represent our significant related-party transactions:

· We record revenue from TCEH, principally for electricity delivery fees, which totaled $273 million and $281 million for the three months ended September 30, 2013 and 2012, respectively, and $728 million and $746 million for the nine months ended September 30, 2013 and 2012, respectively.  The fees are based on rates regulated by the PUCT that apply to all REPs.  These revenues included less than $1 million for each of the three- and nine-month periods ended September 30, 2013 and 2012 pursuant to a transformer maintenance agreement with TCEH.  The balance sheets at September 30, 2013 and December 31, 2012 reflect receivables from affiliates totaling $158 million ($53 million of which was unbilled) and $53 million ($48 million of which was unbilled), respectively, primarily consisting of trade receivables from TCEH related to these electricity delivery fees.  Trade accounts receivable from TCEH at December 31, 2012 reflects timing of payments in 2012.

· Prior to August 2012, 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 $16 million for the three and nine months ended September 30, 2012, respectively.  Also prior to August 2012, we received reimbursement under a note receivable from TCEH for incremental amounts payable related to income taxes as a result of delivery fee surcharges related to the transition bonds.  Amounts received under the note receivable for the nine months ended September 30, 2012 totaled $20 million.  See Note 11 to Financial Statements in our 2012 Form 10-K for additional information regarding the sale to EFIH of the agreement and related future interest reimbursements as well as the note receivable from TCEH.

· EFH Corp. subsidiaries charge us for certain administrative services at cost.  We also charge each other for shared facilities at cost.  Our costs, which are primarily reported in operation and maintenance expenses, totaled $8 million and $10 million for the three months ended September 30, 2013 and 2012, respectively, and $24 million and $27 million for the nine months ended September 30, 2013 and 2012, respectively.

· Under Texas regulatory provisions, the trust fund for decommissioning TCEH’s 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, 2013 and 2012, and $12 million for each of the nine-month periods ended September 30, 2013 and 2012. Our sole obligation with regard to nuclear decommissioning is as the collection agent of funds charged to ratepayers for nuclear decommissioning activities.  If, at the time of decommissioning, actual decommissioning costs exceed available trust funds, we would not be obligated to pay any shortfalls but would be required to collect any rates approved by the PUCT to recover any additional decommissioning costs.  Further, if there were to be a surplus when decommissioning is complete, such surplus would be returned to ratepayers under terms prescribed by the PUCT.

· 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.  For periods prior to the tax sharing agreement (entered into in October 2007 and amended and restated in November 2008), we are responsible for our share of redetermined tax liability for the EFH Corp. consolidated tax group.  EFH Corp. also includes our results in its consolidated 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 2012 Form 10-K under “Income Taxes.”  Under the “in lieu of” tax concept, all in lieu 16   of tax assets and tax liabilities represent amounts that will eventually be settled with our members.  At September 30, 2013, we had federal income tax amounts payable to members under the agreement totaling $13 million ($11 million due to EFH Corp. and $2 million due to Texas Transmission and Investment LLC) and a current Texas margin tax payable to EFH Corp. totaling $17 million,  which are reported as amounts payable to members related to income taxes of $30 million.    At December 31, 2012, we had a current Texas margin tax payable to EFH Corp. under the agreement of $22 million, which is reported as amounts payable to members related to income taxes.  We made income tax payments totaling $64 million and $4 million to members in the nine months ended September 30, 2013 and 2012, respectively. The 2013 net payment included a $33 million payment to EFH Corp. related to the 1997 through 2002 IRS appeals settlement and a  $10 million refund from EFH Corp. related to the filing of amended Texas franchise tax returns for 1997 through 2001.  The 2012 net payment included a $21 million federal income tax-related refund from EFH Corp.

· 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, 2013 and December 31, 2012, TCEH had posted letters of credit in the amount of $10 million and $11 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 Notes 7 and 8 for information regarding distributions to members and our participation in EFH Corp. pension and OPEB plans, respectively.

10.   SUPPLEMENTARY FINANCIAL INFORMATION

Major Customers

Revenues from TCEH represented 28% and 30% of our total operating revenues for the three months ended September 30, 2013 and 2012, respectively, and 28% and 29% of our total operating revenues for the nine months ended September 30, 2013 and 2012, respectively.  Revenues from REP subsidiaries of a nonaffiliated entity collectively represented 16% of our total operating revenues for each of the three-month periods ended September 30, 2013 and 2012, and 15% of total operating revenues for each of the nine-month periods ended September 30, 2013 and 2012.  No other customer represented 10% or more of our total operating revenues.

Other Income and Deductions

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Other income:
Accretion of fair value adjustment (discount) to regulatory assets due   to purchase accounting	$	4	$	6	$	14	$	18
Other		-		-		-		2
Total other income	$	4	$	6	$	14	$	20
Other deductions:
Professional fees	$	2	$	-	$	8	$	2
Other		-		1		3		2
Total other deductions	$	2	$	1	$	11	$	4

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Interest Expense and Related Charges

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Interest expense	$	90	$	90	$	270	$	275
Amortization of debt issuance costs and discounts		6		8		21		11
Allowance for funds used during construction – capitalized   interest portion		(2)		(2)		(8)		(7)
Total interest expense and related charges	$	94	$	96	$	283	$	279

Restricted Cash

All restricted cash amounts reported on our balance sheet at September 30, 2013 and December 31, 2012 relate to the transition bonds.

Trade Accounts Receivable

Trade accounts receivable reported on our balance sheet consisted of the following:

	At September 30,		At December 31,
	2013		2012
Gross trade accounts receivable	$	567	$	395
Trade accounts receivable from TCEH		(160)		(55)
Allowance for uncollectible accounts		(3)		(2)
Trade accounts receivable from nonaffiliates – net	$	404	$	338

Gross trade accounts receivable at September 30, 2013 and December 31, 2012 included unbilled revenues of $166 million and $147 million, respectively.  At both September 30, 2013 and December 31, 2012, REP subsidiaries of a nonaffiliated entity collectively represented approximately 14% of the nonaffiliated trade accounts receivable amount.  Trade accounts receivable from TCEH at December 31, 2012 reflects timing of payments in 2012.

Investments and Other Property

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

	At September 30,		At December 31,
	2013		2012
Assets related to employee benefit plans, including employee savings   programs, net of distributions	$	83	$	80
Land		2		3
Total investments and other property	$	85	$	83

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Property, Plant and Equipment

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

	At September 30,		At December 31,
	2013		2012
Total assets in service	$	16,891	$	16,083
Less accumulated depreciation		5,633		5,407
Net of accumulated depreciation		11,258		10,676
Construction work in progress		520		627
Held for future use		16		15
Property, plant and equipment – net	$	11,794	$	11,318

Intangible Assets

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

	At September 30, 2013						At December 31, 2012
	Gross						Gross
	Carrying		Accumulated				Carrying		Accumulated
	Amount		Amortization		Net		Amount		Amortization		Net
Identifiable intangible assets subject to amortization included in property, plant and equipment:
Land easements	$	434	$	81	$	353	$	295	$	79	$	216
Capitalized software		381		176		205		409		220		189
Total	$	815	$	257	$	558	$	704	$	299	$	405

Aggregate amortization expense for intangible assets totaled $8 million and $13 million for the three months ended September 30, 2013 and 2012, respectively, and $38 million and $39 million for the nine months ended September 30, 2013 and 2012, respectively.  The estimated aggregate amortization expense for each of the next five fiscal years from December 31, 2012 is as follows:

Year	Amortization Expense
2013	$	52
2014		55
2015		55
2016		51
2017		43

At both September 30, 2013 and December 31, 2012, 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 reported on our balance sheet consisted of the following:

	At September 30,		At December 31,
	2013		2012
Retirement plans and other employee benefits	$	1,529	$	1,495
Uncertain tax positions (including accrued interest)		60		169
Amount payable related to income taxes		14		-
Other		58		58
Total other noncurrent liabilities and deferred credits	$	1,661	$	1,722

We have been advised by EFH Corp. that approval by the Joint Committee on Taxation for the 1997 through 2002 IRS appeals settlement was received in May 2013 and that all issues contested have been resolved.  As a result, the liability for uncertain tax positions was reduced by $32 million in the second quarter of 2013.  This resolution also resulted in a $10 million net reduction to liability in lieu of deferred income taxes and a reversal of accrued interest and tax totaling $5 million ($3 million after tax), which is reported as a decrease in provision in lieu of income taxes.  We made a cash payment of $33 million to EFH Corp. in the third quarter of 2013, as required under the tax sharing agreement, to settle the liability resulting from the 1997 through 2002 IRS audit, and received a $10 million refund from EFH Corp. as a result of filing amended Texas franchise tax returns for 1997 through 2001.

The IRS audit for the years 2003 through 2006 was concluded in June 2011.  A significant number of adjustments to the originally filed returns for such years were proposed.  In March 2013, EFH Corp. and the IRS agreed on terms to resolve the disputed adjustments.  In the first quarter of 2013, we reduced the liability for uncertain tax positions by $76 million to reflect the terms of the agreement.  This reduction consisted of a $58 million increase to liability in lieu of deferred income taxes and a reversal of accrued interest and tax totaling $18 million ($12 million after tax), which is reported as a decrease in provision in lieu of income taxes.  Any cash income tax impact related to the conclusion of the 2003 through 2006 audit is expected to be immaterial. 

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2013		2012
Cash payments (receipts) related to:
Interest	$	300	$	291
Capitalized interest		(8)		(7)
Interest (net of amounts capitalized)		292		284
Amount in lieu of income taxes:
Federal		52		(18)
State		12		22
Total amount in lieu of income taxes		64		4
Noncash construction expenditures (a)		55		78

______________

(a) Represents end-of-period accruals.

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

The following discussion and analysis of our financial condition and results of operations for the three and nine months ended September 30, 2013 and 2012 should be read in conjunction with the condensed consolidated financial statements and the notes to those statements as well as the Risk Factors contained in our 2012 Form 10-K.

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 28%  and 29% of our reported total operating revenues for the nine months ended September 30, 2013 and 2012, respectively.  We are a direct, 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 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.

As noted in the Current Reports on Form 8-K filed with the SEC on April 15, 2013 and October 15, 2013 by EFH Corp., EFIH and Energy Future Competitive Holdings Company (EFCH) and subsequent SEC filings made by those entities, EFH Corp., EFIH, EFCH, TCEH and certain subsidiaries of EFH Corp., have engaged, and may continue in the future to engage, in discussions with certain unaffiliated creditors of EFCH, EFIH, TCEH and certain of TCEH’s subsidiaries regarding certain of those entities’ capital structures and long-term liquidity, including the possibility of restructuring transactions involving those companies.  We believe the “ring-fencing” measures discussed above mitigate our exposure to a bankruptcy or other restructuring transactions involving members of the Texas Holdings Group.    

Significant Activities and Events

Competitive Renewable Energy Zones (CREZ) — 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

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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, 2013, our cumulative CREZ-related capital expenditures totaled $1.842 billion, including $382 million during 2013.  We expect that all necessary permitting actions, other requirements and all line and station construction activities for our CREZ construction projects will be completed by the end of 2013.  Additional voltage support projects are expected to be completed by early 2014, with the exception of one series capacitor project that is scheduled to be completed in December 2015 in order to allow for further study and evaluation.  The delay to 2015 is not expected to have a significant impact on the ability of the CREZ system to support existing or currently expected renewable generation.

For information regarding other matters with the PUCT, see discussion below under “Regulation and Rates.”

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RESULTS OF OPERATIONS

Operating Data

	Three Months Ended			Nine Months Ended
	September 30,		%	September 30,		%
	2013	2012	Change	2013	2012	Change
Operating statistics:
Electric energy billed volumes (gigawatt-hours):
Residential	14,165	14,259	(0.7)	32,166	32,278	(0.3)
Other (a)	20,082	19,834	1.3	53,326	53,188	0.3
Total electric energy billed volumes	34,247	34,093	0.5	85,492	85,466	-
Reliability statistics (b):
System Average Interruption Duration Index (SAIDI) (nonstorm)				109.5	99.0	10.6
System Average Interruption Frequency Index (SAIFI) (nonstorm)				1.4	1.3	7.7
Customer Average Interruption Duration Index (CAIDI) (nonstorm)				77.2	78.8	(2.0)
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of active meters)				3,275	3,232	1.3

	Three Months Ended						Nine Months Ended
	September 30,				$		September 30,				$
	2013		2012		Change		2013		2012		Change
Operating revenues:
Distribution base rates	$	532	$	526	$	6	$	1,387	$	1,382	$	5
Reconcilable rates (c)		271		235		36		768		697		71
Third-party transmission revenues		111		100		11		324		296		28
Advanced metering surcharges		36		37		(1)		114		104		10
Other miscellaneous revenues (d)		16		27		(11)		47		57		(10)
Total operating revenues	$	966	$	925	$	41	$	2,640	$	2,536	$	104

_____________

(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, 2013 and 2012 data.

(c)    Includes TCRF revenues and energy efficiency surcharges.  Also includes transition charge revenue totaling $44 million and $42 million for the three months ended September 30, 2013 and 2012, respectively, and $113 million and $111 million for the nine months ended September 30, 2013 and 2012, respectively,  associated with the issuance of transition bonds.

(d)    Includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs, rents, energy efficiency performance bonus and other miscellaneous revenues.

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Financial Results — Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

Total operating revenues increased $41 million, or 4%, to $966 million in 2013.  The change reflected:

· a $6 million increase in distribution base rate revenues consisting of an estimated $5 million effect of growth in points of delivery and a $1 million impact of higher average consumption;

· a $36 million increase in reconcilable rate revenues (those in which recognized revenues equal incurred costs) consisting of a $4 million increase in energy efficiency surcharges (offset in operation and maintenance expense), a $30 million increase in TCRF revenues driven by higher wholesale transmission service expense  ($23 million of which was from third parties)  and a $2 million increase in charges related to transition bonds (with an offsetting increase in amortization expense);

· $11 million in higher third-party transmission revenues reflecting rate increases to recover ongoing investment in the transmission system;    

· a $1 million decrease in recognized revenues from the advanced metering deployment surcharge reflecting lower costs associated with meter installation and systems development completed in 2012, and

· an $11 million decrease in other miscellaneous revenues, consisting primarily of a $9 million energy efficiency performance bonus recognized in 2012.  We received final approval of a $12 million energy efficiency performance bonus in October 2013.

Wholesale transmission service expense increased $23 million, or 19%, to $146 million in 2013 due to higher fees paid to other transmission entities and a 2% increase in volumes.

Operation and maintenance expense totaled $169 million in each of 2013 and 2012.  Amortization of regulatory assets reported in operation and maintenance expense totaled $13 million and $14 million for the three months ended September 30, 2013 and 2012, respectively.

Depreciation and amortization increased $6 million, or 3%, to $207 million in 2013.  The increase reflected $2 million attributed to ongoing investments in property, plant and equipment, $2 million attributed to investments related to the deployment of advanced meters completed in 2012 and $2 million in higher amortization of regulatory assets associated with transition bonds (with an offsetting decrease in revenues).

Other income totaled $4 million in 2013 and $6 million in 2012, and for both periods, consisted entirely of the accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting.  See Note 10 to Financial Statements.

Other deductions totaled $2 million and $1 million in 2013 and 2012, respectively.  See Note 10 to Financial Statements.

Provision in lieu of income taxes totaled $94 million in 2013 (including $93 million related to operating income and $1 million related to nonoperating income) compared to $92 million (including $89 million related to operating income and $3 million related to nonoperating income) in 2012.  The effective income tax rate on pretax income was 39.2% in 2013 and 39.8% in 2012.  The 2013 effective income tax rate on pretax income differs from the US federal statutory rate of 35% primarily due to $4 million of non-deductible amortization of the regulatory asset attributed to a change in deductibility of the Medicare Part D subsidy as a result of the Patient Protection and Affordable Care Act of 2010 and the effect of the 2013 Texas margin tax.

Interest income decreased $3 million in 2013.  The change reflected a $2 million decrease as a result of our sale of the TCEH transition bond interest reimbursement agreement to EFIH in August 2012 (see Note 11 to Financial Statements in our 2012 Form 10-K for discussion of the sale) and the effect of a sales tax refund in 2012.

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Interest expense and related charges decreased $2 million, or 2%, to $94 million in 2013.  The change was driven by $2 million in lower amortization of net debt-related costs.

Net income increased $7 million, or 5%, to $146 million in 2013.  The change reflected increased revenue from higher transmission rates and growth in points of delivery,  partially offset by higher depreciation, lower interest income and higher income taxes.

Financial Results — Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Total operating revenues increased $104 million, or 4%, to $2,640 million in 2013.  The change reflected:

· a $5 million increase in distribution base rate revenues consisting of an estimated $14 million effect of growth in points of delivery, partially offset by a  $9 million impact of lower average consumption, primarily due to the effects of milder weather in 2013 as compared to 2012;

· a $71 million increase in reconcilable rate revenues (those in which recognized revenues equal incurred costs) consisting of a $13 million increase in energy efficiency surcharges (offset in operation and maintenance expense), a $55 million increase in TCRF revenues driven by higher wholesale transmission service expense  ($39 million of which was from third parties) and a $3 million increase in charges related to transition bonds (with an offsetting increase in amortization expense);

· $28 million in higher third-party transmission revenues reflecting rate increases to recover ongoing investment in the transmission system;

· a $10 million increase in recognized revenues from the advanced metering deployment surcharge due to increased costs driven by meter installation and systems development completed in 2012, and

· a $10 million decrease in other miscellaneous revenues, consisting primarily of a $9 million energy efficiency performance bonus recognized in 2012.  We received final approval of a $12 million energy efficiency performance bonus in October 2013.

Wholesale transmission service expense increased $39 million, or 10%, to $417 million in 2013.  Third-party wholesale transmission service expense increased $48 million in 2013 due to higher fees paid to other transmission entities and a 2% increase in volumes, partially offset by a $9 million charge associated with a wholesale transmission cost settlement in 2012.

Operation and maintenance expense increased $7 million, or 1%, to $502 million in 2013.  The change included $7 million in higher labor costs and $3 million in higher employee benefit costs, offset by $9 million in lower vegetation management expenses, $6 million in lower professional and outside services and $2 million in lower amortization of regulatory assets.  Operation and maintenance expense also reflects fluctuations in expenses that are offset by corresponding revenues, including a $13 million increase in costs related to programs designed to improve customer electricity efficiency and a $1 million increase related to advanced meters.  Amortization of regulatory assets reported in operation and maintenance expense totaled $39 million and $41 million for the nine months ended September 30, 2013 and 2012, respectively.

Depreciation and amortization increased $31 million, or 5%, to $608 million in 2013.  The increase reflected $17 million attributed to ongoing investments in property, plant and equipment, $11 million attributed to investments related to the deployment of advanced meters completed in 2012 and $3 million in higher amortization of regulatory assets associated with transition bonds (with an offsetting increase in revenues).

Other income totaled $14 million in 2013 and $20 million in 2012.  The 2013 and 2012 amounts included accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting totaling $14 million and $18 million, respectively.  See Note 10 to Financial Statements.

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Other deductions totaled $11 million and $4 million in 2013 and 2012, respectively.  See Note 10 to Financial Statements.

Provision in lieu of income taxes totaled $191 million in 2013 (including $190 million related to operating income and $1 million related to nonoperating income) compared to $213 million (including $198 million related to operating income and $15 million related to nonoperating income) in 2012.  The effective income tax rate on pretax income was 36.7% in 2013 and 39.9% in 2012.  The 2013 effective income tax rate on pretax income differs from the US federal statutory rate of 35% primarily due to $11 million of non-deductible amortization of the regulatory asset attributed to a change in deductibility of the Medicare Part D subsidy as a result of the Patient Protection and Affordable Care Act of 2010 and the effect of the 2013 Texas margin tax,  partially offset by the reversal of accrued interest and taxes totaling $15 million attributed to favorable resolution of certain uncertain tax positions.

Interest income decreased $22 million, or 92%, to $2 million in 2013.  The change reflected a $16 million decrease as a result of our sale of the TCEH transition bond interest reimbursement agreement to EFIH in August 2012 (see Note 11 to Financial Statements in our 2012 Form 10-K for discussion of the sale) and a $6 million decrease related to a prior year sales tax refund.    

Interest expense and related charges increased $4 million, or 1%, to $283 million in 2013.  The change was driven by $10 million in higher amortization of net debt-related costs and a $3 million increase attributable to higher average borrowings reflecting ongoing capital investments, partially offset by a $9 million decrease attributable to lower average interest rates.

Net income increased $8 million, or 2%, to $329 million in 2013.  The change reflected increased revenue from higher transmission rates and growth in points of delivery and lower income taxes, partially offset by higher depreciation, lower interest income and higher operation and maintenance expenses.

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows — Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Cash provided by operating activities totaled $910 million and $815 million in the nine months ended September 30, 2013 and 2012, respectively.  The $95 million increase was driven by an  $82 million decrease in contributions to pension and OPEB plans, a $73 million increase in transmission and distribution revenue receipts due to higher rates and a  $29 million decrease in energy efficiency program payments.  These increases in cash were partially offset by a $60 million increase in estimated federal income tax payments and a $29 million decrease in federal income tax reimbursements from TCEH as a result of the sale of our tax reimbursement agreement to EFIH in August 2012.

Cash used in financing activities totaled $72 million and cash provided by financing activities totaled $291 million in the nine months ended September 30, 2013 and 2012, respectively.  The 2013 activity reflected $215 million of cash used in distributions to our members (reflecting a $60 million increase from 2012 (see Note 7 to Financial Statements) and $84 million in cash principal payments on transition bonds (reflecting a $5 million increase from 2012 (see Note 5 to Financial Statements)),  partially offset by a $125 million increase in short-term borrowings, a $100 million increase from the issuance of long-term debt in May 2013 and a $2 million increase in net debt discount, premium, financing and reacquisition expenses.

Cash used in investing activities, which consisted primarily of capital expenditures, totaled $866 million and $1,109 million in the nine months ended September 30, 2013 and 2012, respectively.  The $243 million, or 22%, decrease was driven by lower capital expenditures primarily for advanced metering deployment initiatives completed in 2012 and CREZ.

Depreciation and amortization expense reported in the condensed statements of consolidated cash flows was $26 million more and $23 million more than the amounts reported in the condensed statements of consolidated income for the nine months ended September 30, 2013 and 2012, respectively.  The differences represent the

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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 the nine months ended September 30, 2013 totaled $84 million and represent transition bond principal payments at scheduled maturity dates (see Note 5 to Financial Statements). 

See Note 5 to Financial Statements for additional information regarding repayments and issuance of 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, 2013, we had a $2.4 billion secured revolving credit facility.  The revolving credit facility expires in October 2016.  Subject to the limitations described below, available borrowing capacity under our revolving credit facility totaled $1.534 billion and $1.659 billion at September 30, 2013 and December 31, 2012, respectively.  We may request an increase in our borrowing capacity of $100 million in the aggregate and up to two one-year extensions, provided certain conditions are met, including lender approval.

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, 2013, 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 have been 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 have been certified to the Deed of Trust collateral agent.  At September 30, 2013, the available bond credits totaled $2.061 billion, and the amount of additional potential indebtedness that could be secured by property additions, subject to the completion of a certification process, totaled $1.112 billion.  At September 30, 2013, the available borrowing capacity of the revolving credit facility could be fully drawn.

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.

Cash and cash equivalents totaled $17 million and $45 million at September 30, 2013 and December 31, 2012, respectively.  Available liquidity (cash and available credit facility capacity) at September 30, 2013 totaled $1.551 billion reflecting a decrease of $153 million from December 31, 2012.  The change reflects our ongoing capital investment in transmission and distribution infrastructure.

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, 2013 and December 31, 2012, our regulatory capitalization ratios were 58.7% debt and 41.3% equity and 58.8% debt and 41.2% equity, respectively.  See Note 7 to Financial Statements for discussion of the regulatory capitalization ratio.

Liquidity Needs, Including Capital Expenditures — We expect our capital expenditures to total approximately $1.1 billion in 2013, and approximately $1.0 billion in each of the years 2014 through 2017,

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including amounts related to CREZ construction and voltage support projects totaling approximately $400 million in 2013, $160 million in 2014 and $30 million in 2015.  These capital expenditures are expected to be used for investment in transmission and distribution infrastructure.

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.

Distributions — On October 29, 2013, our board of directors declared a cash distribution of $95 million, which was paid to our members on October 31, 2013.  During the nine months ended September 30, 2013, our board of directors declared, and we paid the following cash distributions to our members:

Declaration Date	Payment Date	Amount
July 31, 2013	August 1, 2013	$	95
May 1, 2013	May 2, 2013	$	70
February 13, 2013	February 15, 2013	$	50

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

Pension and OPEB Plan Funding — Our funding for the pension plans and the OPEB Plan for the calendar year 2013 is expected to total $10 million and $12 million, respectively.  In the nine months ended September 30, 2013, we made cash contributions to the pension plans and the OPEB Plan of $8 million and $9 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, 2013, we were in compliance with this covenant with a senior debt-to-capitalization ratio of 0.46 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.

Most of our large suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions with us.  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.

Presented below are the credit ratings assigned for our debt securities at October 31, 2013.  Oncor is on “stable” outlook with S&P, Fitch and Moody’s.

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	Senior Secured
S&P	A
Fitch	BBB+
Moody’s	Baa3

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 1.50%.  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 ($860 million in short-term borrowings and $6 million in letters of credit at September 30, 2013) 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, 2013, we did not have any material off-balance sheet arrangements with special purpose entities or variable interest entities.

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, 2013 that are expected to materially impact us.

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REGULATION AND RATES

Matters with the PUCT

Transmission Cost Recovery and TCRF Rates  —TCRF is a rate charged to REPs to recover fees paid to other transmission service providers under their TCOS rates and the retail portion of our own TCOS rate.  PUCT rules require us to update the TCRF component of our retail delivery rates twice a year.  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).  Approved TCRF filings impacting cash flow in or after the three- and nine-month periods ended September 30, 2013 and 2012 are listed below (millions of dollars).

			Semi-Annual
			Billing Impact
Docket No.	Filed	Effective	Increase (Decrease)
41543	June 2013	September 2013 – February 2014	$	88
41002	November 2012	March 2013 – August 2013	$	(47)
40451	June 2012	September 2012 – February 2013	$	129
39940	November 2011	March 2012 – August 2012	$	(41)

Transmission Interim Rate Update Applications — In order to reflect changes in our invested transmission capital, PUCT rules allow us to update our TCOS rates by filing up to two interim TCOS rate adjustments in a calendar year.  The TCOS rate is charged directly to third-party distribution service providers benefitting from our transmission system and, through the TCRF mechanism, to REPs with retail customers in our service territory.  TCOS filings impacting revenues in or after the three- and nine-month periods ended September 30, 2013 and 2012 are listed below (millions of dollars).

Docket No.	Filed	Effective	Annual Revenue Impact		Third Party Wholesale Transmission		Included in TCRF
41706	July 2013	September 2013	$	71	$	45	$	26
41166	January 2013	March 2013	$	27	$	17	$	10
40603	July 2012	August 2012	$	30	$	19	$	11
40142	January 2012	March 2012	$	2	$	1	$	1

Application for Energy Efficiency Cost Recovery Factors (EECRF) —The EECRF is a reconcilable rate designed to recover current energy efficiency program costs and performance bonuses earned by exceeding PUCT targets in prior years and to recover or refund any under-/over-recovery of our costs in prior years.  PUCT rules require us to make an annual EECRF filing by the first business day in June of each year for implementation in the next calendar year.  Approved EECRF filings impacting revenues in or after the three- and nine-month periods ended September 30, 2013 and 2012 are listed below (millions of dollars, except monthly charge amounts).

Docket No.	Filed	Effective	Monthly Charge per Residential Customer			Program Costs		Performance Bonus		Under-/  (Over)- Recovery
41544	May 2013	March 2014	$	1.01	*	$	62	$	12	$	(1)
40361	May 2012	January 2013	$	1.23		$	62	$	9	$	2
39375	May 2011	January 2012	$	0.99		$	49	$	8	$	(3)

__________

*      Monthly charge of $1.01 is for a residential customer using 1,000 kWh, as the energy efficiency substantive rules require rates to be on a volumetric basis as of March 2014 rather than a fixed monthly charge.

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Application for Reconciliation of Advanced Meter Surcharge (PUCT Docket No. 41814) — In September 2013, we filed an application with the PUCT for reconciliation of all costs incurred and investments made from January 1, 2011 through December 31, 2012, in the deployment of our AMS (advanced metering system) pursuant to the AMS Deployment Plan approved in Docket No. 35718.  During the 2011 to 2012 period, we incurred approximately $300 million of capital expenditures and $34 million of operating and maintenance expense, and billed customers approximately $174 million through the AMS surcharge.  In addition to the reconciliation, we are seeking a finding from the PUCT that approximately $28 million of additional estimated capital expenditures and approximately $4 million of additional estimated annual operation and maintenance expense related to cyber security and disaster recovery protections are reasonable and necessary costs associated with the deployment of an advanced metering system are recoverable through the AMS surcharge.   We are not seeking a change in the AMS surcharge in this proceeding, and anticipate that the proceeding will be concluded in the second quarter of 2014.

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.  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.

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.

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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, 2013 and December 31, 2012 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” in our 2012 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 net exposure to credit risk associated with accounts receivables from affiliates totaled $154 million at September 30, 2013, consisting of $109 million of billed receivables and $53 million of unbilled receivables, of which $8  million is secured by letters of credit posted by TCEH for our benefit. Under PUCT rules, unbilled amounts are billed within the following month and amounts are due in 35 days of billing.  Due to commitments made to the PUCT, this concentration of affiliate receivables increases the risk that a default could have a material effect on earnings and cash flows.  See Note 9 to Financial Statements for additional information regarding our transactions with affiliates.

Our exposure to credit risk associated with accounts receivable from nonaffiliates totaled $407 million at September 30, 2013.  The nonaffiliated receivable amount is before the allowance for uncollectible accounts, which totaled $3 million at September 30, 2013.  The nonaffiliated exposure includes trade accounts receivable from REPs totaling $310 million, which are almost entirely noninvestment grade.  At September 30, 2013,  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 trade accounts receivable amount.  We view our exposure to this customer to be within an acceptable level of risk tolerance considering PUCT rules and regulations; however, this concentration increases the risk that a default could have a material effect on cash flows.

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain “forward-looking statements.”  All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of 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 2012 Form 10-K and the discussion under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2012 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 US Federal Energy Regulatory Commission, the PUCT, the North American Electric Reliability Corporation, the Texas Reliability Entity, Inc., the Environmental Protection Agency, and the Texas Commission on Environmental Quality, with respect to:

o allowed rate of return;

o permitted capital structure;

o industry, market and rate structure;

o recovery of investments;

o acquisition and disposal of assets and facilities;

o operation and construction of facilities;

o changes in tax laws and policies, and

o 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;

· effects of a bankruptcy or other restructuring transactions, and negotiations relating thereto, involving members of the Texas Holdings Group;

· 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;

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

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

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

· actions by credit rating agencies, and

· our ability to effectively execute our operational strategy.

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

ITEM 4.   CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect at the end of the current period included in this 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.

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PART II.  OTHER INFORMATION

ITEM 1.   LEGAL PROCEEDINGS

Reference is made to the discussion in Notes 2 and 6 to Financial Statements regarding legal and regulatory proceedings.

ITEM 1A.   RISK FACTORS

There are numerous factors that affect our business and results of operations, many of which are beyond our control.  In addition to the other information set forth in this report, including “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” you should carefully consider the factors discussed in “Part I, Item 1A. Risk Factors” in our 2012 Form 10-K, 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

None.

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ITEM 6.   EXHIBITS

(a)   Exhibits provided as part of Part II are:
Exhibits	Previously Filed* With File Number	As Exhibit
(10)	Material Contracts.
	Material Contracts; Compensatory Plans, Contracts and Arrangements.
10(a)	333-100240 Form 8-K (filed October 7, 2013)	10.1	—	Form of Indemnification Agreement.
(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, 2013.
	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

__________________

*  Incorporated herein by reference.

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SIGNATURE

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

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 31, 2013

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EXHIBIT INDEX

4
Exhibits	Previously Filed* With File Number	As Exhibit
(10)	Material Contracts.
	Material Contracts; Compensatory Plans, Contracts and Arrangements.
10(a)	333-100240 Form 8-K (filed October 7, 2013)	10.1	—	Form of Indemnification Agreement.
(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, 2013.
	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

__________________

*  Incorporated herein by reference. 

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