Oncor Electric Delivery 10-K 2012 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2012

— OR —

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

Commission File Number 333-100240

Oncor Electric Delivery Company LLC

(Exact name of registrant as specified in its charter)

Delaware	75-2967830
(State of Organization)	(I.R.S. Employer Identification No.)
1616 Woodall Rodgers Fwy., Dallas, TX 75202	(214) 486-2000
(Address of principal executive offices)(Zip Code)	(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  þ    No  ¨

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

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  þ    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

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

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

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

Aggregate market value of Oncor Electric Delivery Company LLC common membership interests held by non-affiliates: None

As of February 19, 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.

DOCUMENTS INCORPORATED BY REFERENCE- None

TABLE OF CONTENTS

		PAGE
GLOSSARY			ii
PART I
Items 1 and 2. BUSINESS AND PROPERTIES			1
Item 1A.	RISK FACTORS		6
Item 1B.	UNRESOLVED STAFF COMMENTS		13
Item 3.	LEGAL PROCEEDINGS		13
Item 4.	MINE SAFETY DISCLOSURES		13
PART II
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED EQUITY HOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		14
Item 6.	SELECTED FINANCIAL DATA		14
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		15
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		34
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		36
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		71
Item 9A.	CONTROLS AND PROCEDURES		71
Item 9B.	OTHER INFORMATION		73
PART III
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		74
Item 11.	EXECUTIVE COMPENSATION		85
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED EQUITY HOLDER MATTERS		128
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		132
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		142
PART IV
Item 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES		144

Oncor Electric Delivery Company LLC’s (Oncor) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the Oncor website at http://www.oncor.com as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on Oncor’s website or available by hyperlink from the website shall not be deemed a part of, or incorporated by reference into, this report on Form 10-K. The representations or warranties contained in any agreement that we have filed as an exhibit to this Form 10-K or that we have or may publicly file in the future may contain representations or 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-K and other Securities and Exchange Commission filings of Oncor and its subsidiary occasionally make references to Oncor (or “we,” “our,” “us” or “the company”) when describing actions, rights or obligations of its subsidiary. These references reflect the fact that the subsidiary is consolidated with Oncor for financial reporting purposes. However, these references should not be interpreted to imply that Oncor is actually undertaking the action or has the rights or obligations of its subsidiary or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or of any other affiliate.

i

GLOSSARY

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

Bondco	Refers to Oncor Electric Delivery Transition Bond Company LLC, a wholly-owned consolidated bankruptcy-remote financing subsidiary of Oncor that has issued securitization (transition) bonds to recover certain regulatory assets and other costs.
CREZ	Competitive Renewable Energy Zone
Deed of Trust	Deed of Trust, Security Agreement and Fixture Filing, dated as of May 15, 2008, made by Oncor to and for the benefit of The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, formerly The Bank of New York), as collateral agent, as amended
EFH Corp.	Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include Oncor and TCEH.
EFH Retirement Plan	Refers to the defined benefit pension plan sponsored by EFH Corp., in which Oncor participates. In 2012, EFH Corp. made various changes to the EFH Retirement Plan, including splitting off all of the assets and liabilities associated with Oncor employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses) into a new plan. See Oncor Retirement Plan below.
EFIH	Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.
EPA	US Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
ERISA	Employee Retirement Income Security Act of 1974, as amended
FERC	US Federal Energy Regulatory Commission
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
kV	kilovolts
kWh	kilowatt-hours
LIBOR	London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
Limited Liability Company Agreement	The Second Amended and Restated Limited Liability Company Agreement of Oncor, dated as of November 5, 2008, by and among Oncor Holdings, Texas Transmission and Investment LLC, as amended
Luminant	Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.

ii

Moody’s	Moody’s Investors Services, Inc. (a credit rating agency)
MW	megawatts
NERC	North American Electric Reliability Corporation
Oncor	Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings, and/or its wholly-owned consolidated bankruptcy-remote financing subsidiary, Bondco, depending on context.
Oncor Holdings	Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIH and the direct majority owner (approximately 80.03%) of Oncor, and/or its subsidiaries, depending on context.
Oncor Retirement Plan	Refers to the defined benefit pension plan sponsored by Oncor. In 2012, EFH Corp. made various changes to the EFH Retirement Plan, including splitting off all of the assets and liabilities associated with Oncor employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses) into a new plan. Effective January 1, 2013, Oncor assumed sponsorship of this new plan.
Oncor Ring-Fenced Entities	Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.
OPEB	other postretirement employee benefits
OPEB Plan	Refers to an EFH Corp.-sponsored plan (in which Oncor 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.
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act
purchase accounting	The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs, are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
REP	retail electric provider
S&P	Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc. (a credit rating agency)
SARs	Stock Appreciation Rights
SARs Plan	Refers to the Oncor Stock Appreciation Rights Plan.
SEC	US Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
Sponsor Group	Refers collectively to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (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.
Supplemental Retirement Plan	Refers to the Oncor Supplemental Retirement Plan.
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.
TCEQ	Texas Commission on Environmental Quality

iii

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 Transmission	Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is an entity indirectly owned by a private investment group led by OMERS Administration Corporation, acting through its infrastructure investment entity, Borealis Infrastructure Management Inc., and the Government of Singapore Investment Corporation, acting through its private equity and infrastructure arm, GIC Special Investments Pte Ltd. Texas Transmission is not affiliated with EFH Corp., any of EFH Corp.’s subsidiaries or any member of the Sponsor Group.
TRE	Refers to Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and ERCOT protocols.
TXU Energy	Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.
US	United States of America
VIE	variable interest entity

iv

PART I

Items 1. and 2. BUSINESS AND PROPERTIES

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” on page ii for definition of terms and abbreviations.

Overview of Oncor

We are a regulated electricity transmission and distribution company that provides the essential service of delivering electricity safely, reliably and economically to end-use consumers through our distribution systems, as well as providing transmission grid connections to merchant generation plants and interconnections to other transmission grids in Texas. 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 beneficially own our remaining outstanding membership interests. We are a limited liability company organized under the laws of the State of Delaware, formed in 2007 as the successor entity to Oncor Electric Delivery Company, a corporation formed under the laws of the State of Texas in 2001.

Our transmission and distribution assets are located principally in the north-central, eastern and western parts of Texas. This territory has an estimated population in excess of ten million, about forty percent of the population of Texas, and comprises 91 counties and over 400 incorporated municipalities, including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler and Killeen. We are not a seller of electricity, nor do we purchase electricity for resale. We provide transmission services to other electricity distribution companies, cooperatives, municipalities and REPs. We provide distribution services to REPs, including subsidiaries of TCEH, which sell electricity to retail customers. Revenues from TCEH represented 29% of our total reported consolidated revenues for the year ended December 31, 2012. Our transmission and distribution rates are regulated by the PUCT, and in certain instances, by the FERC. The company is managed as an integrated business; consequently, there are no reportable segments.

We operate the largest transmission and distribution system in Texas, delivering electricity to more than 3.2 million homes and businesses and operating more than 119,000 miles of transmission and distribution lines. Most of our power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law. At December 31, 2012, we had approximately 3,500 full-time employees, including approximately 790 employees under collective bargaining agreements.

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.

In November 2008, we sold equity interests to Texas Transmission. We also indirectly sold equity interests to certain members of our board of directors and management team. Accordingly, after giving effect to all equity issuances, at December 31, 2012, the ownership of our outstanding membership interests was as follows: 80.03% held by Oncor Holdings and indirectly by EFH Corp., 19.75% held by Texas Transmission and 0.22% held indirectly by certain members of our board of directors and management team.

1

Oncor’s Market (ERCOT statistics below were derived from information published by ERCOT)

We operate within the ERCOT market. This market represents approximately 85% of the electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the Independent System Operator (ISO) of the interconnected transmission grid for those systems. ERCOT is responsible for ensuring reliability, adequacy and security of the electric systems, as well as nondiscriminatory access to transmission service by all wholesale market participants in the ERCOT region. ERCOT’s membership consists of approximately 300 corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, transmission service providers and distribution services providers, independent REPs and consumers.

In 2012, ERCOT’s hourly demand peaked at 66,548 MW as compared to the record peak demand of 68,305 in 2011. The ERCOT market has limited interconnections to other markets in the US and Mexico, which currently limits potential imports into and exports out of the ERCOT market to 1,106 MW of generation capacity (or approximately 2% of peak demand). In addition, wholesale transactions within the ERCOT market are generally not subject to regulation by the FERC.

The ERCOT market operates under reliability standards set by NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’ main interconnected transmission grid. We, along with other owners of transmission and distribution facilities in Texas, assist the ERCOT ISO in its operations. We have planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations we own, primarily within our certificated distribution service area. We participate with the ERCOT ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing and constructing new transmission lines in order to remove existing constraints and interconnect generation on the ERCOT transmission grid. The new transmission lines are necessary to meet reliability needs, support renewable energy production and increase bulk power transfer capability.

Oncor’s Strategies

We focus on delivering electricity in a safe and reliable manner, minimizing service interruptions and investing in our transmission and distribution infrastructure to maintain our system, serve our growing customer base with a modernized grid and support renewable energy production.

We believe that building and leveraging upon opportunities to scale our operating advantage and technology programs enables us to create value by eliminating duplicative costs, efficiently managing supply costs, and building and standardizing distinctive process expertise over a larger grid. Scale also allows us to take part in large capital investments in our transmission and distribution system, with a smaller fraction of overall capital at risk and with an enhanced ability to streamline costs. Our growth strategies are to invest in technology upgrades, including advanced metering systems initiatives, and to construct new transmission and distribution facilities to meet the needs of the growing Texas market and support renewable energy production. We and other transmission and distribution businesses in ERCOT benefit from regulatory capital recovery mechanisms known as “capital trackers” that we believe enable adequate and timely recovery of transmission, distribution and advanced metering investments through our regulated rates.

Oncor’s Operations

Performance — We achieved or exceeded market performance protocols in 12 out of 14 PUCT market metrics in 2012. These metrics measure the success of transmission and distribution companies in facilitating customer transactions in the competitive Texas electricity market.

Investing in Infrastructure and Technology —In 2012, we invested approximately $1.4 billion in our network to construct, rebuild and upgrade transmission lines and associated facilities, to extend the distribution infrastructure, and to pursue certain initiatives in infrastructure maintenance and information technology. Reflecting our commitment to infrastructure, in September 2008, we and several other ERCOT utilities filed with the PUCT a plan to participate in the construction of transmission improvements designed to interconnect existing and future renewable energy facilities to transmit electricity from CREZs identified by the PUCT. In 2009, the PUCT awarded us CREZ construction projects 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,

2

principally wind generation facilities, in west Texas to population centers in the eastern part of the state. In addition to these projects, ERCOT completed a study in December 2010 that will result in us and other transmission service providers building additional facilities to provide further voltage support to the transmission grid as a result of CREZ. We currently estimate, based on these additional voltage support facilities and the approved routes and stations for our awarded CREZ projects, that CREZ construction costs will total approximately $2.0 billion. CREZ-related costs could change based on finalization of costs for the additional voltage support facilities and final detailed designs of subsequent project routes. At December 31, 2012, our cumulative CREZ-related capital expenditures totaled $1.460 billion, including $561 million in 2012. 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. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulation and Rates.”

Our technology upgrade initiatives include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is producing electricity service reliability improvements and providing for additional products and services from REPs that enable businesses and consumers to better manage their electricity usage and costs. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits. With the new meters integrated, we report 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options.

At December 31, 2012, we had installed 3,263,000 advanced digital meters (including 961,000 during 2012) completing our planned deployment of advanced meters to all residential and most non-residential retail electricity customers in our service area. Cumulative capital expenditures for the deployment of the advanced meter system totaled $660 million through December 31, 2012, including $142 million in 2012.

In a stipulation with several parties that was approved by the PUCT (as discussed in Note 2 to Financial Statements), we committed to a variety of actions, including minimum capital spending of $3.6 billion and spending an additional $100 million in excess of regulatory requirements on energy efficiency initiatives over the five-year period ending December 31, 2012, subject to certain defined conditions. At December 31, 2012, we had satisfied our commitments to the PUCT with respect to this spending.

In addition to the potential energy efficiencies from advanced metering and the $100 million in energy efficiency spending discussed above, we spent approximately $240 million over the five-year period ending December 31, 2012 in programs designed to improve customer electricity demand efficiencies, including approximately $50 million in 2012.

Electricity Transmission —Our electricity transmission business is responsible for the safe and reliable operations of our transmission network and substations. These responsibilities consist of the construction and maintenance of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over our transmission facilities in coordination with ERCOT.

We are a member of ERCOT, and our transmission business actively assists the operations of ERCOT and market participants. Through our transmission business, we participate with ERCOT and other member utilities to plan, design, construct and operate new transmission lines, with regulatory approval, necessary to maintain reliability, interconnect to merchant generation facilities, increase bulk power transfer capability and minimize limitations and constraints on the ERCOT transmission grid.

Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to an interconnection to other markets, the FERC. Network transmission revenues compensate us for delivery of electricity over transmission facilities operating at 60 kV and above. Other services we offer through our transmission business include, but are not limited to: system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.

3

PURA allows us to update our transmission rates periodically to reflect changes in invested capital. This “capital tracker” provision encourages investment in the transmission system to help ensure reliability and efficiency by allowing for timely recovery of and return on new transmission investments.

At December 31, 2012 our transmission facilities included 5,760 circuit miles of 345kV transmission lines and 9,713 circuit miles of 138kV and 69kV transmission lines. Sixty-four generation facilities totaling 33,880 MW were directly connected to our transmission system at December 31, 2012, and 288 transmission stations and 708 distribution substations were served from our transmission system.

At December 31, 2012, our transmission facilities had the following connections to other transmission grids in Texas:

	Number of Interconnected Lines
Grid Connections	345kV		138kV		69kV
Centerpoint Energy Inc.		8		—		—
American Electric Power Company, Inc (a)		6		7		11
Lower Colorado River Authority		10		22		3
Texas Municipal Power Agency		7		6		—
Texas New Mexico Power		4		9		12
Brazos Electric Power Cooperative, Inc.		8		109		22
Lone Star Transmission		12		—		—
Electric Transmission Texas, LLC		2		1		—
Rayburn Country Electric Cooperative, Inc.		—		38		6
Tex-La Electric Cooperative of Texas, Inc.		—		12		1
Other small systems operating wholly within Texas		—		7		2

(a) One of the 345-kV lines is an asynchronous high-voltage direct current connection with the Southwest Power Pool.

Electricity Distribution — Our electricity distribution business is responsible for the overall safe and efficient operation of distribution facilities, including electricity delivery, power quality and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the distribution system within our certificated service area. Our distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through 3,169 distribution feeders.

Our distribution system includes over 3.2 million points of delivery at December 31, 2012. Over the past five years, the number of distribution system points of delivery we serve, excluding lighting sites, grew an average of 1.07% per year, adding approximately 40,000 points of delivery in 2012.

Our distribution system consists of 56,615 miles of overhead primary conductors, 21,497 miles of overhead secondary and street light conductors, 15,898 miles of underground primary conductors and 9,840 miles of underground secondary and street light conductors. The majority of the distribution system operates at 25kV and 12.5kV.

Distribution rates for residential and small business users are based on actual monthly consumption (kWh), and rates for large commercial and industrial users are based primarily on the greater of actual monthly demand (kilowatts) or 80% of peak monthly demand during the prior eleven months.

As directed by Senate Bill 1693, which was passed by the Texas Legislature in 2011, the PUCT approved a periodic rate adjustment rule in September 2011, which allows utilities to file, under certain circumstances, up to four rate adjustments between rate reviews to recover distribution-related investments on an interim basis.

Customers —Our transmission customers consist of municipalities, electric cooperatives and other distribution companies. Our distribution customers consist of more than 80 REPs, including TCEH and certain electric cooperatives in our certificated service area. Revenues from TCEH represented 29% of our total operating revenues in 2012. Revenues from REP subsidiaries of a nonaffiliated entity collectively represented 15% of our total operating revenues in 2012. No other customer represented more than 10% of our total operating revenues. The consumers of the electricity we deliver are free to choose their electricity supplier from REPs who compete for their business.

Seasonality—Our revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.

4

Regulation and Rates —As our operations are wholly within Texas, we believe we are not a public utility as defined in the Federal Power Act and, as a result, we are not subject to general regulation under this act. However, we are subject to reliability standards adopted and enforced by the TRE and the NERC (including critical infrastructure protection) under the Federal Power Act. See Item 1A. “RISK FACTORS –As a transmission operator, we are subject to mandatory reliability standards and periodic audits of our compliance with those standards. Efforts to comply with those standards could subject us to higher operating costs and/or increased capital expenditures, and non-compliance with applicable standards could subject us to penalties that could have a material effect on our business.”

The PUCT has original jurisdiction over transmission and distribution rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT and has exclusive appellate jurisdiction to review the rate and service orders and ordinances of municipalities. Generally, PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that does not have the prior approval of the appropriate regulatory authority (PUCT or municipality with original jurisdiction). In January 2011, we filed for a rate review with the PUCT and 203 cities based on a test year ended June 30, 2010 (PUCT Docket No. 38929). In August 2011, the PUCT issued a final order with respect to the rate review as discussed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulation and Rates.”

At the state level, PURA requires owners or operators of transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility’s own use of its system. The PUCT has adopted rules implementing the state open-access requirements for utilities including the company that are subject to the PUCT’s jurisdiction over transmission services.

Securitization Bonds—Our consolidated financial statements include our wholly-owned, bankruptcy-remote financing subsidiary, Bondco. This financing subsidiary was organized for the limited purpose of issuing certain transition bonds in 2003 and 2004. Bondco issued $1.3 billion principal amount of transition bonds to recover generation-related regulatory asset stranded costs and other qualified costs under an order issued by the PUCT in 2002. At December 31, 2012, $436 million principal amount of transition bonds (maturing between 2013 and 2016) was outstanding. See Note 11 to Financial Statements for discussion of the agreements between TCEH and us regarding payment of interest and incremental taxes related to these bonds that were settled in 2012.

Environmental Regulations and Related Considerations—The TCEQ and the EPA have jurisdiction over water discharges (including storm water) from facilities in Texas. We believe our facilities are presently in material compliance with applicable state and federal requirements relating to discharge of pollutants into the water. We believe we hold all required waste water discharge permits from the TCEQ for facilities in operation and have applied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirements necessary to obtain any required permits or renewals. There are also federal rules pertaining to Spill Prevention, Control and Countermeasure (SPCC) plans for oil-filled electrical equipment and bulk storage facilities for oil that affect certain of our facilities. We have implemented SPCC plans as required for those substations, work centers and distribution systems, and believe we are currently in compliance with these rules.

Treatment, storage and disposal of solid waste and hazardous waste are regulated at the state level under the Texas Solid Waste Disposal Act and at the federal level under the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act. The EPA has issued regulations under the Resource Conservation and Recovery Act of 1976 and the Toxic Substances Control Act, and the TCEQ has issued regulations under the Texas Solid Waste Disposal Act applicable to our facilities. We are in compliance with applicable solid and hazardous waste regulations.

Our capital expenditures for environmental matters totaled $54 million in 2012 and are expected to total approximately $43 million in 2013.

5

Item 1A. RISK FACTORS

Some important factors, in addition to others specifically addressed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” that could have a material negative impact on our operations, financial results and financial condition, or could cause our actual results or outcomes to differ materially from any projected outcome contained in any forward-looking statement in this report, include:

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

Our business operates in a changing market environment influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry. We will need to continually adapt to these changes.

Our business is subject to changes in state and federal laws (including PURA, the Federal Power Act, the Public Utility Regulatory Policies Act of 1978 and the Energy Policy Act of 2005), changing governmental policy and regulatory actions (including those of the PUCT, the NERC, the TRE, the TCEQ, the FERC and the EPA and the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, construction and operation of transmission facilities, acquisition, disposal, depreciation and amortization of regulated assets and facilities, recovery of costs and investments, return on invested capital and environmental matters. Changes in, revisions to, or reinterpretations of existing laws and regulations may have an adverse effect on our business and we could be exposed to increased costs to comply with the more stringent requirements or new interpretations and to potential liability for customer refunds, penalties or other amounts. If it is determined that we did not comply with applicable statutes, regulations, rules, tariffs or orders and we are ordered to pay a material amount in customer refunds, penalties or other amounts, our financial condition, results of operations and cash flow would be materially adversely affected.

For example, under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from cyber and physical security breaches. In addition, the PUCT may impose penalties on us if it finds that we violated any law, regulation, PUCT order or other rule or requirement. The PUCT has the authority to impose penalties of up to $25,000 per day, per violation.

The Texas Legislature meets every two years (the current Legislature is in regular session from January 2013 to May 2013). However, at any time the governor of Texas may convene a special session of the Legislature. During any regular or special session bills may be introduced that, if adopted, could materially and adversely affect our business and our business prospects.

The rates of our electricity delivery business are subject to regulatory review and may be reduced below current levels, which could adversely impact our financial condition and results of operations.

The rates we charge are regulated by the PUCT and certain cities and are subject to cost-of-service regulation and annual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Our rates are regulated based on an analysis of our costs and capital structure, as reviewed and approved in a regulatory proceeding. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCT will judge all of our costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure that our rates are based upon, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs, including regulatory assets reported in the balance sheet, and the return on invested capital allowed by the PUCT.

Attacks on our infrastructure or other events that disrupt or breach our cyber/data security measures could have an adverse impact on our reputation, disrupt business operations and expose us to significant liabilities including penalties for failure to comply with federal, state or local statutes and regulations, which could have a material effect on our results of operations, liquidity and financial condition.

A breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our transmission and distribution assets, access customer information and limit communication with third parties. Much of our information technology infrastructure is connected (directly or indirectly) to the Internet. Recently there have been numerous attacks on government and industry information technology systems through the Internet that have resulted in material operational, reputation and/or financial costs. While we have

6

controls in place designed to protect our infrastructure and have not had any significant breaches, any loss of confidential or proprietary data through a breach could adversely affect our reputation, expose us to material legal/regulatory claims, impair our ability to execute on business strategies and/or materially affect our results of operations, liquidity and financial condition.

As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its Critical Infrastructure Protection reliability standards and has established standards for assets that a utility has identified as “critical cyber assets.” Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from cyber and physical security breaches.

We participate in industry groups and discussions with regulators to remain current on emerging threats and mitigating techniques. These groups include, but are not limited to: the US Cyber Emergency Response Team, the National Electric Sector Cyber Security Organization, the Department of Homeland Security, the US Nuclear Regulatory Commission and NERC. We also apply the knowledge gained by continuing to invest in technology, processes and services to detect, mitigate and protect our cyber assets. These investments include upgrades to network architecture, regular intrusion detection monitoring and compliance with emerging industry regulation.

Our capital deployment program may not be executed as planned, which could adversely impact our financial condition and results of operations.

There can be no guarantee that the execution of our capital deployment program for our electricity delivery facilities will be successful, and there can be no assurance that the capital investments we intend to make in connection with our electricity delivery business will produce the desired reductions in cost and improvements to service and reliability. Furthermore, there can be no guarantee that our capital investments, including our investments associated with projects to construct CREZ-related transmission lines and facilities and additional voltage support projects will ultimately be recoverable through rates or, if recovered, that they will be recovered on a timely basis. For more information regarding the limitation on recovering the value of investments using rates and the CREZ project, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Key Risks and Challenges” and “– Regulation and Rates.” There can also be no assurance that the PUCT’s award of CREZ construction projects will not be modified or otherwise vacated through judicial or administrative actions, or that CREZ-related costs will not be materially increased as a result of administrative actions of the finalization of voltage support facilities and final detailed designs of subsequent project routes.

Market volatility may impact our business and financial condition in ways that we currently cannot predict.

Because our operations are capital intensive, we expect to rely over the long-term upon access to financial markets as a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or our revolving credit facility. With the construction of our CREZ-related transmission lines and facilities and our other planned projects, it is likely we will incur additional debt. In addition, we may incur additional debt in connection with other investments in infrastructure or technology, such as smart grid systems. Our ability to access the capital or credit markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost of debt financing may be materially and adversely impacted by these market conditions. Even if we are able to obtain debt financing, we may be unable to recover in rates some or all of the costs of such debt financing if they exceed our PUCT-approved cost of debt determined in our most recent rate review or subsequent rate reviews. Accordingly, there can be no assurance that the capital and credit markets will continue to be a reliable or acceptable source of short-term or long-term financing for us. Additionally, disruptions in the capital and credit markets could have a broader impact on the economy in general in ways that could lead to reduced electricity usage, which could have a negative impact on our revenues, or have an impact on our customers, counterparties and/or lenders, causing them to fail to meet their obligations to us.

Adverse actions with respect to our credit ratings could negatively affect our ability to access capital.

Our access to capital markets and our cost of debt are 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. Our credit ratings are currently substantially higher than those of EFH Corp., our majority equity investor. If credit rating agencies were to change their views of our independence of EFH Corp., our credit ratings would likely decline. Despite our ring-fencing measures, rating agencies have in the past, and could in the future take an adverse action with respect to our credit ratings in response to financing and liability management activities by EFH Corp. or its

7

subsidiaries including the issuance of debt by EFH Corp. and/or EFIH that is secured by a lien on the equity of Oncor Holdings held by EFIH. In the event any such adverse action takes place and causes our 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 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 would likely 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.

As a transmission operator, we are subject to mandatory reliability standards and periodic audits of our compliance with those standards. Efforts to comply with those standards could subject us to higher operating costs and/or increased capital expenditures, and non-compliance with applicable standards could subject us to penalties that could have a material effect on our business.

The FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by utilities within ERCOT. The FERC has designated the NERC to establish and enforce Reliability Standards, under FERC oversight, for all owners, operators and users of the bulk power system. The FERC has approved the delegation by NERC of compliance and enforcement authority for reliability in the ERCOT region to the TRE. To maintain compliance with the mandatory reliability standards, we may be subjected to higher operating costs and/or increased capital expenditures. While we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the PUCT will approve full recovery of such costs or the timing of any such recovery. In addition, if we were to be found to be in noncompliance with applicable reliability standards, we could be subject to sanctions, including monetary penalties. Under the Energy Policy Act of 2005, FERC can impose penalties (up to $1 million per day per violation) for failure to comply with reliability standards, which would not be recoverable from customers through regulated rates. We have five registrations with NERC – as a transmission planner, a transmission owner, a transmission operator, a distribution provider and a load serving entity. As a registered entity we are subject to periodic audits by the TRE of our compliance with reliability standards. These audits will occur as designated by the TRE at a minimum of every three years. The TRE has indicated that it intends to audit our compliance with mandatory planning and operations reliability standards in June 2013 and our compliance with critical infrastructure protection standards in August 2013. We cannot predict the outcome of any such audits.

Our revenues are concentrated in a small number of customers, including TCEH, and any delay or default in payment could adversely affect our cash flows, financial condition and results of operations.

Our revenues from the distribution of electricity are collected from more than 80 REPs, including TXU Energy (a subsidiary of TCEH), that sell the electricity we distribute to consumers. Revenues from TCEH represented 29% of our total operating revenues for the year ended December 31, 2012. Revenues from REP subsidiaries of a non-affiliated entity collectively represented 15% of our total operating revenues for the year ended December 31, 2012. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of TCEH or one or more other REPs could impair the ability of these REPs to pay for our services or could cause them to delay such payments. We depend on these REPs to timely remit these revenues to us. We could experience delays or defaults in payment from these REPs, which could adversely affect our cash flows, financial condition and results of operations. Due to commitments made to the PUCT in 2007, we may not recover bad debt expense, or certain other costs and expenses, from rate payers in the event of a default or bankruptcy by an affiliate REP.

In the future, we could have liquidity needs that could be difficult to satisfy under some circumstances, especially in uncertain financial market conditions.

Our operations are capital intensive. We rely on access to financial markets and our revolving credit facility as a significant source of liquidity for capital requirements, including maturities of long-term debt, not satisfied by cash-on-hand or operating cash flows. The inability to raise capital on favorable terms or access liquidity facilities, particularly during times of uncertainty similar to those experienced in the financial markets in 2008 and 2009, could adversely impact our ability to sustain and grow our business and would likely increase capital costs that may not be recoverable through rates. Our access to the financial markets and our revolving credit facility, and the pricing and terms we receive in the financial markets, could be adversely impacted by various factors, such as:

8

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

• economic weakness in the ERCOT market;

• changes in interest rates;

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

• a deterioration of the credit or bankruptcy of one or more lenders under our revolving credit facility that affects the ability of the lender(s) to make loans to us;

• a deterioration of the credit of EFH Corp. or EFH Corp.’s other subsidiaries or a reduction in the credit ratings of EFH Corp. or EFH Corp.’s other subsidiaries that is perceived to potentially have an adverse impact on us despite the ring-fencing of the Oncor Ring-Fenced Entities from the Texas Holdings Group;

• a material breakdown in our risk management procedures, and

• the occurrence of changes that restrict our ability to access our revolving credit facility.

Our primary source of liquidity aside from operating cash flows is our ability to borrow under our revolving credit facility. The revolving credit facility contains a debt-to-capital ratio covenant that effectively limits our ability to incur indebtedness in the future. At December 31, 2012, we were in compliance with such covenant. The revolving credit facility and the senior notes and debentures issued by us are secured by the Deed of Trust, which permits us to secure other indebtedness with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the lower of the fair value or cost of certain property additions that could be certified to the Deed of Trust collateral agent. At December 31, 2012, the available bond credits were approximately $2.2 billion. The amount of future debt we could secure with property additions, subject to those property additions being certified to the Deed of Trust collateral agent, was $731 million. In 2007, we 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 December 31, 2012, our regulatory capitalization ratio was 58.8% debt and 41.2% equity. Our ability to incur additional long-term debt will be limited by our regulatory capital structure.

The costs of providing pension and OPEB and related funding requirements may have a material adverse effect on our financial condition, results of operations and cash flows.

We offer certain pension and health care and life insurance (OPEB) benefits to eligible employees and their eligible dependents upon the retirement of such employees. Some of these benefits are provided through participation with EFH Corp. and certain other subsidiaries of EFH Corp. in joint plans.

In 2012, we also entered into an agreement with EFH Corp. to assume primary responsibility for pension benefits of certain participants for whom EFH Corp. bore primary funding responsibility (a closed group of retired and terminated vested plan participants not related to our regulated utility business). As the Oncor Retirement Plan received an amount of plan assets equal to the liabilities we assumed for those participants, execution of the agreement did not have a material impact on our reported results of operations or financial condition in 2012. However, there can be no guarantee that such assumption will not have an impact on our results of operations or financial condition in the future.

Our share of the costs of providing pension and OPEB benefits and related funding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in these factors, assumptions and estimates, including the market value of the assets funding the pension and the OPEB plans. Benefits costs and related funding requirements are also subject to changing employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in actual market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

If EFH Corp., which is highly leveraged, was unable to make contributions to the EFH Retirement Plan while it is a member of our controlled group within the meaning of ERISA, we could be liable under ERISA for such contributions as well as any unfunded pension plan liability that EFH Corp. is unable to pay. EFH Corp.’s portion of the EFH Retirement Plan’s unfunded pension liability is $20 million at December 31, 2012. Funding for the EFH Retirement Plan, based on the funded status at December 31, 2012, is expected to total approximately $6 million in 2013 and $109 million in the 2013 to 2017 period. We are expected to fund approximately $6 million in 2013 and $97 million in the 2013 to 2017 period of the total amount consistent with our share of this plan. Our share of funding for the EFH Retirement Plan represents obligations we assumed with respect to certain employees of EFH Corp.’s predecessor at the time of deregulation of the Texas electricity market. PURA allows for our recovery of those costs and, as a result, in 2005 we entered into an agreement with EFH Corp.’s predecessor to assume those costs.

9

See Note 9 to Financial Statements and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Condition – Pension and OPEB Plan Funding” for further information regarding pension and OPEB plans’ funding.

Our ring-fencing measures may not work as planned and a bankruptcy court may nevertheless subject Oncor to the claims of its affiliates’ creditors.

As discussed above, to enhance the separateness between the Oncor Ring-Fenced Entities and the Texas Holdings Group and our credit quality, various legal, financial and contractual provisions were implemented. These enhancements are intended to minimize the risk that a court would order any of the Oncor Ring-Fenced Entities’ assets and liabilities to be substantively consolidated with those of any member of the Texas Holdings Group in the event that a member of the Texas Holdings Group were to become a debtor in a bankruptcy case. Substantive consolidation is an equitable remedy in bankruptcy that results in the pooling of the assets and liabilities of the debtor and one or more of its affiliates solely for purposes of the bankruptcy case, including for purposes of distributions to creditors and voting on and treatment under a reorganization plan. Bankruptcy courts have broad equitable powers, and as a result, outcomes in bankruptcy proceedings are inherently difficult to predict. To the extent a bankruptcy court were to determine that substantive consolidation is appropriate under the facts and circumstances, then the assets and liabilities of any Oncor Ring-Fenced Entity that is subject to the substantive consolidation order would be available to help satisfy the debt or contractual obligations of the Texas Holdings Group entity that is a debtor in bankruptcy and subject to the same substantive consolidation order. If any Oncor Ring-Fenced Entity were included in such a substantive consolidation order, the secured creditors of Oncor would retain their liens and priority with respect to Oncor’s assets.

If any member of the Texas Holdings Group were to become a debtor in a bankruptcy case, there can be no assurance that a court would not order an Oncor Ring-Fenced Entity’s assets and liabilities to be substantively consolidated with those of such member of the Texas Holdings Group or that a proceeding would not result in a disruption of services we receive from, or jointly with, our affiliates. See Note 1 to Financial Statements for additional information on our ring fencing measures.

Goodwill that we have recorded is subject to at least annual impairment evaluations, and as a result, we could be required to write off some or all of this goodwill, which may cause adverse impacts on our financial condition and results of operations.

In accordance with accounting standards, recorded goodwill is not amortized but is reviewed annually or more frequently for impairment, if certain conditions exist, and may be impaired. Any reduction in or impairment of the value of goodwill will result in a charge against earnings, which could cause a material adverse impact on our reported results of operations and financial condition. See Note 1 to Financial Statements for goodwill impairment assessment and testing.

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

We derive substantially all of our revenues from operations in the ERCOT market, which covers approximately 75% of the geographical area in the State of Texas. As a result, regardless of the state of the economy in areas outside the ERCOT market, economic weakness in the ERCOT market could lead to reduced demand for electricity in the ERCOT market. Such a reduction could have a material negative impact on our results of operations and financial condition.

The PUCT and ERCOT are subject to regular “sunset” reviews by the Texas Sunset Advisory Commission. The PUCT is currently subject to a limited purpose sunset review. If either the PUCT or ERCOT is not renewed by the Texas Legislature pursuant to Sunset review, it could have a material effect on our business.

Sunset review is the regular assessment of the continuing need for an administrative agency to exist, and is grounded in the premise that an agency will be abolished unless legislation is passed to continue its functions. The Texas Sunset Advisory Commission (Sunset Commission) closely reviews each agency and recommends action on each agency to the Texas Legislature, which action may include modifying or even abolishing the agency. Of the agencies scheduled for Sunset review by the Sunset Commission, the PUCT and ERCOT are the most significant to our business. The PUCT is scheduled for a limited purpose sunset review in 2013 (with its next review in 2023) and ERCOT is scheduled for review after 2013. These agencies are also subject to focused, limited scope, or special purpose reviews. These agencies, for the most part,

10

participate in, govern or operate the electricity markets in Texas upon which our business model is based. If the Texas Legislature fails to renew any of these agencies, it could result in a significant restructuring of the Texas electricity market or regulatory regime that could have a material impact on our business. There can be no assurance that future action of the Sunset Commission will not result in legislation that could have a material adverse effect on us and our financial prospects.

Disruptions at power generation facilities owned by third parties could interrupt our sales of transmission and distribution services.

The electricity we transmit and distribute to customers of REPs is obtained by the REPs from electricity generation facilities. We do not own or operate any generation facilities. If generation is disrupted or if generation capacity is inadequate, our sales of transmission and distribution services may be diminished or interrupted, and our results of operations, financial condition and cash flows may be adversely affected.

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

The operation and maintenance of delivery facilities involves many risks, including equipment breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of efficiency or reliability, the occurrence of any of which could result in lost revenues and/or increased expenses that may not be recoverable through rates. A significant number of our facilities were constructed many years ago. In particular, older transmission and distribution equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from damage to facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events. Further, our ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs that may not be recoverable through rates and/or the write-off of our investment in the project or improvement.

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

Changes in technology or increased conservation efforts may reduce the value of our electricity delivery facilities and may significantly impact our business in other ways as well.

Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines, photovoltaic (solar) cells and concentrated solar thermal devices. It is possible that advances in these or other technologies will reduce the costs of electricity production from these technologies to a level that will enable these technologies to compete effectively with traditional generation plants. Changes in technology could also alter the channels through which retail customers buy electricity. To the extent self-generation facilities become a more cost-effective option for certain customers, our revenues could be materially reduced.

Also, electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewise significantly reduce the value of our electricity delivery facilities. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Effective energy conservation by our customers could result in reduced energy demand, or significantly slow the growth in demand. Such reduction in demand could materially reduce our revenues. Furthermore, we may incur increased capital expenditures if we are required to invest in conservation measures.

We are dependent upon a limited number of suppliers and service providers for certain of our operations. If any of these suppliers or service providers failed or became unable to perform on their agreements with us, it could disrupt our business and have an adverse effect on our cash flows, financial condition and results of operations.

We rely on suppliers and service providers to provide us with certain specialized materials and services, including materials and services for power line maintenance, repair and construction, our advanced metering system (AMS), information technology and customer operations. The financial condition of our suppliers and service providers may be adversely affected by general economic conditions, such as credit risk and the turbulent macroeconomic environment in recent years. Because many of the tasks of these suppliers and service providers require specialized electric industry

11

knowledge and equipment, if any of these parties fail to perform, go out of business or otherwise become unable to perform, we may not be able to transition to substitute suppliers or service providers in a timely manner. This could delay our construction and improvement projects, increase our costs and disrupt our operations, which could negatively impact our business and reputation. In addition, we could be subject to fines or penalties in the event a delay resulted in a violation of a PUCT or other regulatory order.

Our revenues and results of operations are seasonal.

A significant portion of our revenues is derived from rates that we collect from REPs based on the amount of electricity we distribute on behalf of such REPs. Sales of electricity to residential and commercial customers are influenced by temperature fluctuations. Thus, our revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.

The litigation environment in which we operate poses a significant risk to our business.

We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial and environmental issues and other claims for injuries and damages, among other matters. Judges and juries in the State of Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage and business tort cases. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment in the State of Texas poses a significant business risk.

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

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

12

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 3. LEGAL PROCEEDINGS

Remand of 1999 Wholesale Transmission Matrix Case (PUCT Docket No. 38780)

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

The first issue was the wholesale transmission transition mechanism for the period of September 1999 through December 1999. The disputed issue was whether the PUCT should have allowed the transition mechanism to continue for the last four months of 1999. The appealing parties (Texas Municipal Power Agency, the City of Denton, the City of Garland and GEUS (formerly known as Greenville Electric Utility System)) argued that the transition mechanism was not authorized in the September 1, 1999 100% postage stamp pricing legislation. Our transmission deficit position was mitigated by approximately $8 million in the last four months of 1999 through the transition mechanism. In October 2011, certain parties filed a proposed settlement of this issue, subject to PUCT approval, in which we would pay approximately $9 million including interest through October 9, 2003. The PUCT approved the settlement in January 2012, and the PUCT order became final in February 2012. We made the payment in accordance with the settlement in February 2012. In November 2012, the PUCT gave its final approval of the TCRF application allowing us recovery of the $9 million through TCRF billings during the period September 2012 through February 2013.

The second issue was the San Antonio City Public Service Board’s (CPSB) claim that the PUCT did not have the authority to reduce CPSB’s requested TCOS revenue requirement. CPSB’s initial TCOS rate was in effect from 1997 through 2000. Since the period of January 1997 through August 1999 is incorporated in the joint settlement, CPSB’s remaining claim is for the period of September 1999 through December 2000. In January 2011, CPSB made a filing with the PUCT (PUCT Docket No. 39068), seeking an additional $22 million of TCOS revenue, including interest, for the 16-month period, of which we would be responsible for approximately $11 million. In late 2011, we intervened in the proceeding and, along with several other parties, filed motions to dismiss CPSB’s request. In January 2012, the PUCT upheld an administrative law judge’s earlier decision to dismiss CPSB’s request, and the PUCT order became final in February 2012.

We are involved in other 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 on our financial position, results of operations or cash flows. See Note 7 to Financial Statements for additional information concerning our legal and regulatory proceedings.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

13

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED EQUITY HOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

At December 31, 2012, 80.03% of our outstanding membership interests was held by Oncor Holdings and indirectly held by EFH Corp., 19.75% was held by Texas Transmission and 0.22% was indirectly held by certain members of our management team and board of directors through Investment LLC. None of the membership interests are publicly traded, and none were issued in 2012.

See Note 8 to Financial Statements for a description of cash distributions we paid to our members and the restrictions on our ability to pay such distributions.

Item 6. SELECTED FINANCIAL DATA

	At December 31,
	2012			2011			2010			2009			2008
	(millions of dollars, except ratios)
Total assets – end of year	$	17,990		$	17,371		$	16,846		$	16,232		$	15,706
Property, plant & equipment – net – end of year		11,318			10,569			9,676			9,174			8,606
Goodwill		4,064			4,064			4,064			4,064			4,064
Capitalization – end of year
Long-term debt, less amounts due currently	$	5,400		$	5,144		$	5,333		$	4,996		$	5,101
Membership interests		7,304			7,181			6,988			6,847			6,799
Total	$	12,704		$	12,325		$	12,321		$	11,843		$	11,900
Capitalization ratios – end of year (a)
Long-term debt, less amounts due currently		42.5	%		41.7	%		43.3	%		42.2	%		42.9	%
Membership interests		57.5			58.3			56.7			57.8			57.1
Total		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%

(a) For purposes of reporting to the PUCT, the regulatory capitalization ratio at December 31, 2012 was 58.8% debt and 41.2% equity. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Available Liquidity/Credit Facility” and Note 8 to Financial Statements for additional information regarding regulatory capitalization ratios.

	Year Ended December 31,
	2012			2011			2010			2009			2008
	(millions of dollars, except ratios)
Operating revenues	$	3,328		$	3,118		$	2,914		$	2,690		$	2,580
Net income (loss) (a)	$	349		$	367		$	352		$	320		$	(487	)
Capital expenditures	$	1,389		$	1,362		$	1,020		$	998		$	919
Ratio of earnings to fixed charges (b)		2.49			2.62			2.60			2.40			—
Embedded interest cost on long-term debt – end of period (c)		7.0	%		6.6	%		6.5	%		6.6	%		6.7	%

(a) Amount in 2008 includes an $860 million goodwill impairment charge.

(b) Fixed charges exceeded earnings by $266 million for the year ended December 31, 2008.

(c) Represents the annual interest and amortization of any discounts, premiums, issuance costs (including the effects of interest rate hedges) and any deferred gains/losses on reacquisitions divided by the carrying value of the debt plus or minus the unamortized balance of any discounts, premiums, issuance costs (including the effects of interest rate hedges) and gains/losses on reacquisitions at the end of the year.

14

Item 7. 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 fiscal years ended December 31, 2012, 2011 and 2010 should be read in conjunction with Selected Financial Data and our audited consolidated financial statements and the notes to those statements.

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

BUSINESS

We are a regulated electricity transmission and distribution company principally engaged in providing delivery services to REPs, including subsidiaries of TCEH, that sell power in the north-central, eastern and western parts of Texas. Revenues from TCEH represented 29%, 33% and 36% of our total operating revenues for the years ended December 31, 2012, 2011 and 2010, respectively. We are a majority-owned subsidiary of Oncor Holdings, which is a direct, wholly-owned subsidiary of EFIH, a direct, wholly-owned subsidiary of EFH Corp. Oncor Holdings owns 80.03% of our outstanding membership interests, Texas Transmission owns 19.75% of our outstanding membership interests and certain members of our management team and board of directors indirectly own the remaining outstanding membership interests through Investment LLC. We are managed as an integrated business; consequently, there are no separate reportable business segments.

Various “ring-fencing” measures have been taken to enhance the separateness between the Oncor Ring-Fenced Entities and the Texas Holdings Group and our credit quality. These measures serve to mitigate our and Oncor Holdings’ credit exposure to the Texas Holdings Group and to reduce the risk that our assets and liabilities or those of Oncor Holdings would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities. Such measures include, among other things: our sale of a 19.75% equity interest to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; our board of directors being comprised of a majority of independent directors; and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, including TXU Energy and Luminant, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or contractual obligations of any member of the Texas Holdings Group. We do not bear any liability for debt or contractual obligations of the Texas Holdings Group, and vice versa. Accordingly, our operations are conducted, and our cash flows are managed, independently from the Texas Holdings Group.

Significant Activities and Events

Pension Plan Changes— We participate in the EFH Retirement Plan, which offers pension benefits based on either a traditional defined benefit formula or a cash balance formula. In 2012, EFH Corp. made various changes to the EFH Retirement Plan, including splitting off into a new plan all of the assets and liabilities associated with Oncor employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Effective January 1, 2013, we assumed sole sponsorship of this new plan, referred to herein as the Oncor Retirement Plan. In connection with assuming the sponsorship of the Oncor Retirement Plan, we entered into an agreement with EFH Corp. to assume primary responsibility for benefits of certain participants for whom EFH Corp. bore primary funding responsibility (a closed group of retired and terminated vested plan participants not related to our regulated utility business) as of December 31, 2012. As the Oncor Retirement Plan received an amount of plan assets equal to the liabilities we assumed for those participants, execution of the agreement did not have a material impact on our reported results of operations or financial condition. In addition EFH Corp. made cash contributions totaling $259 million in the fourth quarter of 2012 to settle all obligations relating to a terminating plan created for active nonunion employees of EFH Corp.’s competitive businesses. See Note 9 to Financial Statements for additional information related to the pension plan changes.

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

15

In August 2012, we sold both agreements to EFIH for an aggregate amount of $159 million. At the time of sale, the remaining principal balance on the note was $159 million, and the remaining interest reimbursements to be received through 2016 totaled $51 million. As a result of the sale of the agreements to EFIH, future interest income is expected to be $6 million, $20 million and $20 million less than it otherwise would have been in the fourth quarter of 2012, the year 2013 and the period 2014 to 2016, respectively. In accordance with accounting rules for related-party matters, we reported the transaction as a decrease in total membership interests totaling $2 million (after tax) for the year ended December 31, 2012. See Note 11 to Financial Statements for additional information related to the sale to EFIH of our interest and tax reimbursement agreements with TCEH.

Technology Initiatives— We continue to invest in technology initiatives that include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is producing electricity service reliability improvements and providing the potential for additional products and services from REPs that enable businesses and consumers to better manage their electricity usage and costs. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits. With the new meters integrated, we report 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options.

At December 31, 2012, we had installed 3,263,000 advanced digital meters (including 961,000 during 2012) completing our planned deployment of advanced meters to all residential and most non-residential retail electricity customers in our service area. Cumulative capital expenditures for the deployment of the advanced meter system totaled $660 million through December 31, 2012, including $142 million in 2012.

As discussed below under “Regulation and Rates,” we implemented a rate surcharge effective January 1, 2009 to recover our investment in the advanced meter deployment.

Revolving Credit Facility and Debt-Related Activities— See Notes 5 and 6 to Financial Statements for information regarding a $400 million increase in commitments under our revolving credit facility in May 2012, issuances of $900 million principal amount of senior secured notes in May 2012 and early redemption of $524 million principal amount of senior secured notes in June 2012.

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

KEY RISKS AND CHALLENGES

Following is a discussion of key risks and challenges facing management and the initiatives currently underway to manage such challenges.

Rates and Cost Recovery

Our rates are regulated by the PUCT and certain cities and are subject to regulatory rate-setting processes and annual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Our rates are regulated based on an analysis of our costs and capital structure, as reviewed and approved in a regulatory proceeding. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there is no assurance that the PUCT will judge all of our costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure that our rates are based upon, that the regulatory process in which rates are determined will always result in rates that produce full recovery of our costs or that our authorized return on equity will not be reduced. See “Regulation and Rates” below for further information.

16

Advanced Meter Deployment

Under a PUCT order approving our proposed advanced meter deployment plan and rate surcharge to recover the investment, we began billing the advanced metering surcharge in the January 2009 billing month cycle. In July 2011, we filed an application with the PUCT for reconciliation of all costs and investments incurred through December 31, 2010, in the deployment of our AMS. In November 2011, the PUCT issued its final order in the proceeding approving the stipulation and finding that costs expended and investments made in the deployment of our AMS through December 31, 2010 were properly allocated, reasonable and necessary. We may, through subsequent reconciliation proceedings, request recovery of additional costs that are reasonable and necessary. While there is a presumption that costs spent in accordance with a plan approved by the PUCT are reasonable and necessary, recovery of any costs that are found not to have been spent or properly allocated, or not to be reasonable or necessary, must be refunded. See “Regulation and Rates” below for further information.

Capital Availability and Cost

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. Our credit ratings are currently substantially higher than those of the Texas Holdings Group. If credit rating agencies were to change their views of our independence from any member of the Texas Holdings Group, our credit ratings would likely decline. We believe this risk is substantially mitigated by the ring-fencing measures as described in Note 1 to Financial Statements.

Technology Initiatives

Risks to our technology initiative programs discussed above under “Significant Activities and Events” include nonperformance by equipment and service providers, failure of the technology to meet performance expectations and inadequate cost recovery allowances by regulatory authorities. We are implementing measures to mitigate these risks, but there can be no assurance that these technology initiatives will achieve the operational and financial objectives.

APPLICATION OF CRITICAL ACCOUNTING POLICIES

Our significant accounting policies are discussed in Note 1 to Financial Statements. We follow accounting principles generally accepted in the US. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

Revenue Recognition

Revenue includes an estimate for electricity delivery services provided from the meter reading date to the end of the period (unbilled revenue). Unbilled revenue is based on actual daily revenues for the most recent period, adjusted for the impact of weather and other measurable factors that affect consumption, applied to the number of unmetered days through the end of the period. Accrued unbilled revenues totaled $147 million, $127 million and $126 million at December 31, 2012, 2011 and 2010, respectively.

Accounting for the Effects of Income Taxes

Our tax sharing agreement with Oncor Holdings and EFH Corp. was amended in November 2008 to include Texas Transmission and Investment LLC. The tax sharing agreement provides for the calculation of amounts related to income taxes for each of Oncor Holdings and Oncor substantially as if these entities file their own income tax returns and requires payments to the members determined on that basis (without duplication for any income taxes paid by a subsidiary of Oncor Holdings).

17

We became a partnership for US federal income tax purposes effective with the equity sale to Texas Transmission and Investment LLC in November 2008. Accordingly, while partnerships are not subject to income taxes, in consideration of the tax sharing agreement and the presentation of our financial statements as an entity subject to cost-based regulatory rate-setting processes, with such costs historically including income taxes, the financial statements present amounts determined under the tax sharing agreement as “provision in lieu of income taxes” and “liability in lieu of deferred income taxes” for periods subsequent to the equity sale. Such amounts are determined in accordance with the provisions of the accounting guidance for income taxes and accounting standards that provide interpretive guidance for accounting for uncertain tax positions and thus differences between the book and tax bases of assets and liabilities are accounted for as if we were a stand-alone corporation. The accounting guidance for rate-regulated enterprises requires the recognition of regulatory assets or liabilities if it is probable such deferred tax amounts will be recovered from, or returned to customers in future rates.

Our expense amounts related to income taxes and related balance sheet amounts are recorded pursuant to our tax sharing agreement as discussed above. Recording of such amounts involves significant management estimates and judgments, including judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of assets related to income taxes, management considers estimates of the amount and character of future taxable income. Actual amounts related to income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. EFH Corp.’s income tax returns are regularly subject to examination by applicable tax authorities. In management’s opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future amounts that may be owed as a result of any examination.

See Notes 1 and 3 to Financial Statements.

Depreciation

Depreciation expense for the transmission and distribution utility assets subject to regulated rate recovery is based on rates periodically approved by the PUCT. Amounts totaled $614 million, $565 million and $523 million in 2012, 2011 and 2010, respectively, or 4.0% of the carrying value in each of the years 2012, 2011 and 2010.

Regulatory Assets

Our financial statements at December 31, 2012 and 2011 reflect total regulatory assets of $2.093 billion and $2.007 billion, respectively. These amounts include $409 million and $531 million, respectively, of generation-related regulatory assets recoverable by transition bonds as discussed immediately below. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 4 to Financial Statements for more information regarding regulatory assets and liabilities.

Generation-related regulatory asset stranded costs arising prior to the Texas Electric Choice Plan (the 1999 legislation that restructured the electric utility industry in Texas to provide for retail competition) became subject to recovery through issuance of $1.3 billion principal amount of transition bonds in accordance with a regulatory financing order. The carrying value of the regulatory asset upon final issuance of the bonds in 2004 represented the projected future cash flows to be recovered from REPs by us through revenues as a transition charge to service the principal and fixed rate interest on the bonds. The regulatory asset is being amortized to expense in an amount equal to the transition charge revenues being recognized.

Other regulatory assets that we believe are probable of recovery, but are subject to review and possible disallowance, totaled $315 million and $146 million at December 31, 2012 and 2011, respectively. These amounts consist primarily of storm-related service recovery costs and employee retirement costs.

Impairment of Long-Lived Assets and Goodwill

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

We also evaluate goodwill for impairment annually (at December 1) and whenever events or changes in circumstances indicate that an impairment may exist. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows.

18

Under the quantitative goodwill impairment analysis, if at the assessment date our carrying value exceeds our estimated fair value (enterprise value), then the estimated enterprise value is compared to the estimated fair values of our operating assets (including identifiable intangible assets) and liabilities at the assessment date. The resultant implied goodwill amount is compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.

Effective with the December 1, 2011 test, we adopted new accounting guidance that provides the option of using a qualitative assessment in which we may consider macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and other relevant events.

Testing performed in December 2012 and 2010 was based on the quantitative method and determined that our estimated fair value was substantially in excess of the net carrying value of our operating assets and liabilities, resulting in no additional testing. In December 2011, we concluded, based on the results of a qualitative assessment, that our estimated enterprise fair value was more likely than not greater than our net carrying value. As a result, no further testing for impairment was required. Accordingly, there were no impairments of goodwill in the years ended December 31, 2012, 2011 or 2010.

Defined Benefit Pension Plans and OPEB Plans

We offer certain pension, health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. Some of these benefits are provided through participation with EFH Corp. and certain other subsidiaries of EFH Corp. in joint plans. Reported costs of providing noncontributory pension and OPEB benefits are dependent upon numerous factors, assumptions and estimates.

PURA provides for our recovery of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility. These costs are associated with our active and retired employees as well as active and retired personnel engaged in other EFH Corp. activities related to service prior to the deregulation and disaggregation of EFH Corp.’s businesses effective January 1, 2002 (recoverable service). Accordingly, we entered into an agreement with EFH Corp. whereby we assumed responsibility in 2005 for applicable pension and OPEB costs related to those personnel’s recoverable service.

We are authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs reflected in our PUCT-approved billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings related to recoverable service. Accordingly, we defer (principally as a regulatory asset or property) additional pension and OPEB costs consistent with PURA. Amounts deferred are ultimately subject to regulatory approval. Any retirement costs not associated with recoverable service are recognized in comprehensive income.

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

In accordance with accounting rules, changes in benefit obligations associated with factors discussed above may be immediately recognized in other comprehensive income and reclassified as a current cost in future years. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. Net direct and indirect allocated pension and OPEB costs as determined under applicable accounting rules are summarized in the following table:

19

	Year Ended December 31,
	2012			2011			2010
Pension costs	$	179		$	95		$	67
OPEB costs		27			74			63
Total benefit costs		206			169			130
Less amounts deferred as a regulatory asset or property		(169	)		(132	)		(93	)
Net amounts recognized as expense	$	37		$	37		$	37
Discount rate (percentage) (a)(b)		5.00	%		5.50	%		5.90	%
Funding of the pension plans and the OPEB Plan (c)	$	104		$	193		$	61

(a) As a result of the amendments to the EFH Retirement Plan discussed in Note 9 to Financial Statements, the discount rate reflected in net pension costs for January through July 2012 was 5.00%, for August through September 2012 was 4.15% and for October through December 31, 2012 was 4.20%.

(b) Discount rate for OPEB was 4.95%, 5.55% and 5.90% in 2012, 2011 and 2010, respectively.

(c) 2012 amount excludes transfers of investments between benefit plans in 2012. See Note 9 to Financial Statements for additional information regarding pension and OPEB plans.

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

Assumption	Increase/ (decrease) in 2013 Pension and OPEB Costs
Discount rate – 1% increase	$	(28	)
Discount rate – 1% decrease	$	27
Expected return on assets – 1% increase	$	(22	)
Expected return on assets – 1% decrease	$	22

See Note 9 to Financial Statements regarding other disclosures related to pension and OPEB obligations.

20

RESULTS OF OPERATIONS

Operating Data

	Year Ended December 31,
	2012		2011		2010
Operating statistics:
Electric energy billed volumes (gigawatt-hours):
Residential		40,377		43,888		41,823
Other (a)		69,994		69,949		67,500
Total electric energy billed volumes		110,371		113,837		109,323
Reliability statistics (b):
System Average Interruption Duration Index (SAIDI) (nonstorm)		89.9		106.2		96.6
System Average Interruption Frequency Index (SAIFI) (nonstorm)		1.2		1.3		1.2
Customer Average Interruption Duration Index (CAIDI) (nonstorm)		77.6		83.1		82.3
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of active meters)		3,242		3,203		3,171
Operating revenues (c):
Distribution base rates	$	1,789	$	1,993	$	2,185
Reconcilable rates (d)		926		594		235
Advanced metering surcharges		142		103		75
Third-party transmission revenues		398		351		327
Other miscellaneous revenues (e)		73		77		92
Total operating revenues	$	3,328	$	3,118	$	2,914

(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.

(c) Operating revenues for the years ended December 31, 2011 and 2010 have been reclassified to conform to the current period presentation. 2011 revenues reflect a $29 million reclassification of TCRF unbilled revenues from distribution revenues to reconcilable rates and an $8 million reclassification of energy efficiency performance bonus from reconcilable revenues to other miscellaneous revenues; 2010 revenues reflect a $2 million reclassification of TCRF unbilled revenues from distribution revenues to reconcilable rates and an $11 million reclassification of energy efficiency performance bonus from reconcilable revenues to other miscellaneous revenues.

(d) Includes TCRF revenues and energy efficiency surcharges. Also includes transition charge revenue totaling $144 million, $151 million and $153 million for the years ended December 31, 2012, 2011 and 2010, respectively, associated with the issuance of transition bonds.

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

Effective July 1, 2011, pursuant to the PUCT’s order (see Note 2 to Financial Statements), we no longer recover the cost of wholesale transmission service expense through distribution base rates, but rather through reconcilable TCRF rates. Now, TCRF revenue is recognized as wholesale transmission expense is incurred, thereby removing the impact of seasonal and extreme weather and other factors affecting consumption on revenue and pretax income. Under the current rate structure, revenue recognition for recovery of wholesale transmission expense is expected to be less in the high volume periods, such as the third quarter, and greater in low volume periods than it otherwise would have been under the previous rate structure. For the years ended December 31, 2012 and 2011, we recognized $60 million more and $20 million less, respectively, in TCRF revenues than otherwise would have been recognized under the previous rate structure. The timing of billings to REPs has not changed and cash flows are not affected by the rate structure change. See Note 1 to Financial Statements for accounting treatment of reconcilable tariffs.

21

Financial Results — Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Total operating revenues increased $210 million, or 7%, to $3.328 billion in 2012. The increase reflected:

• a $332 million increase in reconcilable rate revenues (those in which recognized revenues equal incurred expenses) consisting of a $223 million impact from the rate structure change described above (with a corresponding amount recognized in base rate revenues below), a $109 million increase in TCRF revenues driven by an increase in wholesale transmission expense ($63 million of which was from third parties) and a $6 million increase in energy efficiency surcharges (offset in operation and maintenance expense), partially offset by a $6 million decrease in charges related to transition bonds (with an offsetting decrease in amortization expense);

• $47 million in higher transmission revenues reflecting rate increases to recover ongoing investment in the transmission system, and

• a $39 million increase in recognized revenues from the advanced metering deployment surcharge due to increased costs driven by ongoing meter installation and systems development;

partially offset by:

• a $204 million decrease in distribution base rate revenues consisting of a $223 million impact from reclassifying all TCRF revenues as reconcilable revenues resulting from the rate structure change described above (with a corresponding amount recognized in reconcilable rate revenues above) and a $78 million impact of lower average consumption, primarily due to the effects of milder weather in 2012 as compared to 2011, partially offset by $77 million in higher distribution tariffs (see Note 2 to Financial Statements) and an estimated $20 million effect of growth in points of delivery, and

• a $4 million decrease in other miscellaneous revenues, primarily due to lower REP discretionary services as a result of the continuing deployment of advanced meters, which we expect will continue to decrease in the future, and other revenues.

Wholesale transmission service expense increased $63 million, or 14%, to $502 million, due to higher fees paid to other transmission entities and a 2% increase in volumes.

Operation and maintenance expense increased $11 million, or 2%, to $669 million in 2012. The increase included $12 million in higher amortization of regulatory assets and $6 million in higher outside services costs, partially offset by a $14 million effect of unusual non-cash expenses in 2011 (primarily consisting of a $9 million write off of excessive inventory and a $5 million decrease related to SARs). Operation and maintenance expense also reflects fluctuations in other expenses that are offset by corresponding revenues, including a $6 million increase in costs related to programs designed to improve customer electricity demand efficiencies and a $2 million increase in costs related to advanced meters. Amortization of regulatory assets reported in operation and maintenance expense totaled $54 million and $42 million in 2012 and 2011, respectively.

Depreciation and amortization increased $52 million, or 7%, to $771 million in 2012. The increase reflected $58 million attributed to ongoing investments in property, plant and equipment (including $26 million related to advanced meters), partially offset by $6 million in lower amortization of regulatory assets associated with transition bonds (with an offsetting decrease in revenues).

Taxes other than amounts related to income taxes increased $15 million, or 4%, to $415 million in 2012. The change was the result of a $9 million increase in property taxes and a $6 million increase in local franchise fees.

Other income totaled $26 million in 2012 and $30 million in 2011. The 2012 and 2011 amounts included accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting totaling $23 million and $29 million, respectively. See Note 12 to Financial Statements.

22

Other deductions totaled $64 million in 2012 and $9 million in 2011. The increase was the result of a SARs settlement totaling $57 million, partially offset by a $2 million decrease in professional fees and other expenses. See Notes 10 and 12 to Financial Statements.

Provision in lieu of income taxes totaled a net $234 million in 2012 (including $240 million related to operating income and a benefit of $6 million related to nonoperating income) compared to $229 million in 2011 (including $209 million related to operating income and $20 million related to nonoperating income). The effective income tax rate on pretax income was 40.1% in 2012 and differs from the US federal statutory rate of 35% primarily due to non-deductible amortization of the regulatory asset resulting from a change in deductibility of Medicare Part D subsidy as a result of the Patient Protection and Affordable Care Act of 2010 and the effect of the 2012 Texas gross margin tax. See Note 3 to Financial Statements for reconciliation of the effective rate to the US federal statutory rate.

Interest income decreased $8 million, or 25%, to $24 million in 2012. The decrease reflected lower reimbursement of transition bond interest from TCEH due to lower remaining principal amounts and our sale of the TCEH interest agreement to EFIH in August 2012, partially offset by a $6 million increase in interest income related to a sales tax refund. See Note 11 to Financial Statements for discussion of the sale of the interest agreement.

Interest expense and related charges increased $15 million, or 4%, to $374 million in 2012. The change was driven by a $22 million increase attributable to higher average borrowings reflecting ongoing capital investments and $15 million in higher amortization of debt issuance costs and discounts, partially offset by a $14 million decrease attributable to lower average interest rates and a $8 million decrease attributable to higher capitalized interest.

Net income decreased $18 million, or 5%, to $349 million in 2012. The change reflected the effects on revenue of milder weather, the effect of the SARs settlement and increases in depreciation and interest expense, partially offset by increased revenue from higher transmission and distribution rates and growth in points of delivery.

Financial Results – Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Total operating revenues increased $204 million, or 7%, to $3.118 billion in 2011. The increase reflected:

• a $359 million increase in reconcilable rate revenues (those in which recognized revenues equal incurred expenses) consisting of a $309 million impact from the rate structure change described above (with a corresponding amount recognized in base rate revenues below), a $56 million increase in TCRF revenues driven by an increase in wholesale transmission expense ($46 million of which was from third parties), partially offset by a $4 million decrease in energy efficiency surcharges (offset in operation and maintenance expense) and a $2 million decrease in charges related to transition bonds (with an offsetting decrease in amortization expense);

• a $28 million increase in recognized revenues from the advanced metering deployment surcharge due to increased costs driven by ongoing meter installation and systems development, and

• $24 million in higher transmission revenues reflecting rate increases to recover ongoing investment in the transmission system;

partially offset by:

• a $192 million decrease in distribution base rate revenues consisting of a $309 million impact from reclassifying all TCRF revenues as reconcilable revenues resulting from the rate structure change described above (with a corresponding amount recognized in reconcilable rate revenues above), partially offset by $52 million in higher distribution tariffs (see Note 2 to Financial Statements), an estimated $47 million impact of higher average consumption, primarily due to the effects of significantly warmer summer weather in 2011 as compared to 2010 and an estimated $18 million effect of growth in points of delivery, and

• a $15 million decrease in other miscellaneous revenues, primarily due to REP discretionary services as a result of the continuing deployment of advanced meters and other revenues.

23

Wholesale transmission service expense increased $46 million, or 12%, to $439 million, due to higher fees paid to other transmission entities and a 2% increase in volumes.

Operation and maintenance expense increased $42 million, or 7%, to $658 million in 2011. The increase included $17 million of unusual non-cash expenses consisting of a $9 million write off of excessive inventory, a $5 million SARs accrual and a $3 million write off of deferred costs resulting from amending the revolving credit facility. The increase also included $8 million in higher vegetation management expenses, $4 million in higher transportation costs primarily due to increases in fuel and lease expense, $4 million in higher support services, a $3 million increase in labor costs associated with restoration activities in response to extreme weather conditions (including wild fires) in 2011, $3 million in higher professional services expense, $2 million in higher costs to implement a PUCT rule designed to reduce theft of electricity and $2 million in higher insurance and damage claims. Operation and maintenance expense also reflects fluctuations in other expenses that are offset by corresponding revenues, including a $4 million decrease in costs related to programs designed to improve customer electricity demand efficiencies, partially offset by $2 million in higher costs related to advanced meters. Amortization of regulatory assets reported in operation and maintenance expense totaled $42 million and $41 million in 2011 and 2010, respectively.

Depreciation and amortization increased $46 million, or 7%, to $719 million in 2011. The increase reflected $48 million attributed to ongoing investments in property, plant and equipment (including $22 million related to advanced meters), partially offset by $2 million in lower amortization of regulatory assets associated with transition bonds (with an offsetting increase in revenues).

Taxes other than amounts related to income taxes increased $16 million, or 4%, to $400 million in 2011. The increase was the result of a $13 million increase in local franchise fees and a $3 million increase in property taxes.

Other income totaled $30 million in 2011 and $36 million in 2010. The 2011 and 2010 amounts included accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting totaling $29 million and $34 million, respectively. See Note 12 to Financial Statements.

Other deductions totaled $9 million in 2011 and $8 million in 2010. Each of the 2011 and 2010 amounts included professional fees totaling $4 million. See Note 12 to Financial Statements.

Provision in lieu of income taxes totaled $229 million in 2011 (including $209 million related to operating income and $20 million related to nonoperating income) compared to $215 million (including $193 million related to operating income and $22 million related to nonoperating income) in 2010. The effective income tax rate on pretax income was 38.4% in 2011 and differs from the US federal statutory rate of 35% primarily due to the 2011 Texas gross margin tax and amortization of non-deductible basis differences. See Note 3 to Financial Statements for reconciliation of the effective rate to the US federal statutory rate.

Interest income decreased $6 million, or 16%, to $32 million in 2011. The decrease reflected lower reimbursement of transition bond interest from TCEH due to lower remaining principal amounts.

Interest expense and related charges increased $12 million, or 3%, to $359 million in 2011. The increase was driven by $7 million attributable to higher average interest rates due to the refinancing of short-term borrowings with $300 million and $475 million of senior secured notes issued in November 2011 and September 2010, respectively, and $5 million attributable to higher average borrowings reflecting ongoing capital investments.

Net income increased $15 million, or 4%, to $367 million in 2011. The increase reflected the effects on revenue of higher base revenue and warmer summer weather, partially offset by higher depreciation, higher operation and maintenance expenses and higher income taxes.

OTHER COMPREHENSIVE INCOME

In August 2011, we entered into interest rate hedge transactions hedging the variability of treasury bond rates used to determine the interest rates on an anticipated issuance of senior secured notes (see Note 6 to Financial Statements for information regarding the debt issuance). The hedges were terminated in November 2011 upon the issuance of the senior secured notes. We reported the $46 million ($29 million after tax) loss related to the fair value of the hedge transaction in accumulated other comprehensive income, which is being reclassified into net income over the life of the senior secured notes issued, which mature in 2041.

24

In 2012, we reported $4 million ($3 million after tax) in other comprehensive income, which represents the net actuarial losses of the non-recoverable portion of benefit plans (see Note 9 to Financial Statements for information regarding changes to the pension plans).

FINANCIAL CONDITION

Liquidity and Capital Resources

Cash Flows—Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Cash provided by operating activities totaled $1.269 billion and $1.295 billion in 2012 and 2011, respectively. The $26 million decrease was driven by a $112 million effect of significantly lower income tax refunds in 2012 compared to 2011, a $57 million SARs payout (see Note 10 to Financial Statements), a $26 million decrease in accounts payable levels, a $20 million increase in ad valorem tax payments primarily due to the timing of such payments, a $20 million increase in cash interest payments primarily due to the early redemption of debt in June 2012, a $20 million increase in cash payments to third party transmission providers and an $18 million decrease in transition-related interest income as a result of the sale to EFIH of our interest and tax agreements with TCEH (see Note 11 to Financial Statements). These decreases in cash were partially offset by a $119 million increase in transmission and distribution receipts due to higher rates, an $89 million decrease in pension and OPEB contributions, a $25 million decrease in cash purchases of materials and supplies and a $22 million decrease related to retrospective municipal franchise fees paid as a result of the 2011 rate review settlement.

Cash provided by financing activities totaled $132 million and $80 million in 2012 and 2011, respectively. The 2012 activity reflected a $343 million increase in short-term borrowings, a $159 million increase reflecting the sale to EFIH of our interest and tax agreements with TCEH (see Note 11 to Financial Statements) and $20 million in payments received on the related note receivable from TCEH, partially offset by $225 million of cash used in distributions to our members (an $80 million increase compared to 2011 (see Note 8 to Financial Statements)), $118 million in cash principal payments on transition bonds (a $5 million increase compared to 2011 (all discussed in Note 6 to Financial Statements)) and $46 million in debt discount, financing and reacquisition expenses.

Cash used in investing activities, which consisted primarily of capital expenditures, totaled $1.368 billion in 2012 and $1.396 billion in 2011. The $28 million, or 2%, change was driven by the effect of the hedge transaction in 2011 (discussed in “Other Comprehensive Income” above) and a decrease in capital expenditures for transmission facilities, advanced metering deployment initiatives and infrastructure maintenance, partially offset by an increase in capital expenditures for information technology initiatives, distribution facilities to serve new customers and other general plant.

Depreciation and amortization expense reported in the statements of consolidated cash flows was $31 million and $13 million more than the amounts reported in the statements of consolidated income for the years ended December 31, 2012 and 2011, respectively. The differences represent the accretion of the adjustment (discount) to regulatory assets, net of the amortization of debt fair value discount, both due to purchase accounting, and reported in other income and interest expense and related charges, respectively, in the statements of consolidated income. In addition, the differences represent regulatory asset amortization, which is reported in operation and maintenance expense in the statements of consolidated income.

Cash Flows—Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Cash provided by operating activities totaled $1.295 billion and $1.098 million in 2011 and 2010, respectively. The drivers of the $197 million increase included a $243 million effect of net tax refunds in 2011 compared to net tax payments in 2010 and a $149 million increase in transmission and distribution receipts due to higher rates and increased consumption attributed to the effects of warmer summer weather in 2011. The increases were partially offset by a $132 million increase in pension and OPEB contributions, a $24 million increase in storm-related restoration efforts incurred in 2011, a $22 million increase related to retrospective municipal franchise fees paid as a result of the 2011 rate review settlement (see Note 2 to Financial Statements) and a $15 million increase in interest payments due to the issuance of senior secured notes in November 2011 and September 2010.

25

Cash provided by and used in financing activities totaled $80 million and $61 million in 2011 and 2010, respectively. The 2011 activity reflected $145 million of cash used in distributions to our members (a $66 million decrease from 2011 (see Note 8 to Financial Statements)), offset by a $185 million increase in cash resulting from the net effect of issuances of debt and a reduction in short-term borrowings (see Note 6 to Financial Statements) and a $40 million decrease in the income-tax related note receivable from TCEH.

Cash used in investing activities, primarily for capital expenditures, totaled $1.396 billion in 2011 and $1.032 billion in 2010. The $364 million, or 35%, increase was driven by an increase in capital expenditures for CREZ investments, infrastructure maintenance, distribution facilities to serve new customers and information technology initiatives, partially offset by decreased spending for other transmission facilities, general plant and advanced metering deployment initiatives.

Depreciation and amortization expense reported in the statements of consolidated cash flows was $13 million and $9 million more than the amounts reported in the statements of consolidated income for the years ended December 31, 2011 and 2010, respectively. The differences represent amortization of regulatory assets, offset by the accretion of the adjustment (discount) to regulatory assets, net of the amortization of debt fair value discount, both due to purchase accounting, and reported in other income and interest expense and related charges, respectively, in the statements of consolidated income.

Long-Term Debt Activity —Repayments of long-term debt in 2012 totaled $1.018 billion, consisting of $376 million principal amount of 6.375% senior secured notes paid at the scheduled maturity date of May 1, 2012, the redemption of $524 million principal amount of 5.950% senior secured notes due September 1, 2013 (2013 Notes) and $118 million principal amount of transition bonds paid at scheduled maturity dates.

Issuances of long-term debt in 2012 totaled $900 million, consisting of $400 million aggregate principal amount of 4.10% Senior Secured Notes due 2022 (2022 Notes) and $500 million aggregate principal amount of 5.30% Senior Secured Notes due 2042 (2042 Notes). We used the net proceeds of approximately $890 million from the sale of the 2022 notes and the 2042 notes to repay borrowings under our revolving credit facility, to redeem all of our 2013 Notes and for other general corporate purposes. See Note 6 to Financial Statements for additional information regarding repayments, redemptions and issuances 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 December 31, 2012, we had a $2.4 billion secured revolving credit facility, reflecting a $400 million increase in commitments under the revolving credit facility effective May 15, 2012 (see Note 5 to Financial Statements). The revolving credit facility expires in October 2016. At December 31, 2011, the revolving credit facility had $2.0 billion in commitments under which borrowings were available on a revolving basis through October 2016. Subject to the limitations described below, available borrowing capacity under our revolving credit facility totaled $1.659 billion and $1.602 billion at December 31, 2012 and 2011, respectively. We may request an additional 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 December 31, 2012, we were in compliance with the covenant. See “Financial Covenants, Credit Rating Provisions and Cross Default Provisions” below for additional information on this covenant and the calculation of this ratio. The revolving credit facility and the senior notes and debentures issued by us are secured by the Deed of Trust, which permits us to secure other indebtedness with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the lower of the fair value or cost of certain property additions that could be certified to the Deed of Trust collateral agent. Accordingly, the availability under our revolving credit facility is limited by the amount of available bond credits and any property additions certified to the Deed of Trust collateral agent in connection with the revolving credit facility borrowings. In addition, our outstanding senior notes and debentures are secured by the Deed of Trust. To the extent we continue to issue debt securities secured by the Deed of Trust, those debt securities would also be limited by the amount of available bond credits and any property additions that could be certified to the Deed of Trust collateral agent. At December 31, 2012, the available bond credits totaled $2.2 billion, and the amount of additional potential indebtedness that could be secured by property additions, subject to the completion of a certification process, totaled $731 million. At December 31, 2012, the available borrowing capacity of the revolving credit facility could be fully drawn.

We also committed to the PUCT that we would maintain a regulatory capital structure at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. At December 31, 2012 and 2011, our regulatory capitalization ratios were 58.8% debt and 41.2% equity and 59.7% debt and 40.3% equity, respectively. See Note 8 to Financial Statements for discussion of the debt-to-equity ratio.

26

Cash and cash equivalents totaled $45 million and $12 million at December 31, 2012 and 2011, respectively. Available liquidity (cash and available credit facility capacity) at December 31, 2012 totaled $1.704 billion reflecting an increase of $90 million as compared to December 31, 2011. The change reflects the increase in available credit facility commitments and the impact of weather from year to year on our cash flow, partially offset by ongoing capital investment in transmission and distribution infrastructure.

Under the terms of our revolving credit facility, the commitments of the lenders to make loans to us are several and not joint. Accordingly, if any lender fails to make loans to us, our available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the facility. See Note 5 to Financial Statements for additional information regarding the revolving credit facility.

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, including amounts related to CREZ construction and voltage support projects totaling approximately $350 million in 2013, $120 million in 2014 and $30 million in 2015. These capital expenditures are expected to be used for investment in transmission and distribution infrastructure. In 2012, we satisfied our commitment to spend a minimum of $3.6 billion in capital expenditures (excluding amounts related to CREZ construction projects) over the five-year period ending December 31, 2012. See Note 2 to Financial Statements for discussion of this and other commitments in the stipulation approved by the PUCT and “Regulation and Rates” below for discussion of the CREZ projects.

We expect cash flows from operations, combined with availability under the revolving credit facility, to provide sufficient liquidity to fund current obligations, projected working capital requirements, maturities of long-term debt and capital spending for at least the next twelve months. Should additional liquidity or capital requirements arise, we may need to access capital markets, generate equity capital or preserve equity through reductions or suspension of distributions to members. In addition, we may also consider new debt issuances, repurchases, exchange offers and other transactions in order to refinance or manage our long-term debt. The inability to raise capital on favorable terms or failure of counterparties to perform under credit or other financial agreements, particularly during any uncertainty in the financial markets, could impact our ability to sustain and grow the business and would likely increase capital costs that may not be recoverable through rates.

Distributions — On February 13, 2013, our board of directors declared a cash distribution of $50 million, which was paid to our members on February 15, 2013. See Note 8 to Financial Statements for discussion of distribution restrictions.

During 2012, our board of directors declared, and we paid, the following cash distributions to our members:

Declaration Date	Payment Date	Amount
October 24, 2012	October 30, 2012	$	70
July 25, 2012	July 31, 2012	$	50
April 25, 2012	May 1, 2012	$	60
February 14, 2012	February 21, 2012	$	45

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. Based on the funded status of the pension plans at December 31, 2012 and as a result of the effect of the amendments on the EFH Retirement Plan and the new retirement plans, our aggregate pension plans and OPEB Plan funding is expected to total approximately $510 million for 2013 to 2017. In 2012, we made cash contributions to the pension plans and the OPEB Plan of $93 million and $11 million, respectively. See Note 9 to Financial Statements for additional information regarding the pension plans and the OPEB Plan, including discussion of the amendments to the EFH Retirement Plan adopted by EFH Corp in 2012.

In July 2012, the US Congress enacted legislation that includes, among other things, pension funding stabilization provisions. These provisions are not expected to have a material impact on our long-term funding levels absent a sustained low interest rate environment.

27

Capitalization— Our capitalization ratios were 42.5% and 41.7% long-term debt, less amounts due currently, to 57.5% and 58.3% membership interests at December 31, 2012 and 2011, 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 December 31, 2012, we were in compliance with this covenant with a debt-to-capitalization ratio of 0.44 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 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.

In August 2012, Moody’s changed our senior secured credit rating from Baa1 to Baa2. The downgrade in our credit rating was primarily driven by Moody’s view of the risks to which we are exposed by EFH Corp. (our majority equity investor) and TCEH, and increased debt at EFIH. In December 2012, Moody’s changed our ratings outlook to “developing” from “negative” based on their views regarding certain steps implemented by EFH Corp. In February 2013, S&P changed our senior secured credit rating to A from A- after revising its criteria for rating utility first mortgage bonds. Oncor remains on “stable outlook” with S&P and Fitch. The credit ratings assigned for debt securities issued by us at February 15, 2013 are presented below.

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

As described in Note 6 to Financial Statements, our long-term debt, excluding Bondco’s non-recourse debt, is currently secured pursuant to the Deed of Trust by a first priority lien on certain of our transmission and distribution assets and is considered senior secured debt.

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

Material Credit Rating Covenants — Our revolving credit facility contains terms pursuant to which the interest rates charged under the agreement may be adjusted depending on credit ratings. Borrowings under the revolving credit facility bear interest at per annum rates equal to, at our option, (i) LIBOR plus a spread ranging from 1.00% to 1.75% depending on credit ratings assigned to our senior secured non-credit enhanced long-term debt or (ii) an alternate base rate (the highest of (1) the prime rate of JPMorgan Chase, (2) the federal funds effective rate plus 0.50%, and (3) daily one-month LIBOR plus 1.00%) plus a spread ranging from 0.00% to 0.75% depending on credit ratings assigned to our senior secured non-credit enhanced long-term debt. Based on our current ratings, our borrowings are generally LIBOR-based and will bear interest at LIBOR plus 1.25%. A decline in credit ratings would increase the cost of our revolving credit facility and likely increase the cost of any debt issuances and additional credit facilities.

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

28

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 ($735 million in short-term borrowings and $6 million in letters of credit at December 31, 2012) under such facility to be accelerated. Additionally, under the Deed of Trust, an event of default under either our revolving credit facility or our indentures would permit our lenders and the holders of our senior secured notes to exercise their remedies under the Deed of Trust.

Long-Term Contractual Obligations and Commitments— The following table summarizes our contractual cash obligations at December 31, 2012 (see Notes 6 and 7 to Financial Statements for additional disclosures regarding these long-term debt and non-cancelable purchase obligations).

Contractual Cash Obligations	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years		Total
Long-term debt – principal	$	125	$	770	$	365	$	4,301	$	5,561
Long-term debt – interest		317		618		559		3,268		4,762
Operating leases (a)		7		9		4		—		20
Obligations under outsourcing agreements		5		119		7		—		131
Total contractual cash obligations	$	454	$	1,516	$	935	$	7,569	$	10,474

(a) Includes short-term noncancelable leases.

The following are not included in the table above:

• individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one counterparty that are more than $1 million on an aggregated basis have been included);

• employment contracts with management;

• liabilities related to uncertain tax positions totaling $144 million discussed in Note 3 to Financial Statements as the ultimate timing of payment is not known;

• our estimated funding of the pension plans and the OPEB Plan totaling $22 million in 2013 and approximately $510 million for the 2013 to 2017 period as discussed above under “Pension and OPEB Plan Funding,” and

• capital expenditures under PUCT orders (CREZ-related projects) and other commitments made (see Note 2 to Financial Statements).

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

OFF-BALANCE SHEET ARRANGEMENTS

At December 31, 2012, we did not have any material off-balance sheet arrangements with special purpose entities or VIEs.

COMMITMENTS AND CONTINGENCIES

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

CHANGES IN ACCOUNTING STANDARDS

There have been no recently issued accounting standards effective after December 31, 2012 that are expected to materially impact us.

29

REGULATION AND RATES

Sunset Review and Other State Legislation

The PUCT is subject to a limited purpose “sunset” review by the Texas Legislature in the 2013 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (e.g., PUCT), along with an evaluation of the advisability of any changes to that agency’s authorizing legislation (e.g., PURA). We cannot predict the outcome of the sunset review.

Matters with the PUCT

2011 Rate Review Filing (PUCT Docket No. 38929)— In January 2011, we filed a rate review with the PUCT and 203 original jurisdiction cities based on a test year ended June 30, 2010. In April 2011, we and the other parties reached a Memorandum of Settlement that would settle and resolve all issues in the rate review. We filed a stipulation in May 2011 that incorporated the Memorandum of Settlement along with pleadings and other documentation (Stipulation) for the purpose of obtaining final approval of the settlement. The terms of the Stipulation include an approximate $137 million base rate increase and additional provisions to address franchise fees (discussed below) and other expenses. Approximately $93 million of the increase became effective July 1, 2011, and the remainder became effective January 1, 2012. Under the Stipulation, amortization of regulatory assets increased by approximately $24 million ($14 million of which will be recognized as tax expense) annually beginning January 1, 2012. The Stipulation did not change our authorized regulatory capital structure of 60% debt and 40% equity or our authorized return on equity of 10.25%. Under the terms of the Stipulation, we cannot file another general base rate review prior to July 1, 2013, but we are not restricted from filing wholesale transmission rate, TCRF, distribution-related investment and other rate updates and adjustments permitted by Texas state law and PUCT rules.

In response to concerns raised by PUCT Commissioners at a July 2011 PUCT open meeting regarding the Stipulation, we filed a modified stipulation that removed from the Stipulation a one-time payment to certain cities we serve for retrospective franchise fees (Modified Stipulation). Instead, pursuant to the terms of a separate agreement with certain cities we serve, through December 31, 2012, we have made $22 million in retrospective franchise fee payments to cities that accepted the terms of the separate agreement. The payments are subject to refund from the cities or recovery from customers after final resolution of proceedings related to the appeals from our June 2008 rate review filing (discussed below). No other significant terms of the Stipulation were revised. In August 2011, the PUCT issued a final order approving the settlement terms contained in the Modified Stipulation.

2008 Rate Review Filing (PUCT Docket No. 35717) — In August 2009, the PUCT issued a final order with respect to our June 2008 rate review filing with the PUCT and 204 cities based on a test year ended December 31, 2007, and new rates were implemented in September 2009. The final order approved a total annual revenue requirement for us of $2.64 billion. New rates were calculated for all customer classes using 2007 test year billing metrics and the approved class cost allocation and rate design. The PUCT staff estimated that the final order resulted in an approximate $115 million increase in base rate revenues over our 2007 adjusted test year revenues, before recovery of rate review expenses. Prior to implementing the new rates in September 2009, we had already begun recovering $45 million of the $115 million increase as a result of approved transmission cost recovery factor and energy efficiency cost recovery factor filings, such as those discussed below.

Key findings by the PUCT in the rate review included:

• recognizing and affirming our corporate ring-fence from EFH Corp. and its unregulated affiliates by rejecting a proposed consolidated tax savings adjustment arising out of EFH Corp.’s ability to offset our taxable income against losses from other investments;

• approving the recovery of all of our capital investment in our transmission and distribution system, including investment in certain automated meters that will be replaced pursuant to our advanced meter deployment plan;

• denying recovery of $25 million of regulatory assets, which resulted in a $16 million after-tax loss being recognized in the third quarter of 2009, and

• setting our return on equity at 10.25%.

30

In November 2009, the PUCT issued an order on rehearing that established a new rate class but did not change the revenue requirements. We and four other parties appealed various portions of the rate review final order to a state district court, and oral argument was held in October 2010. In January 2011, the district court signed its judgment reversing the PUCT with respect to two issues: the PUCT’s disallowance of certain franchise fees and the PUCT’s decision that PURA no longer requires imposition of a rate discount for state colleges and universities. We filed an appeal with the Austin Court of Appeals in February 2011 with respect to the issues we appealed to the district court and did not prevail upon, as well as the district court’s decision to reverse the PUCT with respect to discounts for state colleges and universities. Oral argument before the Austin Court of Appeals was completed in April 2012. There is no deadline for the court to act. We are unable to predict the outcome of the appeal.

Competitive Renewable Energy Zones (CREZs) — In 2009, the PUCT awarded us CREZ construction projects (PUCT Docket Nos. 35665 and 37902) requiring 14 related Certificate of Convenience and Necessity (CCN) amendment proceedings before the PUCT for 17 of those projects. All 17 projects and 14 CCN amendments have been approved by the PUCT. The projects involve the construction of transmission lines and stations to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. In addition to these projects, ERCOT completed a study in December 2010 that will result in us and other transmission service providers building additional facilities to provide further voltage support to the transmission grid as a result of CREZ. We currently estimate, based on these additional voltage support facilities and the approved routes and stations for our awarded CREZ projects, that CREZ construction costs will total approximately $2.0 billion. CREZ-related costs could change based on finalization of costs for the additional voltage support facilities and final detailed designs of subsequent project routes. At December 31, 2012, our cumulative CREZ-related capital expenditures totaled $1.460 billion, including $561 million during 2012. 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.

Advanced Metering Deployment Surcharge Filing (PUCT Docket Nos. 35718 and 36157) — In May 2008, we filed with the PUCT a description and request for approval of our proposed advanced metering system (AMS) deployment plan and proposed surcharge for the recovery of estimated future investment for AMS deployment. In September 2008, a PUCT order became final approving a settlement reached with the majority of the parties to this surcharge filing. The settlement included the following major provisions, as amended by the final order in the 2008 rate review:

• the full deployment of over three million advanced meters to all residential and most non-residential retail electricity customers in our service area;

• a surcharge beginning on January 1, 2009 and continuing for 11 years;

• a total revenue requirement over the surcharge period of $1.023 billion;

• estimated capital expenditures for advanced metering facilities of $686 million;

• related operation and maintenance expenses for the surcharge period of $153 million;

• $204 million of operation and maintenance expense savings, and

• an advanced metering cost recovery factor of $2.19 per month per residential retail customer and varying from $2.39 to $5.15 per month for non-residential retail customers.

At December 31, 2012, we had installed 3,263,000 advanced digital meters (including 961,000 during 2012) completing our planned deployment of advanced meters to all residential and most non-residential retail electricity customers in our service area. Cumulative capital expenditures for the deployment of the advanced meter system totaled $660 million through December 31, 2012, including $142 million in 2012. With the new meters integrated, we report 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options.

We may, through subsequent reconciliation proceedings (see discussion below), request recovery of additional costs that are reasonable and necessary. While there is a presumption that costs spent in accordance with a plan approved by the PUCT are reasonable and necessary, recovery of any costs that are found not to have been spent or properly allocated, or not to be reasonable or necessary, must be refunded.

31

Application for Reconciliation of Advanced Meter Surcharge (PUCT Docket No. 39552)— In July 2011, we filed an application with the PUCT for reconciliation of all costs incurred and investments made through December 31, 2010, in the deployment of our AMS pursuant to our AMS Deployment Plan approved in Docket No. 35718. The order in Docket No. 35718 included a requirement that we file a reconciliation proceeding two years after the implementation of the AMS surcharge. Through the end of 2010, we had spent approximately $357 million in executing the approved AMS Deployment Plan and billed customers approximately $171 million through the AMS surcharge. We did not seek a change in the AMS surcharge or the AMS Deployment Plan in this proceeding. In October 2011, we and the other parties to the case filed a proposed order and stipulation, which would resolve all issues in the case. In November 2011, the PUCT issued its final order in the proceeding approving the stipulation and finding that costs expended and investments made in the deployment of our AMS through December 31, 2010 were properly allocated, reasonable and necessary.

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 allow 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 revenues (millions of dollars) in the years ended December 31, 2012 and 2011 are listed below.

Docket No.	Filed	Effective	Semi-Annual Revenue  Impact Increase (Decrease)
41002	November 2012	March 2013 – August 2013	$	(47	)
40451	June 2012	September 2012 – February 2013	$	129
39940	November 2011	March 2012 – August 2012	$	(41	)
39456	June 2011	September 2011 – February 2012	$	24
38938	December 2010	March 2011 – August 2011	$	17
38460	July 2010	September 2010 – February 2011	$	7

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 wholesale transmission providers benefitting from our transmission system and, through the TCRF mechanism, to REPs with retail customers in our service territory. TCOS filings impacting revenues (millions of dollars) in the years ended December 31, 2012 and 2011 are listed below.

Docket No.	Filed	Effective	Annual Revenue Impact		Third Party Wholesale Transmission		Included in TCRF
41166*	January 2013	March 2013	$	27	$	17	$	10
40603	July 2012	August 2012	$	30	$	19	$	11
40142	January 2012	March 2012	$	2	$	1	$	1
39644	August 2011	October 2011	$	35	$	22	$	13
38495	July 2010	September 2010	$	43	$	27	$	16

* Approval pending.

32

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 over/under recovery of our costs in prior years. PUCT rules require us to make an annual EECRF filing by the first business day in May of each year for implementation at the beginning of the next calendar year. Approved EECFR filings impacting revenues (millions of dollars, except monthly charge amounts) in the years ended December 31, 2012 and 2011 are listed below.

							Prior Year Amounts
Docket No.	Filed	Effective	Monthly  Charge per Residential Customer		Program Costs		Performance Bonus		Under-/ (Over-) Recovery
40361	May 2012	January 1, 2013	$	1.23	$	62	$	9	$	2
39375	May 2011	January 1, 2012	$	0.99	$	49	$	8	$	(3	)
38217	April 2010	January 1, 2011	$	0.91	$	45	$	11	$	(5	)

Remand of 1999 Wholesale Transmission Matrix Case (PUCT Docket No. 38780)— In October 2010, the PUCT established Docket No. 38780 for the remand of Docket No. 20381, the 1999 wholesale transmission charge matrix case. A joint settlement agreement was entered into effective October 6, 2003. This settlement resolved disputes regarding wholesale transmission pricing and charges for the period January 1997 through August 1999, the period prior to the September 1, 1999 effective date of the legislation that authorized 100% postage stamp pricing for ERCOT wholesale transmission. After a series of appeals became final, the 1999 matrix docket was remanded to the PUCT to address two additional issues. The PUCT ruled on both issues in January 2012. No appeals were filed prior to the appeals deadlines, and the PUCT orders became final in February 2012. See Note 7 to Financial Statements for a discussion of this proceeding.

Stipulation Approved by the PUCT— In April 2008, the PUCT entered an order (PUCT Docket No. 34077), which became final in June 2008, approving the terms of a stipulation relating to a filing in 2007 by us and Texas Holdings with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. Among other things, the stipulation required us to file a rate review no later than July 1, 2008 based on a test year ended December 31, 2007, which we filed in June 2008. The PUCT issued a final order with respect to the rate review in August 2009. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200^th District Court of Travis County, Texas (District Court). A hearing on the appeal was held in June 2010, and the District Court affirmed the PUCT order in its entirety. Nucor Steel appealed that ruling to the Austin Court of Appeals in July 2010. Oral argument was held before the Austin Court of Appeals in March 2011. In March 2012, the Austin Court of Appeals affirmed the District Court’s ruling, which is now final.

Summary

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

33

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate 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 December 31, 2012 and 2011 carried fixed interest rates.

	Expected Maturity Date
	2013			2014			2015			2016			2017			There- after			2012 Total Carrying Amount			2012 Total Fair Value		2011 Total Carrying Amount			2011 Total Fair Value
	(millions of dollars, except percentages)
Long-term debt (including current maturities):
Fixed rate debt amount (a)	$	125		$	131		$	639		$	41		$	324		$	4,301		$	5,561		$	6,568	$	5,679		$	6,705
Average interest rate		5.30	%		5.34	%		6.15	%		5.29	%		5.00	%		6.17	%		6.12	%		—		6.28	%		—

(a) Excludes unamortized premiums and discounts. See Note 6 to Financial Statements for a discussion of changes in long-term debt obligations.

Credit Risk

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

Our exposure to credit risk associated with accounts receivable totaled $53 million from affiliates, substantially all of which consisted of trade accounts receivable from TCEH, and $340 million from nonaffiliated customers at December 31, 2012. The nonaffiliated customer receivable amount is before the allowance for uncollectible accounts, which totaled $2 million at December 31, 2012. The nonaffiliated exposure includes trade accounts receivable from REPs totaling $251 million, which are almost entirely noninvestment grade. At December 31, 2012, REP subsidiaries of a nonaffiliated entity collectively represented approximately 12% of the nonaffiliated trade receivable amount. No other nonaffiliated parties represented 10% or more of the total exposure. We view our exposure to this customer to be within an acceptable level of risk tolerance considering PUCT rules and regulations; however, this concentration increases the risk that a default would have a material effect on cash flows. See Note 11 to Financial Statements for additional information.

34

FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain “forward-looking statements.” All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of facilities, market and industry developments and the growth of our business and operations (often, but not always, through the use of words or phrases such as “intends,” “plans,” “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “should,” “projection,” “target,” “goal,” “objective” and “outlook”), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under Item 1A. “Risk Factors” and the discussion under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report and the following important factors, among others, that could cause actual results to differ materially from those projected in such forward-looking statements:

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

• allowed rate of return;

• permitted capital structure;

• industry, market and rate structure;

• recovery of investments;

• acquisition and disposal of assets and facilities;

• operation and construction of facilities;

• changes in tax laws and policies, and

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

• legal and administrative proceedings and settlements, including the exercise of equitable powers by courts;

• weather conditions and other natural phenomena;

• acts of sabotage, wars or terrorist or cyber security threats or activities;

• economic conditions, including the impact of a recessionary environment;

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

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

• unanticipated changes in interest rates or rates of inflation;

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

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

• general industry trends;

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

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

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

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

• significant changes in critical accounting policies material to us;

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

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

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

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

• actions by credit rating agencies, and

• our ability to effectively execute our operational strategy.

35

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

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of Oncor Electric Delivery Company LLC

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Oncor Electric Delivery Company LLC and subsidiary (the “Company”) as of December 31, 2012 and 2011, and the related statements of consolidated income, comprehensive income, cash flows and membership interests for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Oncor Electric Delivery Company LLC and subsidiary as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on the criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Dallas, Texas

February 19, 2013

36

ONCOR ELECTRIC DELIVERY COMPANY LLC

STATEMENTS OF CONSOLIDATED INCOME

(millions of dollars)

	Year Ended December 31,
	2012			2011		2010
Operating revenues:
Affiliated	$	962		$	1,026	$	1,061
Nonaffiliated		2,366			2,092		1,853
Total operating revenues		3,328			3,118		2,914
Operating expenses:
Wholesale transmission service		502			439		393
Operation and maintenance		669			658		616
Depreciation and amortization		771			719		673
Provision in lieu of income taxes (Note 3)		240			209		193
Taxes other than amounts related to income taxes		415			400		384
Total operating expenses		2,597			2,425		2,259
Operating income		731			693		655
Other income and deductions:
Other income (Note 12)		26			30		36
Other deductions (Note 12)		64			9		8
Nonoperating provision (benefit) in lieu of income taxes (Note 3)		(6	)		20		22
Interest income		24			32		38
Interest expense and related charges (Note 12)		374			359		347
Net income	$	349		$	367	$	352

See Notes to Financial Statements.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(millions of dollars)

	Year Ended December 31,
	2012			2011			2010
Net income	$	349		$	367		$	352
Other comprehensive income (loss):
Cash flow hedges (Notes 1 and 6):
Net decrease in fair value of derivatives (net of tax benefit of $—, $17 and $—)		—			(29	)		—
Derivative value net loss recognized in net income (net of tax benefit of $1, $— and $—)		3			—			—
Total cash flow hedges		3			(29	)		—
Defined benefit pension and OPEB plans (net of tax benefit of $1, $— and $—) (Note 9)		(3	)		—			—
Total other comprehensive loss		—			(29	)		—
Comprehensive income	$	349		$	338		$	352

See Notes to Financial Statements.

37

ONCOR ELECTRIC DELIVERY COMPANY LLC

STATEMENTS OF CONSOLIDATED CASH FLOWS

(millions of dollars)

	Year Ended December 31,
	2012			2011			2010
Cash flows — operating activities:
Net income	$	349		$	367		$	352
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		802			732			682
Provision in lieu of deferred income taxes — net		208			258			193
Amortization of investment tax credits		(4	)		(5	)		(5	)
Other — net		—			2			—
Changes in operating assets and liabilities:
Accounts receivable — trade (including affiliates)		52			(36	)		(1	)
Inventories		(3	)		25			(4	)
Accounts payable — trade (including affiliates)		(9	)		17			(17	)
Deferred revenues (Note 4)		(101	)		(7	)		4
Other — assets		(17	)		111			3
Other — liabilities		(8	)		(169	)		(109	)
Cash provided by operating activities		1,269			1,295			1,098
Cash flows — financing activities:
Issuances of long-term debt (Note 6)		900			300			475
Repayments of long-term debt (Note 6)		(1,018	)		(113	)		(108	)
Net increase (decrease) in short-term borrowings (Note 5)		343			15			(239	)
Distributions to members (Note 8)		(225	)		(145	)		(211	)
Decrease in note receivable from TCEH (Note 11)		20			40			37
Sale of related-party agreements (Note 11)		159			—			—
Debt discount, financing and reacquisition expenses — net		(46	)		(17	)		(15	)
Other		(1	)		—			—
Cash provided by (used in) financing activities		132			80			(61	)
Cash flows — investing activities:
Capital expenditures		(1,389	)		(1,362	)		(1,020	)
Other — net		21			(34	)		(12	)
Cash used in investing activities		(1,368	)		(1,396	)		(1,032	)
Net change in cash and cash equivalents		33			(21	)		5
Cash and cash equivalents — beginning balance		12			33			28
Cash and cash equivalents — ending balance	$	45		$	12		$	33

See Notes to Financial Statements.

38

ONCOR ELECTRIC DELIVERY COMPANY LLC

CONSOLIDATED BALANCE SHEETS

(millions of dollars)

	At December 31,
	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	45		$	12
Restricted cash — Bondco (Note 12)		55			57
Trade accounts receivable from nonaffiliates — net (Note 12)		338			303
Trade accounts and other receivables from affiliates (Note 11)		53			179
Amounts receivable from members related to income taxes (Note 11)		—			5
Materials and supplies inventories — at average cost		73			71
Prepayments and other current assets		79			80
Total current assets		643			707
Restricted cash — Bondco (Note 12)		16			16
Investments and other property (Note 12)		83			73
Property, plant and equipment — net (Note 12)		11,318			10,569
Goodwill (Notes 1 and 12)		4,064			4,064
Note receivable from TCEH (Note 11)		—			138
Regulatory assets—net — Oncor (Note 4)		1,453			1,303
Regulatory assets—net — Bondco (Note 4)		335			427
Other noncurrent assets		78			74
Total assets	$	17,990		$	17,371
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Short-term borrowings (Note 5)	$	735		$	392
Long-term debt due currently — Oncor (Note 6)		—			376
Long-term debt due currently — Bondco (Note 6)		125			118
Trade accounts payable		121			197
Amounts payable to members related to income taxes (Note 11)		22			—
Accrued taxes other than amounts related to income		153			151
Accrued interest		95			108
Other current liabilities		109			112
Total current liabilities		1,360			1,454
Long-term debt, less amounts due currently — Oncor (Note 6)		5,090			4,711
Long-term debt, less amounts due currently — Bondco (Note 6)		310			433
Liability in lieu of deferred income taxes (Notes 1, 3 and 11)		2,180			2,018
Investment tax credits		24			28
Other noncurrent liabilities and deferred credits (Notes 11 and 12)		1,722			1,546
Total liabilities		10,686			10,190
Commitments and contingencies (Note 7)
Membership interests (Note 8):
Capital account — number of interests outstanding: 2012 and 2011—635,000,000		7,335			7,212
Accumulated other comprehensive loss		(31	)		(31	)
Total membership interests		7,304			7,181
Total liabilities and membership interests	$	17,990		$	17,371

See Notes to Financial Statements.

39

ONCOR ELECTRIC DELIVERY COMPANY LLC

STATEMENTS OF CONSOLIDATED MEMBERSHIP INTERESTS

(millions of dollars)

	Year Ended December 31,
	2012			2011			2010
Capital account:
Balance at beginning of period	$	7,212		$	6,990		$	6,849
Net income		349			367			352
Distributions to members		(225	)		(145	)		(211	)
Sale of related-party agreements (net of tax benefit of $1, $— and $— ) (Note 11)		(2	)		—			—
Other		1			—			—
Balance at end of period (number of interests outstanding: 2012, 2011 and 2010 – 635 million)		7,335			7,212			6,990
Accumulated other comprehensive income (loss), net of tax effects:
Balance at beginning of period		(31	)		(2	)		(2	)
Net effects of cash flow hedges (net of tax expense (benefit) of $1, $(17) and $—) (Note 6)		3			(29	)		—
Defined benefit pension and OPEB plans (net of tax benefit of $1, $— and $—) (Note 9)		(3	)		—			—
Balance at end of period		(31	)		(31	)		(2	)
Total membership interests at end of period	$	7,304		$	7,181		$	6,988

See Notes to Financial Statements.

40

ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

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

We are a regulated electricity transmission and distribution company principally engaged in providing delivery services to REPs, including subsidiaries of TCEH, that sell power in the north-central, eastern and western parts of Texas. Revenues from TCEH represented 29%, 33% and 36% of our total operating revenues for the years ended December 31, 2012, 2011 and 2010, 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 VIE (see Note 12). 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 consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

From time to time, certain prior period amounts are reclassified to conform to the current period presentation. In the statements of consolidated cash flows included in this report, amounts previously reported as changes in deferred advanced metering system revenues for the years ended December 31, 2011 and 2010 are included in and reported as deferred revenues to conform to the current period presentation. In addition to deferred advanced metering system revenues, other reconcilable revenues (TCRF and energy efficiency surcharges), which were previously reported as changes in other operating assets and liabilities, are included in and reported as deferred revenues.

As discussed in Note 11, the balance sheet at December 31, 2011 has been restated to remove the regulatory liability for nuclear plant decommissioning and related receivable from TCEH related to nuclear plant decommissioning.

41

Consolidation of Variable Interest Entities

A VIE is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. We consolidate a VIE if we have: a) the power to direct the significant activities of the VIE and b) the right or obligation to absorb profit and loss from the VIE (primary beneficiary). See Note 12.

Income Taxes

EFH Corp. files a consolidated federal income tax return. Effective with the November 2008 sale of equity interests to Texas Transmission and Investment LLC, we became a partnership for US federal income tax purposes, and subsequently we are not a member of EFH Corp.’s consolidated tax group and only EFH Corp.’s share of our partnership income is included in its consolidated federal income tax return. Our tax sharing agreement with Oncor Holdings and EFH Corp. was amended in November 2008 to include Texas Transmission and Investment LLC. The tax sharing agreement provides for the calculation of tax liability substantially as if we and Oncor Holdings file our own income tax returns, and requires tax payments to members determined on that basis (without duplication for any income taxes paid by a subsidiary of Oncor Holdings). Accordingly, while partnerships are not subject to income taxes, in consideration of the tax sharing agreement and the presentation of our financial statements as an entity subject to cost-based regulatory rate-setting processes, with such costs including income taxes, the financial statements present amounts determined under the tax sharing agreement as “provision in lieu of income taxes” and “liability in lieu of deferred income taxes” for periods subsequent to the sales of equity interests discussed in Note 3.

Such amounts are determined in accordance with the provisions of accounting guidance for income taxes and for uncertainty in income taxes and thus differences between the book and tax bases of assets and liabilities are accounted for as if we filed our own income tax return. The accounting guidance for rate-regulated enterprises requires the recognition of regulatory assets or liabilities if it is probable such deferred tax amounts will be recovered from, or returned to customers in future rates. Investment tax credits are amortized to income over the estimated lives of the related properties.

We classify interest and penalties expense related to uncertain tax positions as current provision in lieu of income taxes as discussed in Note 3.

Use of Estimates

Preparation of our financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.

Derivative Instruments and Mark-to-Market Accounting

We have from time-to-time entered into derivative instruments to hedge interest rate risk. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, the fair value of each derivative is required to be 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

42

liabilities with an offset to net income, and the carrying value of the related asset or liability (hedged item) is adjusted for changes in fair value with an offset to net income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or loss associated with the hedge is amortized into income over the remaining life of the hedged item. To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedged item. Assessment of the hedge’s effectiveness is tested at least quarterly throughout its term to continue to qualify for hedge accounting. Hedge ineffectiveness, even if the hedge continues to be assessed as effective, is immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the change in value of the hedging instrument over the change in value of the hedged item.

Reconcilable Tariffs

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

Revenue Recognition

Revenue from delivery services are recorded under the accrual method of accounting. Revenues are recognized when delivery services are provided to customers on the basis of periodic cycle meter readings and include an estimate for revenues earned from the meter reading date to the end of the period adjusted for the impact of weather (unbilled revenue).

Impairment of Long-Lived Assets and Goodwill

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

We also evaluate goodwill for impairment annually (at December 1) or whenever events or changes in circumstances indicate that an impairment may exist.

Goodwill impairment tests performed in 2012 and 2010 were based on determinations of enterprise value using discounted cash flow analyses, comparable company equity values and any relevant transactions indicative of enterprise values (quantitative assessment).

Effective with the December 1, 2011 test, we adopted new accounting guidance that provides the option of using a qualitative assessment in which we may consider macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and other relevant events. Based on the results of the qualitative assessment performed, we concluded that no further testing for impairment was required in 2011.

System of Accounts

Our accounting records have been maintained in accordance with the FERC Uniform System of Accounts as adopted by the PUCT.

Defined Benefit Pension Plans and Other Postretirement Employee Benefit (OPEB) Plans

We participate in pension plans that offer benefits based on either a traditional defined benefit formula or a cash balance formula and the OPEB Plan 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. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. In 2012, EFH Corp. made various changes to the EFH Retirement Plan, including splitting off into a new plan all of the assets and liabilities associated with Oncor employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). See Note 9 for additional information regarding the pension plans and the OPEB Plan.

43

Stock-Based Incentive Compensation

In 2008, we implemented the SARs Plan for certain management that purchased equity interests in the company indirectly by investing in Investment LLC. We implemented the Director SARs Plan in 2009. SARs have been awarded under the SARs Plan and are being accounted for based upon the provisions of guidance for share-based payment. See Note 10 for information regarding stock-based compensation, including SARs granted to certain members of our board of directors and a 2012 early exercise of all outstanding SARS under both the SARs Plan and Director SARs Plan.

Fair Value of Nonderivative Financial Instruments

The carrying amounts for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value due to the short maturity of such instruments. The fair values of other financial instruments, for which carrying amounts and fair values have not been presented, are not materially different than their related carrying amounts. The following discussion of fair value accounting standards applies primarily to our determination of the fair value of assets in the pension and OPEB plan trusts as presented in Note 9.

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

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

• Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

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

• Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value.

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis.

Franchise Taxes

Franchise taxes are assessed to us by local governmental bodies, based on kWh delivered and are the principal component of taxes other than amounts related to income taxes as reported in the income statement. Franchise taxes are not a “pass through” item. The rates we charge customers are intended to recover the franchise taxes, but we are not acting as an agent to collect the taxes from customers.

44

Cash and Cash Equivalents

For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents. See Note 12 for details regarding restricted cash.

Property, Plant and Equipment

Properties are stated at original cost. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead and an allowance for funds used during construction.

Depreciation of property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties based on depreciation rates approved by the PUCT. As is common in the industry, depreciation expense is recorded using composite depreciation rates that reflect blended estimates of the lives of major asset groups as compared to depreciation expense calculated on a component asset-by-asset basis. Depreciation rates include plant removal costs as a component of depreciation expense, consistent with regulatory treatment. Actual removal costs incurred are charged to accumulated depreciation. When accrued removal costs exceed incurred removal costs, the difference is reclassified as a regulatory obligation to retire assets in the future.

Allowance for Funds Used During Construction (AFUDC)

AFUDC is a regulatory cost accounting procedure whereby both interest charges on borrowed funds and a return on equity capital used to finance construction are included in the recorded cost of utility plant and equipment being constructed. AFUDC is capitalized on all projects involving construction periods lasting greater than thirty days. The equity portion of capitalized AFUDC is accounted for as other income. We recorded $1 million of equity AFUDC for the year ended December 31, 2012 and none for each of the years ended December 31, 2011 and 2010. See Note 12 for detail of amounts charged to interest expense.

Regulatory Assets and Liabilities

Our financial statements reflect regulatory assets and liabilities under cost-based rate regulation in accordance with accounting standards related to the effect of certain types of regulation. Regulatory decisions can have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 4 for details of regulatory assets and liabilities.

2. REGULATORY MATTERS

2011 Rate Review

In January 2011, we filed a rate review with the PUCT and 203 original jurisdiction cities based on a test year ended June 30, 2010 (PUCT Docket No. 38929). In April 2011, we and the other parties reached a Memorandum of Settlement that would settle and resolve all issues in the rate review. We filed a stipulation (including a proposed order and proposed tariffs) in May 2011 that incorporated the Memorandum of Settlement along with pleadings and other documentation (Stipulation) for the purpose of obtaining final approval of the settlement. The terms of the Stipulation include an approximate $137 million base rate increase and additional provisions to address franchise fees (discussed below) and other expenses. Approximately $93 million of the increase became effective July 1, 2011, and the remainder became effective January 1, 2012. Under the Stipulation, amortization of regulatory assets increased by approximately $24 million ($14 million of which will be recognized as tax expense) annually beginning January 1, 2012. The Stipulation did not change our authorized regulatory capital structure of 60% debt and 40% equity or our authorized return on equity of 10.25%. Under the terms of the Stipulation, we cannot file another general base rate review prior to July 1, 2013, but are not restricted from filing wholesale transmission rate, TCRF, distribution-related investment and other rate updates and adjustments permitted by Texas state law and PUCT rules.

In response to concerns raised by PUCT Commissioners at a July 2011 PUCT open meeting regarding the Stipulation, we filed a modified stipulation that removed from the Stipulation a one-time payment to certain cities we serve for retrospective franchise fees (Modified Stipulation). Instead, pursuant to the terms of a separate agreement with certain cities we serve, through December 31, 2012, we have made $22 million in retrospective franchise fee payments to cities that

45

accepted the terms of the separate agreement. The payments are subject to refund from the cities or recovery from customers after final resolution of proceedings related to the appeals from our June 2008 rate review filing (discussed below). No other significant terms of the Stipulation were revised. In August 2011, the PUCT issued a final order approving the settlement terms contained in the Modified Stipulation.

Effective July 1, 2011, pursuant to the PUCT’s final order, we no longer recover the cost of wholesale transmission service through base rates, and wholesale transmission service expenses incurred are reconcilable to revenues billed under the TCRF rider. For this purpose, all wholesale transmission service expenses consist of amounts charged under a PUCT-approved transmission tariff including our own wholesale transmission tariff. We account for the difference between amounts charged under the TCRF rate and wholesale transmission service expense as a regulatory asset or regulatory liability (under- or over-recovered wholesale transmission service expense (see Note 1)). At December 31, 2012, approximately $60 million ($40 million after tax) was deferred as under-recovered wholesale transmission service expense (see Note 4).

2008 Rate Review

In August 2009, the PUCT issued a final order with respect to our June 2008 rate review filing with the PUCT and 204 cities based on a test year ended December 31, 2007 (PUCT Docket No. 35717), and new rates were implemented in September 2009. In November 2009, the PUCT issued an order on rehearing that established a new rate class but did not change the revenue requirements. We and four other parties appealed various portions of the rate review final order to a state district court, and oral argument was held in October 2010. In January 2011, the district court signed its judgment reversing the PUCT with respect to two issues: the PUCT’s disallowance of certain franchise fees and the PUCT’s decision that PURA no longer requires imposition of a rate discount for state colleges and universities. We filed an appeal with the Texas Third Court of Appeals (Austin Court of Appeals) in February 2011 with respect to the issues we appealed to the district court and did not prevail upon, as well as the district court’s decision to reverse the PUCT with respect to discounts for state colleges and universities. Oral argument before the Austin Court of Appeals was completed in April 2012. There is no deadline for the court to act. We are unable to predict the outcome of the appeal.

Stipulation Approved by the PUCT

In April 2008, the PUCT entered an order (PUCT Docket No. 34077), which became final in June 2008, approving the terms of a stipulation relating to a filing in 2007 by us and Texas Holdings with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. Among other things, the stipulation required us to file a rate review no later than July 1, 2008 based on a test year ended December 31, 2007, which we filed in June 2008. The PUCT issued a final order with respect to the rate review in August 2009. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200^th District Court of Travis County, Texas (District Court). A hearing on the appeal was held in June 2010, and the District Court affirmed the PUCT order in its entirety. Nucor Steel appealed that ruling to the Austin Court of Appeals in July 2010. In March 2012, the Austin Court of Appeals affirmed the District Court’s ruling, which is now final.

In addition to commitments we made in our filings in the PUCT review, the stipulation included the following provisions, among others:

• We provided a one-time $72 million refund to our REP customers in the September 2008 billing cycle. The refund was in the form of a credit on distribution fee billings. The liability for the refund was previously recorded as part of purchase accounting.

• Cash distributions to our members were limited through December 31, 2012, to an amount not to exceed our net income (determined in accordance with US GAAP, subject to certain defined adjustments) for the period beginning October 11, 2007 and ending December 31, 2012, and continue to be limited by an agreement that our regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity (see Note 8).

• We committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. This spending did not include the capital spending on CREZ facilities. We satisfied this spending commitment in 2012.

• We committed to an additional $100 million in spending over the five-year period ending December 31, 2012 on demand-side management or other energy efficiency initiatives. These additional expenditures will not be recoverable in rates, and this amount was recorded as a regulatory liability as part of purchase accounting and consistent with accounting standards related to the effect of certain types of regulation. We satisfied this spending commitment in 2012.

46

• If our credit rating is below investment grade with two or more rating agencies, TCEH will post a letter of credit in an amount of $170 million to secure TXU Energy’s payment obligations to us.

• We agreed not to request recovery of goodwill or any future impairment of the goodwill in our rates.

3. INCOME TAXES

The components of our reported provision (benefit) in lieu of income taxes are as follows:

	Year Ended December 31,
	2012			2011			2010
Reported in operating expenses:
Current:
US federal	$	23		$	(55	)	$	(6	)
State		21			21			21
Deferred:
US federal		200			248			183
State		—			—			—
Amortization of investment tax credits		(4	)		(5	)		(5	)
Total		240			209			193
Reported in other income and deductions:
Current:
US federal		(14	)		9			11
State		—			1			1
Deferred federal		8			10			10
Total		(6	)		20			22
Total provision in lieu of income taxes	$	234		$	229		$	215

Reconciliation of provision in lieu of income taxes computed at the US federal statutory rate to provision in lieu of income taxes:

	Year Ended December 31,
	2012			2011			2010
Income before provision in lieu of income taxes	$	583		$	596		$	567
Provision in lieu of income taxes at the US federal statutory rate of 35%	$	204		$	209		$	198
Amortization of investment tax credits – net of deferred tax effect		(4	)		(5	)		(5	)
Amortization (under regulatory accounting) of statutory tax rate changes		(3	)		(3	)		(3	)
Amortization of Medicare subsidy regulatory asset		14			—			—
Texas margin tax, net of federal tax benefit		14			14			13
Medicare subsidy		—			—			(1	)
Nondeductible losses (gains) on benefit plan investments		(2	)		(1	)		(1	)
Other, including audit settlements		11			15			14
Reported provision in lieu of income taxes	$	234		$	229		$	215
Effective rate		40.1	%		38.4	%		37.9	%

The net amounts of $2.180 billion and $2.018 billion reported in the balance sheets at December 31, 2012 and 2011, respectively, as liability in lieu of deferred income taxes include amounts previously recorded as net deferred tax liabilities. Upon the sale of equity interests to Texas Transmission and Investment LLC in 2008, we became a partnership for US federal income tax purposes, and the temporary differences that gave rise to the deferred taxes will, over time, become taxable to the equity holders. Under a tax sharing agreement among us and our equity holders (see Note 1), we make payments to the equity holders for income taxes as the partnership earnings become taxable to the equity holders. Accordingly, as the temporary differences become taxable, we will pay the equity holders. In the unlikely event such amounts are not paid under the tax sharing agreement, it is probable that they would be reimbursed to rate payers.

At December 31, 2012 and 2011, we had $52 million and $49 million of alternative minimum tax (AMT) credit carryforwards, respectively, available to offset future tax sharing payments. The AMT credit carryforwards have no expiration date. At December 31, 2012, we had net operating loss (NOL) carryforwards for federal income tax purposes of $271 million that expire between 2028 and 2032. The NOL carryforwards can be used to offset future taxable income. We expect to use all of our NOL carryforwards prior to their expiration date.

47

Accounting For Uncertainty in Income Taxes

Prior to November 2008, we were a member of the EFH Corp. consolidated tax group. Effective with the November 2008 sale of equity interests to Texas Transmission and Investment LLC, we became a partnership for US federal income tax purposes. EFH Corp. and its subsidiaries file or have filed income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of EFH Corp. and its subsidiaries’ income tax returns for the years ending prior to January 1, 2007 are complete, but the tax years 1997 through 2006 remain in appeals with the IRS. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2002. Subsequent to November 2008, we are not a member of the EFH Corp. consolidated tax group and assess our liability for uncertain tax positions in our partnership returns.

The IRS audit for the years 2003 through 2006 was concluded in June 2011. A number of proposed adjustments are in appeals with the IRS. The results of the audit did not affect management’s assessment of issues for purposes of determining the liability for uncertain tax positions.

We have been advised by EFH Corp. that the conclusion of all issues contested from the 1997 through 2002 IRS audit, including Joint Committee review, could occur during the first quarter of 2013. Upon such conclusion, we would expect to further reduce the liability for uncertain tax positions by approximately $29 million with a cash payment to EFH Corp. as required under the tax sharing agreement. Other than these items, we do not expect the total amount of liabilities recorded related to uncertain tax positions will change significantly in the next 12 months.

The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in our consolidated balance sheet, during the years ended December 31, 2012, 2011 and 2010:

	2012		2011		2010
Balance at January 1, excluding interest and penalties	$	126	$	82	$	71
Additions based on tax positions related to prior years		18		44		31
Reductions based on tax positions related to prior years		—		—		(20	)
Balance at December 31, excluding interest and penalties	$	144	$	126	$	82

Of the balances at December 31, 2012 and 2011, $133 million and $115 million, respectively, represent tax positions for which the uncertainty relates to the timing of recognition for tax purposes. The disallowance of such positions would not affect the effective tax rate, but would accelerate the payment of cash under the tax sharing agreement to an earlier period.

Noncurrent liabilities included a total of $25 million and $21 million in accrued interest at December 31, 2012 and 2011, respectively. Amounts recorded related to interest and penalties totaled an expense of $3 million and $2 million in the years ended December 31, 2012 and 2011, respectively, and a benefit of $1 million in the year ended December 31, 2010, as a result of reversals of previously accrued amounts (all amounts after tax). The federal income tax benefit on the interest accrued on uncertain tax positions is recorded as liability in lieu of deferred income taxes.

With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should EFH Corp. or we sustain such positions on income tax returns previously filed, our liabilities recorded would be reduced by $11 million, resulting in increased net income and a favorable impact on the effective tax rate.

48

4. 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. Regulatory liabilities at December 31, 2011 have been restated to remove the $225 million regulatory liability for nuclear plant decommissioning (see Note 11). Amounts not earning a return through rate regulation are noted.

	Remaining Rate Recovery/Amortization	Carrying Amount At
	Period at December 31, 2012	December 31, 2012		December 31, 2011
Regulatory assets:
Generation-related regulatory assets securitized by transition bonds (a)(e)	4 years	$	409	$	531
Employee retirement costs	7 years		87		103
Employee retirement costs to be reviewed (b)(c)	To be determined		186		74
Employee retirement liability (a)(c)(d)	To be determined		738		707
Self-insurance reserve (primarily storm recovery costs) — net	7 years		190		221
Self-insurance reserve to be reviewed (b)(c)	To be determined		128		71
Securities reacquisition costs (pre-industry restructure)	5 years		41		48
Securities reacquisition costs (post-industry restructure) — net	Terms of related debt		22		2
Recoverable amounts in lieu of deferred income taxes — net	Life of related asset or liability		71		104
Rate review expenses (a)	Largely 3 years		6		11
Rate review expenses to be reviewed (b)(c)	To be determined		1		1
Advanced meter customer education costs (c)	7 years		10		9
Deferred conventional meter depreciation	8 years		152		107
Deferred advanced metering system costs	7 years		2		—
Energy efficiency performance bonus (a)	1 year		9		8
Under-recovered wholesale transmission service expense (a)(c)	1 year		40		—
Wholesale transmission settlement costs	Not applicable		—		9
Energy efficiency programs (a)	Not applicable		1		—
Other regulatory assets	Not applicable		—		1
Total regulatory assets			2,093		2,007
Regulatory liabilities (e):
Estimated net removal costs	Life of utility plant		244		115
Investment tax credit and protected excess deferred taxes	Various		28		33
Over-collection of transition bond revenues (a)(e)	4 years		33		37
Deferred advanced metering system revenues	7 years		—		52
Committed spending for demand-side management initiatives (a)	Not applicable		—		25
Over-recovered wholesale transmission service expense (a)(c)	1 year		—		13
Energy efficiency programs (a)	Not applicable		—		2
Total regulatory liabilities			305		277
Net regulatory asset		$	1,788	$	1,730

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

49

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act enacted in March 2010 reduce, effective 2013, the amount of OPEB costs deductible for federal income tax purposes by the amount of the Medicare Part D subsidy received by the EFH Corp. OPEB plans in which we participate. Under income tax accounting rules, deferred tax assets related to accrued OPEB liabilities must be reduced immediately for the future effect of the legislation. Accordingly, in the first quarter of 2010, our assets in lieu of deferred tax assets were reduced by $42 million. All of this amount was recorded as a regulatory asset (before gross-up for liability in lieu of deferred income taxes) as the additional amounts due related to income taxes are being recovered in our rates beginning January 1, 2012.

As a result of purchase accounting, in 2007 the carrying value of certain generation-related regulatory assets securitized by transition bonds, which have been reviewed and approved by the PUCT for recovery but without earning a rate of return, was reduced by $213 million. This amount will be accreted to other income over the recovery period remaining at October 10, 2007 (approximately nine years). In August 2011, the PUCT issued a final order in our rate review filed in January 2011. The rate review included a determination of the recoverability of regulatory assets at June 30, 2010, including the recoverability period of those assets deemed allowable by the PUCT.

In September 2008, the PUCT approved a settlement for us to recover our estimated future investment for advanced metering deployment. We began billing the advanced metering surcharge in the January 2009 billing month cycle. The surcharge is expected to total $1.023 billion over the 11-year recovery period and includes a cost recovery factor of $2.19 per month per residential retail customer and $2.39 to $5.15 per month for non-residential retail customers. We account for the difference between the surcharge billings for advanced metering facilities and the allowed revenues under the surcharge provisions, which are based on expenditures and an allowed return, as a regulatory asset or liability. Such differences arise principally as a result of timing of expenditures. As indicated in the table above, the regulatory asset at December 31, 2012 totaled $2 million and the regulatory liability at December 31, 2011 totaled $52 million.

In accordance with the PUCT’s August 2009 order in our rate review, the remaining net book value and anticipated removal cost of existing conventional meters that are being replaced by advanced meters are being charged to depreciation and amortization expense over an 11-year cost recovery period.

See Note 11 for information regarding nuclear decommissioning cost recovery.

5. BORROWINGS UNDER CREDIT FACILITIES

At December 31, 2012, we had a $2.4 billion secured revolving credit facility (reflecting a May 2012 $400 million commitment increase as discussed below) to be used for working capital and general corporate purposes, issuances of letters of credit and support for any commercial paper issuances. The revolving credit facility expires in October 2016, and we have the option of requesting up to two one-year extensions, with such extensions subject to certain conditions and lender approval. Pursuant to the terms of our revolving credit facility, we requested and received a $400 million increase in commitments under the revolving credit facility effective May 15, 2012. The terms of the revolving credit facility allow us to request an additional increase in our borrowing capacity of $100 million, provided certain conditions are met, including lender approval.

Borrowings under the revolving credit facility are classified as short-term on the balance sheet and are secured equally and ratably with all of our other secured indebtedness by a first priority lien on property we acquired or constructed for the transmission and distribution of electricity. The property is mortgaged under the Deed of Trust.

At 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. At December 31, 2011, we had outstanding borrowings under the revolving credit facility totaling $392 million with an interest rate of 1.40% and outstanding letters of credit totaling $6 million.

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 December 31, 2012, all outstanding borrowings bore interest at LIBOR plus 1.25%. Amounts borrowed under the facility, once repaid, can be borrowed again from time to time.

50

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 December 31, 2012, letters of credit bore interest at 1.25%, and a commitment fee (at a rate of 0.175% per annum) was payable on the unfunded commitments under the facility, each based on our current credit ratings.

Subject to the limitations described below, borrowing capacity available under the credit facility at December 31, 2012 and 2011 was $1.659 billion and $1.602 billion, respectively. Generally, our indentures and revolving credit facility limit the incurrence of other secured indebtedness except for indebtedness secured equally and ratably with the indentures and revolving credit facility and certain permitted exceptions. As described further in Note 6, the Deed of Trust permits us to secure indebtedness (including borrowings under our revolving credit facility) with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the lower of the fair value or cost of certain property additions that could be certified to the Deed of Trust collateral agent. At December 31, 2012, the available borrowing capacity of the revolving credit facility could be fully drawn.

The revolving credit facility contains customary covenants for facilities of this type, restricting, subject to certain exceptions, us and our subsidiaries from, among other things: incurring additional liens; entering into mergers and consolidations; and sales of substantial assets. In addition, the revolving credit facility requires that we maintain a consolidated senior debt-to-capitalization ratio of no greater than 0.65 to 1.00 and observe certain customary reporting requirements and other affirmative covenants. For purposes of the 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 December 31, 2012, we were in compliance with this covenant with a debt-to-capitalization ratio of 0.44 to 1.00 and with all other covenants.

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

51

6. LONG-TERM DEBT

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

	December 31,
	2012			2011
Oncor (a):
6.375% Fixed Senior Notes due May 1, 2012	$	—		$	376
5.950% Fixed Senior Notes due September 1, 2013		—			524
6.375% Fixed Senior Notes due January 15, 2015		500			500
5.000% Fixed Senior Notes due September 30, 2017		324			324
6.800% Fixed Senior Notes due September 1, 2018		550			550
5.750% Fixed Senior Notes due September 30, 2020		126			126
4.100% Fixed Senior Notes due June 1, 2022		400			—
7.000% Fixed Debentures due September 1, 2022		800			800
7.000% Fixed Senior Notes due May 1, 2032		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
7.500% Fixed Senior Notes due September 1, 2038		300			300
5.250% Fixed Senior Notes due September 30, 2040		475			475
4.550% Fixed Senior Notes due December 1, 2041		300			300
5.300% Fixed Senior Notes due June 1, 2042		500			—
Unamortized discount		(35	)		(38	)
Less amounts due currently		—			(376	)
Total Oncor		5,090			4,711
Oncor Electric Delivery Transition Bond Company LLC (b):
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		10			56
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015 (c)		145			145
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		—			63
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		281			290
Unamortized fair value discount related to transition bonds		(1	)		(3	)
Less amounts due currently		(125	)		(118	)
Total Oncor Electric Delivery Transition Bond Company LLC		310			433
Total long-term debt	$	5,400		$	5,144

(a) Secured by first priority lien on certain transmission and distribution assets equally and ratably with all of Oncor’s other secured indebtedness. See “Deed of Trust” below for additional information.

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

(c) Principal payments commence in February 2013.

Debt-Related Activity in 2012

Debt Repayments

Repayments of long-term debt in 2012 totaled $1.018 billion and represented $376 million principal amount of 6.375% senior secured notes paid at the scheduled maturity date of May 1, 2012, the redemption of $524 million principal amount of 5.950% senior secured notes due September 1, 2013 (2013 Notes) as discussed below and $118 million principal amount of transition bonds paid at scheduled maturity dates.

In June 2012, pursuant to the terms of the indenture and officer’s certificate governing the 2013 Notes, we redeemed all of the 2013 Notes. We paid a redemption price equal to 100% of the principal amount of the 2013 Notes plus a make-whole amount of $33 million. For accounting purposes, the make-whole amount has been deferred as a regulatory asset and will be amortized to interest expense until September 1, 2013, the original maturity date of the 2013 Notes (see Note 4).

52

Issuance of New Senior Secured Notes

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

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

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

Deed of Trust

Our secured indebtedness, including the 2022 and 2042 Notes described above and the revolving credit facility described in Note 5, are secured equally and ratably 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. The Deed of Trust permits us to secure indebtedness (including borrowings under our revolving credit facility) with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the lower of the fair value or cost of certain property additions that could be certified to the Deed of Trust collateral agent. At December 31, 2012, the amount of available bond credits was approximately $2.2 billion and the amount of future debt we could secure with property additions, subject to those property additions being certified to the Deed of Trust collateral agent, was $731 million.

Debt-Related Activity in 2011

Debt Repayments

Repayments of long-term debt in 2011 totaled $113 million and represented transition bond principal payments at scheduled maturity dates.

Interest Rate Hedge Transaction

In August 2011, we entered into an interest rate hedge transaction hedging the variability of treasury bond rates used to determine interest rates on an anticipated issuance of senior secured notes (see below for information regarding the debt issuance). The hedges were terminated in November 2011 upon the issuance of the senior secured notes. In 2011, we recognized the $46 million ($29 million after tax) loss related to the fair value of the hedge transaction in other comprehensive income, which is expected to be reclassified into net income over the life of the senior secured notes issued, which mature in 2041.

Issuance of New Senior Secured Notes

In November 2011, we issued $300 million aggregate principal amount of 4.550% senior secured notes maturing in December 2041 (2041 Notes). We used the net proceeds of approximately $297 million from the sale of the notes to repay borrowings under our revolving credit facility, including loans under the revolving credit facility and for general corporate purposes. The notes are secured by the first priority lien described below, and are secured equally and ratably with all of our other secured indebtedness.

53

Interest on the 2041 Notes is payable in cash semiannually in arrears on June 1 and December 1 of each year, beginning on June 1, 2012. 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 2041 Notes were issued in a private placement, and in August 2012 we offered holders of the 2041 Notes the opportunity to exchange their respective 2041 Notes for notes that have terms identical in all material respects to the 2041 Notes (2041 Exchange Notes), except that the 2041 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 2041 Exchange Notes were registered on a Form S-4, which was declared effective in July 2012.

Maturities

Long-term debt maturities at December 31, 2012, are as follows:

Year	Amount
2013	$	125
2014		131
2015		639
2016		41
2017		324
Thereafter		4,301
Unamortized fair value discount		(1	)
Unamortized discount		(35	)
Total	$	5,525

Fair Value of Long-Term Debt

The estimated fair value of our long-term debt (including current maturities) totaled $6.568 billion and $6.705 billion at December 31, 2012 and 2011, respectively, and the carrying amount totaled $5.525 billion and $5.638 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.

7. COMMITMENTS AND CONTINGENCIES

Leases

At December 31, 2012, our future minimum lease payments under operating leases (with initial or remaining noncancelable lease terms in excess of one year) were as follows:

Year	Amount
2013	$	7
2014		5
2015		4
2016		3
2017		1
Thereafter		—
Total future minimum lease payments	$	20

Rent charged to operation and maintenance expense totaled $15 million for each of the years ended December 31, 2012, 2011 and 2010.

54

Capital Expenditures

We and Texas Holdings agreed with major interested parties to the terms of a stipulation that was approved by the PUCT in 2008 as discussed in Note 2. As one of the provisions of this stipulation, we committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. At December 31, 2012, we had satisfied this spending commitment. These expenditures did not include the CREZ facilities.

Efficiency Spending

We are required to annually invest in programs designed to improve customer electricity demand efficiencies to satisfy ongoing regulatory requirements. The 2013 requirement is $62 million.

Guarantees

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

We are the lessee under various operating leases that obligate us to guarantee the residual values of the leased assets. At December 31, 2012, both the aggregate maximum amount of residual values guaranteed and the estimated residual recoveries totaled $7 million. These leased assets consist primarily of vehicles used in distribution activities. The average life of the residual value guarantees under the lease portfolio is approximately 1.7 years.

For the purpose of obtaining greater access to materials, we have guaranteed the repayment of borrowings under a nonaffiliated party’s $7 million credit facility maturing on March 31, 2013. The nonaffiliated party’s borrowings under the credit facility are limited to inventory produced solely to satisfy the terms of a contract with us. We would be entitled to the related inventory upon repayment of the credit facility (or payment to the nonaffiliated party). At December 31, 2012, the nonaffiliated party had borrowings of $4 million under the facility.

Legal/Regulatory Proceedings

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

The first issue is the wholesale transmission transition mechanism for the period of September 1999 through December 1999. The disputed issue is whether the PUCT should have allowed the transition mechanism to continue for the last four months of 1999. The appealing parties (Texas Municipal Power Agency, the City of Denton, the City of Garland and GEUS (formerly known as Greenville Electric Utility System)) argued that the transition mechanism was not authorized in the September 1, 1999 100% postage stamp pricing legislation. Our transmission deficit position was mitigated by approximately $8 million in the last four months of 1999 through the transition mechanism. In October 2011, certain parties filed a proposed settlement of this issue, subject to PUCT approval, in which we would pay approximately $9 million including interest through October 9, 2003. The PUCT approved the settlement in January 2012. No appeals were filed prior to the appeals deadline, and the PUCT order became final in February 2012. We made the payment in accordance with the settlement in February 2012. In November 2012, the PUCT gave its final approval of the TCRF application allowing us recovery of the $9 million settlement payment through TCRF billings during the period of September 2012 through February 2013.

The second issue is the San Antonio City Public Service Board’s (CPSB) claim that the PUCT did not have the authority to reduce CPSB’s requested TCOS revenue requirement. CPSB’s initial TCOS rate was in effect from 1997 through 2000. Since the period of January 1997 through August 1999 is incorporated in the joint settlement, CPSB’s remaining claim is for the period of September 1999 through December 2000. In January 2011, CPSB made a filing with the PUCT (PUCT Docket No. 39068), seeking an additional $22 million of TCOS revenue, including interest, for the 16-month period, of which we would be responsible for approximately $11 million. In late 2011, we intervened in the proceeding and, along with several other parties, filed motions to dismiss CPSB’s request. In January 2012, the PUCT upheld an administrative law judge’s earlier decision to dismiss CPSB’s request. No appeals were filed prior to the appeals deadline, and the PUCT order became final in February 2012.

55

We are involved in other 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.

Labor Contracts

Certain of our employees are represented by a labor union and covered by a collective bargaining agreement with an expiration date of October 25, 2013.

Environmental Contingencies

We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. We are in compliance with all current laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulations is not determinable. The costs to comply with environmental regulations can be significantly affected by the following external events or conditions:

• changes to existing state or federal regulation by governmental authorities having jurisdiction over control of toxic substances and hazardous and solid wastes, and other environmental matters, and

• the identification of additional sites requiring clean-up or the filing of other complaints in which we may be asserted to be a potential responsible party.

8. MEMBERSHIP INTERESTS

On February 13, 2013, our board of directors declared a cash distribution of $50 million, which was paid to our members on February 15, 2013.

During 2012, our board of directors declared, and we paid, the following cash distributions to our members:

Declaration Date	Payment Date	Amount
October 24, 2012	October 30, 2012	$	70
July 25, 2012	July 31, 2012	$	50
April 25, 2012	May 1, 2012	$	60
February 14, 2012	February 21, 2012	$	45

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

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

Until December 31, 2012, distributions were limited to our cumulative net income and regulatory capital structure restrictions. Effective January 1, 2013, distributions are limited only to the extent we maintain a required regulatory capital structure as discussed below.

56

Distributions continue to be 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 December 31, 2012, our regulatory capitalization ratio was 58.8% debt and 41.2% 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 December 31, 2012, $167 million was available for distribution to our members under the capital structure restriction.

For the period beginning October 11, 2007 and ending December 31, 2012, our cash distributions (other than distributions of the proceeds of any issuance of limited liability company units) were limited by the Limited Liability Company Agreement and a stipulation agreement with the PUCT to an amount not to exceed our cumulative net income determined in accordance with US GAAP, as adjusted by applicable orders of the PUCT. Adjustments consisted of the removal of noncash impacts of purchase accounting and deducting two specific cash commitments. The noncash impacts consisted of removing the effect of an $860 million goodwill impairment charge in 2008 and the cumulative amount of net accretion of fair value adjustments. The two specific cash commitments were the $72 million ($46 million after tax) one-time refund to customers in September 2008 and the funds spent as part of the $100 million commitment for additional energy efficiency initiatives that was completed in 2012. See Note 2 for additional information regarding the two cash commitments. At December 31, 2012, $420 million of membership interests was available for distribution under the cumulative net income restriction. However, as discussed above, this restriction is no longer applicable.

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

Regulatory Recovery of Pension and OPEB Costs

PURA provides for our recovery of pension and OPEB costs applicable to services of our active and retired employees, as well as services of other EFH Corp. active and retired employees prior to the deregulation and disaggregation of EFH Corp.’s electric utility businesses effective January 1, 2002 (recoverable service). Accordingly, we entered into an agreement with EFH Corp. whereby we assumed responsibility for applicable pension and OPEB costs related to those personnel’s recoverable service.

We are authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings related to recoverable service. Amounts deferred are ultimately subject to regulatory approval. At December 31, 2012 and 2011, we had recorded regulatory assets totaling $1.011 billion and $884 million, respectively, related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.

In a 2012 agreement described below, we assumed primary responsibility for retirement costs related to certain non-recoverable service. Any retirement costs associated with non-recoverable service is not recoverable through rates.

Pension Plan

We participate in two defined benefit pension plans. The EFH Retirement Plan and Oncor Retirement Plan are qualified pension plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and are subject to the provisions of ERISA. All benefits are funded by the participating employers. These pension plans provide benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.

All eligible employees hired after January 1, 2001 participate under the Cash Balance Formula. Certain employees, who, prior to January 1, 2002, participated under the Traditional Retirement Plan Formula, continue their participation under that formula. It is the participating employers’ policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.

57

In August 2012, EFH Corp. approved certain amendments to the EFH Retirement Plan. These actions were completed in the fourth quarter of 2012, and the amendments resulted in:

• the splitting off of assets and liabilities under the plan associated with our employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses) to a new qualified pension plan that provides benefits identical to those provided under the EFH Retirement Plan, for which we assumed sponsorship from EFH Corp. effective January 1, 2013 (Oncor Retirement Plan);

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

• the splitting off of assets and liabilities under the plan associated with all other plan participants (active nonunion employees of EFH Corp.’s competitive businesses) to a terminating plan, freezing benefits and vesting all accrued plan benefits for these participants, and

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

As a result of these actions and in connection with assuming sponsorship of the Oncor Retirement Plan, we entered into an agreement with EFH Corp. to assume primary responsibility for benefits of certain participants for whom EFH Corp. bore primary funding responsibility (a closed group of retired and terminated vested plan participants not related to our regulated utility business) at December 31, 2012. As we received a corresponding amount of assets with the assumed liabilities, execution of the agreement did not have a material impact on our reported results of operations or financial condition. In the fourth quarter of 2012, EFH Corp. made cash contributions totaling $259 million to settle the terminating plan obligations and fully fund its obligations under the Oncor Retirement Plan.

We also have supplemental pension plans for certain employees whose retirement benefits cannot be fully earned under the qualified retirement plan, the information for which is included below.

In July 2012, the US Congress enacted legislation that includes, among other things, pension funding stabilization provisions. These provisions are expected to reduce required minimum pension plan contributions in the near term, but have no impact on long-term funding levels absent a sustained low interest rate environment.

OPEB Plan

We 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 (OPEB Plan). For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service.

Pension and OPEB Costs Recognized as Expense

The pension and OPEB amounts provided herein include our allocated amounts related to EFH Corp.’s plans based on actuarial computations and reflect our employee and retiree demographics as described above. We recognized the following net pension and OPEB costs as expense:

	Year Ended December 31,
	2012			2011			2010
Pension cost	$	179		$	95		$	67
OPEB cost		27			74			63
Total benefit cost		206			169			130
Less amounts deferred as a regulatory asset or property or property		(169	)		(132	)		(93	)
Net amounts recognized as expense	$	37		$	37		$	37

58

We and EFH Corp. use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating our pension costs. We and EFH Corp. include the realized and unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.

We and EFH Corp. use the fair value method to determine the market-related value of the assets held in the trust for purposes of calculating our OPEB cost.

Detailed Information Regarding Pension and OPEB Benefits

The following pension and OPEB information is based on December 31, 2012, 2011 and 2010 measurement dates:

	Pension Plans									OPEB Plan
	Year Ended December 31,									Year Ended December 31,
	2012			2011			2010			2012			2011			2010
Assumptions Used to Determine Net Periodic Pension and Benefit Cost:
Discount rate (a)		5.00	%		5.50	%		5.90	%		4.95	%		5.55	%		5.90	%
Expected return on plan assets		7.40	%		7.70	%		8.00	%		6.80	%		7.10	%		7.60	%
Rate of compensation increase		3.81	%		3.74	%		3.71	%		—			—			—
Components of Net Pension and Benefit Cost:
Service cost	$	23		$	20		$	19		$	5		$	7		$	6
Interest cost		106			110			106			39			54			52
Expected return on assets		(109	)		(99	)		(97	)		(12	)		(14	)		(15	)
Amortization of net transition obligation		—			—			—			1			1			1
Amortization of prior service cost (credit)		—			1			1			(20	)		(1	)		(1	)
Amortization of net loss		78			63			38			14			27			20
Settlement charges		81			—			—			—			—			—
Net periodic pension and benefit cost		179			95			67			27			74			63
Other Changes in Plan Assets and Benefit Obligations Recognized as Regulatory Assets or in Other Comprehensive Income :
Net loss (gain)		110			106			124			83			(91	)		75
Prior service cost (credit)		—			—			—			—			(127	)		1
Amortization of net loss		(78	)		(63	)		(38	)		(14	)		(27	)		(20	)
Amortization of transition obligation (asset)		—			—			—			(1	)		(1	)		(1	)
Amortization of prior service (cost) credit		—			(1	)		(1	)		20			1			—
Settlement charges		(81	)		—			—			—			—			—
Curtailment		(5	)		—			—			—			—			—
Total recognized as regulatory assets or other comprehensive income		(54	)		42			85			88			(245	)		55
Total recognized in net periodic pension and benefit costs and as regulatory assets or other comprehensive income	$	125		$	137		$	152		$	115		$	(171	)	$	118

(a) As a result of the amendments discussed above, the discount rate reflected in net pension costs for January through July 2012 was 5.00%, for August through September 2012 was 4.15% and for October through December 2012 was 4.20%.

	Pension Plans									OPEB Plan
	Year Ended December 31,									Year Ended December 31,
	2012			2011			2010			2012			2011			2010
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate		4.10	%		5.00	%		5.50	%		4.10	%		4.95	%		5.55	%
Rate of compensation increase		3.94	%		3.81	%		3.74	%		—			—			—

59

	Pension Plans						OPEB Plan
	Year Ended December 31,						Year Ended December 31,
	2012			2011			2012			2011
Change in Projected Benefit Obligation:
Projected benefit obligation at beginning of year	$	2,215		$	2,052		$	809		$	1,004
Service cost		23			20			5			7
Interest cost		106			110			39			54
Participant contributions		—			—			15			14
Medicare Part D reimbursement		—			—			3			5
Plan amendments		—			—			—			(127	)
Settlement		(268	)		—			—			—
Curtailment		(5	)		—			—			—
Assumption of liabilities		860			—			6			—
Actuarial (gain) loss		198			119			94			(97	)
Benefits paid		(91	)		(86	)		(58	)		(51	)
Projected benefit obligation at end of year	$	3,038		$	2,215		$	913		$	809
Accumulated benefit obligation at end of year	$	2,908		$	2,063		$	—		$	—
Change in Plan Assets:
Fair value of assets at beginning of year	$	1,542		$	1,341		$	197		$	208
Actual return (loss) on assets		199			112			25			8
Employer contributions		93			175			11			18
Settlement		(268	)		—			—			—
Assets related to assumed liabilities		852			—			—			—
Participant contributions		—			—			15			14
Benefits paid		(91	)		(86	)		(58	)		(51	)
Fair value of assets at end of year	$	2,327		$	1,542		$	190		$	197
Funded Status:
Projected benefit obligation at end of year	$	(3,038	)	$	(2,215	)	$	(913	)	$	(809	)
Fair value of assets at end of year		2,327			1,542			190			197
Funded status at end of year	$	(711	)	$	(673	)	$	(723	)	$	(612	)

	Pension Plans						OPEB Plan
	Year Ended December 31,						Year Ended December 31,
	2012			2011			2012			2011
Amounts Recognized in the Balance Sheet Consist of:
Liabilities:
Other current liabilities	$	(3	)	$	(3	)	$	—		$	—
Other noncurrent liabilities		(708	)		(670	)		(723	)		(612	)
Net liability recognized	$	(711	)	$	(673	)	$	(723	)	$	(612	)
Regulatory assets:
Net loss	$	602		$	659		$	247		$	178
Prior service cost (credit)		—			—			(111	)		(131	)
Net transition obligation		—			—			—			1
Net regulatory asset recognized	$	602		$	659		$	136		$	48
Accumulated other comprehensive net loss	$	3		$	—		$	1		$	—

60

The following tables provide information regarding the assumed health care cost trend rates.

	Year Ended December 31,
	2012			2011
Assumed Health Care Cost Trend Rates – Not Medicare Eligible:
Health care cost trend rate assumed for next year		8.50	%		9.00	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2022			2022
Assumed Health Care Cost Trend Rates – Medicare Eligible:
Health care cost trend rate assumed for next year		7.50	%		8.00	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2022			2022

	1-Percentage Point Increase		1-Percentage Point Decrease
Sensitivity Analysis of Assumed Health Care Cost Trend Rates:
Effect on accumulated postretirement obligation	$	115	$	(99	)
Effect on postretirement benefits cost		6		(5	)

The following table provides information regarding pension plans with projected benefit obligations (PBO) and accumulated benefit obligations (ABO) in excess of the fair value of plan assets.

	At December 31,
	2012		2011
Pension Plans with PBO and ABO in Excess of Plan Assets :
Projected benefit obligations	$	3,038	$	2,215
Accumulated benefit obligations		2,908		2,063
Plan assets		2,327		1,542

Pension Plans and OPEB Plan Investment Strategy and Asset Allocations

Our investment objective for the retirement plans is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Equity securities are held to achieve returns in excess of passive indexes by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging international markets. Fixed income securities include primarily corporate bonds from a diversified range of companies, US Treasuries and agency securities and money market instruments. Our investment strategy for fixed income investments is to maintain a high grade portfolio of securities, which assists us in managing the volatility and magnitude of plan contributions and expense while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses.

The retirement plans’ investments are managed in two pools: one associated with the recoverable service portion of plan obligations related to our regulated utility business, and the other associated with plan obligations for the closed group of retired and terminated plan participants not related to our regulated utility business that we assumed from EFH Corp. in connection with our sponsorship of the Oncor Plan¸ as discussed above. The recoverable service portion is invested in a broadly diversified portfolio of equity and fixed income securities. The nonrecoverable service portion is invested in fixed income securities intended to fully hedge the obligations, within practical limitations.

61

The target asset allocation ranges of pension plan investments by asset category are as follows:

	Target Allocation Ranges
	Recoverable	Nonrecoverable
Asset Category
US equities	24%-31%		—
International equities	20%-25%		—
Fixed income	45%-57%		100	%

Our investment objective for the OPEB Plan primarily follows the objectives of the pension plans discussed above, while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses. The actual amounts at December 31, 2012 provided below are consistent with the asset allocation targets.

Fair Value Measurement of Pension Plan Assets

At December 31, 2012 and 2011, pension plan assets measured at fair value on a recurring basis consisted of the following:

	At December 31, 2012								At December 31, 2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Category
Interest-bearing cash	$	—	$	134	$	—	$	134	$	—	$	60	$	—	$	60
Equity securities:
US		206		95		—		301		263		54		—		317
International		280		7		—		287		152		50		—		202
Fixed income securities:
Corporate bonds (a)		—		1,319		—		1,319		—		859		—		859
US Treasuries		—		206		—		206		—		34		—		34
Other (b)		—		73		—		73		—		61		—		61
Preferred securities		—		—		7		7		—		—		9		9
Total assets	$	486	$	1,834	$	7	$	2,327	$	415	$	1,118	$	9	$	1,542

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s.

(b) Other consists primarily of US agency securities.

There was no significant change in the fair value of Level 3 assets in the periods presented.

Fair Value Measurement of OPEB Plan Assets

At December 31, 2012 and 2011, OPEB Plan assets measured at fair value on a recurring basis consisted of the following:

	At December 31, 2012								At December 31, 2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Category
Interest-bearing cash	$	—	$	10	$	—	$	10	$	—	$	10	$	—	$	10
Equity securities:
US		49		6		—		55		52		3		—		55
International		31		—		—		31		23		3		—		26
Fixed income securities:
Corporate bonds (a)		—		42		—		42		—		54		—		54
US Treasuries		—		4		—		4		—		2		—		2
Other (b)		45		3		—		48		46		3		—		49
Preferred securities		—		—		—		—		—		—		1		1
Total assets	$	125	$	65	$	—	$	190	$	121	$	75	$	1	$	197

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s.

(b) Other consists primarily of US agency securities.

There was no significant change in the fair value of Level 3 assets in the periods presented.

62

Expected Long-Term Rate of Return on Assets Assumption

The retirement plans’ strategic asset allocation is determined in conjunction with the plans’ advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The modeling incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.

Pension Plans				OPEB Plan
Asset Class	Expected Long-Term Rate of Return			Plan Type	Expected  Long-Term Returns
US equity securities		7.7	%	401(h) accounts		7.4	%
International equity securities		9.3	%	Life Insurance VEBA		6.4	%
Fixed income securities		4.1	%	Union VEBA		6.4	%
Other		0.6	%	Non-Union VEBA		3.2	%
Weighted average (a)		7.4	%	Weighted average		6.7	%

(a) The 2013 expected long-term rate of return for the nonregulated portion of the Oncor Retirement Plan is 4.10%.

Significant Concentrations of Risk

The plans’ investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to participating employers. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.

Assumed Discount Rate

We and EFH Corp. selected the assumed discount rate using the Aon Hewitt AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2012 consisted of 332 corporate bonds with an average rating of AA using Moody’s, S&P and Fitch ratings.

Amortization in 2013

In 2013, amortization of the net actuarial loss and prior service cost for the defined benefit pension plans from regulatory assets into net periodic benefit cost is expected to be $70 million and less than $1 million, respectively. Amortization of the net actuarial loss and prior service credit for the OPEB Plan from regulatory assets into net periodic benefit cost is expected to be $26 million and a $20 million credit, respectively.

Pension and OPEB Plan Cash Contributions

Our contributions to the benefit plans were as follows:

	Year Ended December 31,
	2012		2011		2010
Pension plans contributions	$	93	$	175	$	43
OPEB Plan contributions		11		18		18
Total contributions	$	104	$	193	$	61

63

Our funding for the pension plans (based on the funded status at December 31, 2012) and the OPEB Plan is expected to total $10 million and $12 million, respectively in 2013 and approximately $395 million and $115 million, respectively, for the 2013 to 2017 period.

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:

	2013		2014		2015		2016		2017		2018-22
Pension benefits	$	153	$	157	$	158	$	164	$	168	$	910
OPEB	$	43	$	45	$	48	$	51	$	53	$	291

Thrift Plan

Our employees may participate in a qualified savings plan, the EFH Corp. Thrift Plan (Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax applicable payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the Cash Balance Formula of the Oncor Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the Traditional Retirement Plan Formula of the Oncor Retirement Plan. Employer matching contributions are made in cash and may be allocated by participants to any of the plan’s investment options. Our contributions to the Thrift Plan totaled $12 million, $12 million and $11 million for the years ended December 31, 2012, 2011 and 2010, respectively.

10.STOCK-BASED COMPENSATION

In 2008, we established the SARs Plan under which certain of our executive officers and key employees may be granted stock appreciation rights payable in cash, or in some circumstances, Oncor membership interests. In February 2009, we established the Oncor Electric Delivery Company LLC Director Stock Appreciation Rights Plan (the Director SARs Plan) under which certain non-employee members of our board of directors and other persons having a relationship with us may be granted SARs payable in cash, or in some circumstances, Oncor membership interests. SARs under the SARs Plan and the Director SARs Plan are generally payable in cash based on the fair market value of the SAR on the date of exercise. There were no SARs under either plan eligible for exercise at December 31, 2011.

During the year ended December 31, 2012, we granted no SARS under the SARs Plan. In November 2012, we accepted the early exercise of all outstanding SARs (both vested and unvested, totaling 14,322,219 SARs under the SARs Plan and 55,000 SARs under the Director SARs Plan) issued to date pursuant to both SARs Plans. The early exercise was permitted by our board of directors pursuant to the provision of the SARs Plan that permits the board to accelerate the vesting and exercisability of SARs. The early exercise of SARs entitled each participant in the SARs Plan to: (1) an exercise payment (Exercise Payment) equal to the number of SARs exercised multiplied by the difference between $14.54 and the base price of the SARs (as stated in the award letter for each SARs grant); and (2) the accrual of interest on all dividends declared to date with respect to the SARs, but no further dividend accruals. Additionally, each current executive officer agreed to defer payment of a portion of his/her Exercise Payment until the earlier of November 7, 2016 or the occurrence of an event triggering SAR exercisability pursuant to Section 5(c)(ii) of the SARs Plan. These deferred payments totaled approximately $6 million in the aggregate. As a result of the early exercise, in 2012 we paid an aggregate of approximately $64 million related to Exercise Payments ($57 million charged to expense), and began accruing interest on approximately $18 million in aggregate dividends. As a result of the early exercise, no SARs are currently outstanding under either the SARs Plan or the Director SARs Plan.

Under both SARs plans, dividends that are paid in respect of Oncor membership interests while the SARs were outstanding were credited to the SARs holder’s account as if the SARs were units, payable upon the earliest to occur of death, disability, separation from service, unforeseeable emergency, a change in control, or the exercise of the SARs. As a result, in 2012 we recorded compensation expense of approximately $6 million relating to dividend accruals through November 2012. For accounting purposes, the liability is discounted based on an employee’s or director’s expected retirement date.

64

11. RELATED-PARTY TRANSACTIONS

The following represent our significant related-party transactions:

• We record revenue from TCEH, principally for electricity delivery fees, which totaled $1.0 billion for each of the years ended December 31, 2012 and 2011 and $1.1 billion for the year December 31, 2010. The fees are based on rates regulated by the PUCT that apply to all REPs. These revenues included approximately $2 million for each of the years ended December 31, 2012, 2011 and 2010 pursuant to a transformer maintenance agreement with TCEH. The balance sheets at December 31, 2012 and 2011 reflect receivables from affiliates totaling $53 million and $138 million, respectively, primarily consisting of trade receivables from TCEH related to these electricity delivery fees.

• We recognized interest income from TCEH under an agreement related to our generation-related regulatory assets, which have been securitized through the issuance of transition bonds by Bondco. The interest income, which served to offset our interest expense on the transition bonds, totaled $16 million, $32 million and $37 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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

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

• EFH Corp. subsidiaries charge us for certain administrative services. We also charge each other for shared facilities at cost. These net costs, which are primarily reported in operation and maintenance expenses, totaled $35 million, $38 million and $40 million for the years ended December 31, 2012, 2011 and 2010, 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 $16 million, $17 million and $16 million for the years ended December 31, 2012, 2011 and 2010, respectively. 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.

Prior to 2012, we reflected the difference between the trust fund assets and the decommissioning liability (both reported on TCEH’s balance sheet) in our financial statements as a regulatory liability or asset with an offsetting receivable from or payable to TCEH (the beneficiary of the nuclear decommissioning trust). However, amounts associated with nuclear decommissioning activities were not included in our net income or accumulated other comprehensive income. During 2012, we determined that due to our role as the collection agent of funds, the recording of a regulatory liability or asset in our financial statements was an error. As such, the balance sheet at December 31, 2011 has been restated to remove both the $225 million receivable from TCEH related to the Comanche Peak nuclear plant decommissioning and the associated regulatory liability of $225 million. This restatement reduced the receivable from TCEH to zero and increased regulatory assets by $225 million. This error did not have a material impact on our reported results of operations, cash flows or financial condition.

65

• We have a 19.5% limited partnership interest, with a carrying value of less than $1 million at December 31, 2012 and 2011, in an EFH Corp. subsidiary holding principally software-related assets. Equity losses related to this interest are reported in other deductions and totaled less than $1 million for each of the years ended December 31, 2012 and 2011, and $2 million for the year ended December 31, 2010. These losses primarily represent amortization of software assets held by the subsidiary.

• We are not a member of EFH Corp.’s consolidated tax group, but EFH Corp.’s consolidated federal income tax return includes EFH Corp.’s portion of our results due to EFH Corp.’s equity ownership in us. Under the terms of a tax sharing agreement among us, Oncor Holdings, Texas Transmission, Investment LLC and EFH Corp., we are generally obligated to make payments to Texas Transmission, Investment LLC and EFH Corp., pro rata in accordance with their respective membership interests, in an aggregate amount that is substantially equal to the amount of federal income taxes that we would have been required to pay if we were filing our own corporate income tax return. EFH Corp. also includes our results in its consolidated Texas state margin tax 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 under “Income Taxes.” Under the “in lieu of” tax concept, all in lieu of tax assets and tax liabilities represent amounts that will eventually be settled with our members. At December 31, 2012, we had a current state income tax payable to EFH Corp. under the agreement of $22 million, which was reported as a net current tax payable to members. At December 31, 2011, we had federal income tax-related amounts receivable from members under the agreement totaling $27 million ($22 million from EFH Corp. and $5 million from Texas Transmission and Investment LLC) and a current state income tax payable to EFH Corp. of $22 million, which was reported as a net current tax receivable from members of $5 million. We have recorded liabilities in lieu of deferred income taxes of $2.180 billion and $2.018 billion and for uncertain tax positions of $169 million and $147 million as of December 31, 2012 and 2011, respectively. On a net basis, we received income tax refunds from members of $2 million (including $5 million in refunds from members other than EFH Corp. and $2 million paid to EFH Corp.) in the year ended December 31, 2012. We received income tax refunds from members totaling $114 million (including $25 million in federal income tax-related refunds from members other than EFH Corp.) in the year ended December 31, 2011.

• Our PUCT-approved tariffs include requirements to assure adequate credit worthiness of any REP to support the REP’s obligation to collect transition bond-related charges on behalf of Bondco. Under these tariffs, as a result of TCEH’s credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, at December 31, 2012 and 2011, TCEH had posted letters of credit in the amount of $11 million and $12 million, respectively, for our benefit.

• In connection with assuming sponsorship of the Oncor Retirement Plan, we entered into an agreement with EFH Corp. to assume primary responsibility for retirement benefits of a closed group of retired and terminated vested retirement plan participants not related to our regulated utility business. As the Oncor Retirement Plan received an amount of plan assets equal to the liabilities we assumed for those participants, execution of the agreement did not have a material impact on our reported results of operations or financial condition. See Note 9 for further information regarding funding for the pension plans.

• 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 3, 8 and 9 for information regarding the tax sharing agreement, distributions to members and the allocation of EFH Corp.’s pension and OPEB costs, respectively.

66

12. SUPPLEMENTARY FINANCIAL INFORMATION

Variable Interest Entities

We are the primary beneficiary and consolidate a wholly-owned VIE, Bondco, which was organized for the limited purpose of issuing specific transition bonds and purchasing and owning transition property acquired from us that is pledged as collateral to secure the bonds. We act as the servicer for this entity to collect transition charges authorized by the PUCT. These funds are remitted to the trustee and used for interest and principal payments on the transition bonds and related costs.

The material assets and liabilities of Bondco are presented separately on the face of our Consolidated Balance Sheet because the assets are restricted and can only be used to settle the obligations of Bondco, and Bondco’s creditors do not have recourse to our general credit or assets.

Our maximum exposure does not exceed our equity investment in Bondco, which was $16 million at both December 31, 2012 and 2011. We did not provide any financial support to Bondco during the years ended December 31, 2012 and 2011.

Major Customers

Revenues from TCEH represented 29%, 33% and 36% of total operating revenues for the years ended December 31, 2012, 2011 and 2010, respectively. Revenues from REP subsidiaries of a nonaffiliated entity collectively represented 15% of total operating revenues for each of the years ended December 31, 2012, 2011 and 2010. No other customer represented 10% or more of total operating revenues in the years ended December 31, 2012, 2011 or 2010.

Other Income and Deductions

	Year Ended December 31,
	2012		2011		2010
Other income:
Accretion of adjustment (discount) to regulatory assets due to purchase accounting	$	23	$	29	$	34
Net gain on sale of other properties and investments		3		1		2
Total other income	$	26	$	30	$	36
Other deductions:
Professional fees	$	3	$	4	$	4
Equity losses in unconsolidated affiliate (Note 11)		—		—		2
SARs early exercise (Note 10)		57		—		—
Other		4		5		2
Total other deductions	$	64	$	9	$	8

Interest Expense and Related Charges

	Year Ended December 31,
	2012			2011			2010
Interest expense	$	366		$	359		$	342
Amortization of fair value debt discounts resulting from purchase accounting		—			—			2
Amortization of debt issuance costs and discounts		18			3			5
Allowance for funds used during construction – capitalized interest portion		(10	)		(3	)		(2	)
Total interest expense and related charges	$	374		$	359		$	347

67

Restricted Cash

Restricted cash amounts reported on our balance sheet consisted of the following:

	At December 31, 2012				At December 31, 2011
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Customer collections related to transition bonds used only to service debt and pay expenses	$	55	$	—	$	57	$	—
Reserve for fees associated with transition bonds		—		10		—		10
Reserve for shortfalls of transition bond charges		—		6		—		6
Total restricted cash	$	55	$	16	$	57	$	16

Trade Accounts Receivable

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

	At December 31,
	2012			2011
Gross trade accounts receivable	$	395		$	436
Trade accounts receivable from TCEH		(55	)		(131	)
Allowance for uncollectible accounts		(2	)		(2	)
Trade accounts receivable from nonaffiliates — net	$	338		$	303

Gross trade accounts receivable at December 31, 2012 and 2011 included unbilled revenues of $147 million and $127 million, respectively.

Under a PUCT rule relating to the Certification of Retail Electric Providers, write-offs of uncollectible amounts owed by REPs are deferred as a regulatory asset. Due to commitments made to the PUCT in 2007, we are not allowed to recover bad debt expense, or certain other costs and expenses, from ratepayers in the event of a default or bankruptcy by an affiliate REP.

Investments and Other Property

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

	At December 31,
	2012		2011
Assets related to employee benefit plans, including employee savings programs, net of distributions	$	80	$	70
Land		3		3
Total investments and other property	$	83	$	73

The majority of these assets represent cash surrender values of life insurance policies that are purchased to fund liabilities under deferred compensation plans. At December 31, 2012 and 2011, the face amount of these policies totaled $152 million and $137 million, respectively, and the net cash surrender values (determined using a Level 2 valuation technique) totaled $65 million and $46 million, respectively. Changes in cash surrender value are netted against premiums paid. Other investment assets held to satisfy deferred compensation liabilities are recorded at market value.

68

Property, Plant and Equipment

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

	Composite Depreciation Rate/	At December 31,
	Avg. Life at December 31, 2012	2012		2011
Assets in service:
Distribution	4.1% / 24.5 years	$	9,745	$	9,486
Transmission	2.8% / 35.2 years		5,482		4,919
Other assets	9.3% / 10.8 years		856		822
Total			16,083		15,227
Less accumulated depreciation			5,407		5,203
Net of accumulated depreciation			10,676		10,024
Construction work in progress			627		530
Held for future use			15		15
Property, plant and equipment – net		$	11,318	$	10,569

Depreciation expense as a percent of average depreciable property approximated 3.9% for the year ended December 31, 2012 and 4.0% for each of the years ended December 31, 2011 and 2010.

Intangible Assets

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

	At December 31, 2012						At December 31, 2011
	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	$	295	$	79	$	216	$	248	$	77	$	171
Capitalized software		409		220		189		378		181		197
Total	$	704	$	299	$	405	$	626	$	258	$	368

Aggregate amortization expense for intangible assets totaled $53 million, $48 million and $39 million for the years ended December 31, 2012, 2011 and 2010, respectively. At December 31, 2012, the weighted average remaining useful lives of capitalized land easements and software were 89 years and 5 years, respectively. The estimated aggregate amortization expense for each of the next five fiscal years is as follows:

Year	Amortization Expense
2013	$	56
2014		56
2015		56
2016		53
2017		45

At both December 31, 2012 and 2011, goodwill totaling $4.1 billion was reported on the balance sheet. None of this goodwill is being deducted for tax purposes. See Note 1 regarding goodwill impairment assessment and testing. In the fourth quarter of 2008, we recorded a goodwill impairment charge of $860 million, which was not deductible for income tax-related purposes.

69

Other Noncurrent Liabilities and Deferred Credits

Other noncurrent liabilities and deferred credits reported on our balance sheet consisted of the following:

	At December 31,
	2012		2011
Retirement plans and other employee benefits	$	1,495	$	1,340
Uncertain tax positions (including accrued interest)		169		147
Other		58		59
Total	$	1,722	$	1,546

Supplemental Cash Flow Information

	Year Ended December 31,
	2012			2011			2010
Cash payments (receipts) related to:
Interest	$	378		$	360		$	339
Capitalized interest		(10	)		(3	)		(2	)
Interest (net of amounts capitalized).		368			357			337
Amount in lieu of income taxes:
Federal		(23	)		(134	)		109
State		21			20			19
Total amount in lieu of income taxes		(2	)		(114	)		128
SARs early exercise		64			—			—
Noncash investing and financing activities:
Construction expenditures (a)		103			140			78
Debt exchange transactions		—			—			324

(a) Represents end-of-period accruals.

Quarterly Information (unaudited)

Results of operations by quarter for the years ended December 31, 2012 and 2011 are summarized below. In our opinion, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily indicative of a full year’s operations because of seasonal and other factors.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2012
Operating revenues	$	783	$	828	$	925	$	792
Operating income		157		188		230		156
Net income (a)		75		107		139		28

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2011
Operating revenues	$	706	$	756	$	897	$	759
Operating income		145		173		225		150
Net income		65		92		144		66

(a) Fourth quarter 2012 reflects a $57 million charge to expense associated with the SARs settlement (see Note 10).

70

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. 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 December 31, 2012. 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. There has been no change in our internal control over financial reporting during the most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ONCOR ELECTRIC DELIVERY COMPANY LLC

MANAGEMENT’S ANNUAL REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Oncor Electric Delivery Company LLC is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Oncor Electric Delivery Company LLC’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with procedures or policies.

The management of Oncor Electric Delivery Company LLC performed an evaluation as of December 31, 2012 of the effectiveness of the company’s internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission’s (COSO’s)Internal Control—Integrated Framework. Based on the review performed, management believes that as of December 31, 2012 Oncor Electric Delivery Company LLC’s internal control over financial reporting was effective.

The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statements of Oncor Electric Delivery Company LLC has issued an attestation report on Oncor Electric Delivery Company LLC’s internal control over financial reporting.

/s/ ROBERT S. SHAPARD	/s/ DAVID M. DAVIS
Robert S. Shapard, Chairman of the Board	David M. Davis, Senior Vice President
and Chief Executive	and Chief Financial Officer

February 19, 2013

71

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of Oncor Electric Delivery Company LLC

Dallas, Texas

We have audited the internal control over financial reporting of Oncor Electric Delivery Company LLC and subsidiary (the “Company”) as of December 31, 2012 based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Company and our report dated February 19, 2013 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Dallas, Texas

February 19, 2013

72

Item 9B. OTHER INFORMATION

On February 12, 2013, the Organization & Compensation committee of our board of directors approved our entrance into a retention agreement with E. Allen Nye, Jr., our Senior Vice President, General Counsel & Secretary. The agreement provides for the payment of a one-time cash retention bonus of $300,000 to Mr. Nye contingent upon his continued employment and satisfactory performance of his job duties as directed by Oncor through December 31, 2014. The bonus is payable in accordance with Oncor’s normal payroll practices or as soon as practicable after December 31, 2014. In the event Mr. Nye is terminated with cause or elects to terminate his employment without good reason prior to December 31, 2014, he will immediately forfeit the retention bonus. In the event Mr. Nye’s employment is terminated prior to December 31, 2014 either by Oncor without cause, by him for good reason, or as a result of his death or disability, the retention bonus will immediately vest and become payable. Under the agreement, a termination for “cause” is defined as a termination as a result of the commitment of any of the following actions by Mr. Nye: (i) a breach of any fiduciary duty to Oncor, (ii) gross negligence in the performance of his duties, (iii) failure or refusal to carry out the duties of his position with Oncor, (iv) any action or omission that results in material injury to the assets, business prospectus or reputation of Oncor or any of its affiliates, (v) appropriation of a material business opportunity of Oncor or any of its affiliates, including securing or attempting to secure personal profit as a result of any transaction involving Oncor or any of its affiliates; (vi) breach of Oncor’s Code of Conduct or a material employment policy or rule; or (vii) any indictment or plea of nolo contendere or guilty for any crime involving fraud, theft, embezzlement or moral turpitude. The agreement defines “good reason” as any one or more of the following actions taken without Mr. Nye’s express consent: (i) a reduction in base salary other than a broad-based reduction of base salaries for similarly situated Oncor executives; or (ii) a material reduction in the aggregate level or benefits for which Mr. Nye is eligible, other than a broad-based benefits reduction for similarly situated executives. The agreement also provides that during Mr. Nye’s employment with Oncor or any affiliate and for a period of 12 months thereafter, he will not directly or indirectly solicit, recruit, encourage or in any way cause any executive of Oncor or any affiliate to terminate his employment with Oncor or such affiliate. An affiliate is defined in the agreement as any entity that controls, is controlled by, or is under common control with, Oncor.

On February 13, 2013, our board of directors adopted a Long-Term Incentive Plan. For a description of the material terms of this plan, see “EXECUTIVE COMPENSATION – Compensation Discussion & Analysis – Compensation Elements – Long-Term Incentives – Long-Term Incentive Plan.”

Copies of the retention agreement, Long-Term Incentive Plan and form of Long-Term Incentive Plan Award Agreement are filed as exhibits 10(s), 10(t) and 10(u) to this Annual Report on Form 10-K.

73

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors

The names of our directors and information about them, as furnished by the directors themselves, are set forth below:

Name	Age	Business Experience and Qualifications
Nora Mead Brownell (1)	65	Nora Mead Brownell has served as our Director since October 2007. Ms. Brownell is a founding partner of ESPY Energy Solutions, LLC, a consulting firm specializing in energy including infrastructure, energy consumption, new technology and renewables, and has served as its CEO since April 2009. Following her service as a Commissioner of the FERC from May 2001 to June 2006, Ms. Brownell founded BC Strategies, an energy consulting firm, and served as its President until April 2009. She served on the Pennsylvania Public Utility Commission from 1997 until May 2001, and as President of National Association of Regulatory Utility Commissioners (NARUC) from 2000 to 2001. Ms. Brownell serves on the boards of directors of Comverge Inc., an energy technology company, Spectra Energy Partners, a natural gas transportation and storage company, Tangent Energy Solutions, a privately-owned developer of energy generation solutions, Times Publishing Company, a privately-owned regional newspaper publisher, National Grid plc, an international electricity and gas company listed on the New York Stock Exchange and London Stock Exchange, and Oncor Holdings. She also serves on the Advisory Board of Starwood Energy Fund, NewWorld Capital Group and Terviva. During the last six years Ms. Brownell also served on the board of directors of Ener1, a manufacturer of lithium-ion energy storage systems and Leaf Clean Energy Company, which invests in clean energy projects in North America, and on the Gridwise® Architecture Council. We believe Ms. Brownell’s widely-regarded expertise in the energy industry qualifies her to serve on our board of directors. Her extensive experience and insights gained as a regulator of energy companies on both the federal and state levels are a significant contribution to us, a regulated electricity transmission and distribution company, and our board of directors. During her tenures as a Pennsylvania state regulator and FERC Commissioner, Ms. Brownell oversaw several issues similar to those that have been or may be experienced by Oncor, including rate reviews, market issues and reliability proceedings. Her current work in energy consulting further strengthens her understanding and expertise of current issues in our industry, including in the areas of renewable energy, technology and regulatory matters.

74

Name	Age	Business Experience and Qualifications
Thomas M. Dunning (3)	70	Thomas M. Dunning has served as our Director since October 2007 and in July 2010 was elected Lead Independent Director by our board of directors. Since his retirement in 2008 as Chairman of Lockton Dunning Benefits, a company specializing in the design and servicing of employee benefits, he has served as a consultant for the company. Mr. Dunning also served as Chairman and Chief Executive Officer of Lockton Dunning Benefit Company, its predecessor company, from 1998 to 2007 following the 1998 acquisition of Dunning Benefits Corporation by the Lockton Group of Companies. Mr. Dunning currently serves on the boards of directors of American Beacon Funds, BancTec, Baylor Health Care System Foundation, Oncor Holdings, and a number of non-profit organizations. He is also a former Chairman of Dallas Fort Worth International Airport board and a former director of the Southwestern Medical Foundation. We believe Mr. Dunning’s experience with employee benefit programs and his understanding of employee benefits as part of an overall employee compensation program is important to Oncor in his roles as a director and member of the Organization and Compensation Committee (O&C Committee). As member and former chair of the O&C Committee, overseeing the design and effectiveness of Oncor’s executive compensation programs, Mr. Dunning offers broad experience in understanding and addressing compensation-related issues and challenges. His past appointments by Texas Governors as Chairman of the Texas Water Development Board and a director on the boards of the Texas Department of Transportation, Texas Department of Human Services and Texas Department of Criminal Justice, as well as his past service as Chairman of the Dallas/Fort Worth International Airport board, add to the extensive experience and leadership skills Mr. Dunning provides to our board. His experience and familiarity with Texas government, combined with 45 years of experience in business and a strong record of civic involvement in Dallas and in Texas, are valuable to our Texas-based business.
Robert A. Estrada (1)	66	Robert A. Estrada has served as our Director since October 2007. Mr. Estrada is Chairman of the Board and Chief Compliance Officer of Estrada Hinojosa & Company, Inc., an investment banking firm specializing in public finance that he co-founded in 1992. In addition to these positions, he also served as President and Chief Executive Officer of the firm from 1992 to 2006. Since its inception, Estrada Hinojosa & Company, Inc. has been involved in municipal bond underwritings totaling over $80 billion and has provided financial advisory services on financings totaling more than $50 billion. Mr. Estrada is a member of the boards of directors of Oncor Holdings and several civic and arts organization boards. From 2001 until 2008, Mr. Estrada served on the Board of Regents of the University of Texas System, a system with over 60,000 employees and a budget of approximately $14 billion, pursuant to an appointment by the Governor of Texas. In addition to having served on the Board of Regents of the University of Texas System, Mr. Estrada served as that board’s chair of the audit, compliance and management review committee. From 2004 until 2010, he served two consecutive terms on the board of directors of the Federal Reserve Bank of Dallas. From 1990 to 1994, Mr. Estrada also served on the board of directors of the Student Loan Marketing Association (Sallie Mae), a $45 billion entity and was a member of the board’s executive committee. We believe Mr. Estrada’s skills and experience in the financial and legal sectors qualify him to serve as a director of Oncor and chair of the Audit Committee. We also believe his comprehensive understanding of financial, compliance and business matters pertinent to us and his experience in serving large clients and boards regarding these matters are significant assets to our board. Mr. Estrada also has 28 years of legal experience as a securities attorney, giving him a familiarity with securities law issues and investor disclosure requirements relevant to our company.

75

Name	Age	Business Experience and Qualifications
Thomas D. Ferguson (2)	59	Thomas D. Ferguson has served as our Director since January 2011. Mr. Ferguson currently serves as a Managing Director of Goldman, Sachs & Co., having joined the firm in 2002. Mr. Ferguson heads the asset management efforts for the merchant bank’s U.S. real estate investment activity. Mr. Ferguson serves on the board of EFH Corp., American Golf, one of the largest golf course management companies in the world, Agricultural Company of America Partners, LP, a company that owns and manages agriculture real estate, and Nor1, a company providing revenue enhancement solutions to the travel industry. Mr. Ferguson formerly held board seats at Associated British Ports, the largest port company in the UK, as well as Red de Carreteras, a toll road concessionaire in Mexico and Carrix, one of the largest private container terminal operators in the world. Mr. Ferguson was appointed by the Sponsor Group as a member of our board of directors pursuant to the Sponsor Group’s right in the Limited Liability Company Agreement to designate two directors. His extensive experience with corporate finance and in owning and managing privately held enterprises qualifies Mr. Ferguson for serving on our board of directors.
Monte E. Ford (2)	53	Monte E. Ford has served as our Director since February 2008. Since August 2012, Mr. Ford has served as President of Aptean, a global leader in enterprise application software, and from April to August 2012 served as the President of CDC Software Corporation, a predecessor to Aptean. From 2001 until January 2012, he served as Senior Vice President and Chief Information Officer of AMR Corporation, the Fort Worth-based parent company of American Airlines. Prior to joining AMR, Mr. Ford served in various executive positions, including with Associates First Capital in Texas, Bank of Boston and Digital Equipment Corporation. He helped found the Environmental Energy and Nutritional Learning Center in Boston and has served on various community and non-profit boards, including those of Baylor Regional Medical Center and the Children’s Medical Center Development Board. Mr. Ford also serves on the board of directors of Oncor Holdings. Mr. Ford previously served as a director of two public companies, META Group and Moneygram International, from 2006 to 2008 prior to his affiliation with Oncor. We believe Mr. Ford’s skills and expertise with quickly changing information technology matters is an important aspect of his service on Oncor’s board of directors. In regard to our operational advancements, particularly in the areas of the advanced metering system, Smart Grid and transmission infrastructure, information technology is a critical and timely issue for us, as well as the electric industry. Having dedicated his career to technology, Mr. Ford has distinguished himself as a technical industry expert and leader. As Senior Vice President and Chief Information Officer of AMR Corporation, Mr. Ford led technological innovation for American Airlines, one of the world’s largest airlines, including reestablishing the airline as an industry leader in operations research and advancing the airline’s online business. During his tenure as Chief Information Officer at Associates First Capital, Mr. Ford had responsibility for all technical operations at the company and implemented an internet and e-commerce strategy for the company on a worldwide basis.

76

Name	Age	Business Experience and Qualifications
William T. Hill, Jr. (2)	70	William T. Hill, Jr. has served as our Director since October 2007. In 2012, Mr. Hill began practicing law with the law firm of William T. Hill, Jr., Attorney at Law. Prior to 2012, he was of counsel to the Dallas criminal defense law firm of Fitzpatrick Hagood Smith & Uhl LLP. In 2007, he served as Director of Strategic Initiatives of Mercy Street Ministries. From 1999 to 2007, Mr. Hill was Criminal District Attorney of the Dallas County District Attorney’s office. Mr. Hill serves on the boards of directors of Hilltop Holdings, Incorporated, a New York Stock Exchange listed company in the insurance industry, Baylor Hospital Foundation, Oncor Holdings and a number of charitable organizations. We believe Mr. Hill’s 46 years of experience with legal and compliance matters, along with his management of a large group of highly skilled professionals, have given him considerable knowledge concerning many matters that come before our board of directors. In addition, as District Attorney he developed judgment and decision-making abilities that assist him today in evaluating and making decisions on issues that face our board of directors. Mr. Hill has also served on several civic and charitable boards over the past 36 years, which has given him invaluable experience in corporate governance matters.
Jeffrey Liaw (3)	36	Jeffrey Liaw has served as our Director since November 2007. Mr. Liaw currently serves as the Chief Financial Officer of FleetPride, Inc., a nationwide retailer of heavy-duty truck and trailer parts, a position he has held since December 2012. From 2005 until December 2012, Mr. Liaw served as a principal with TPG, focusing on their energy and industrial investing practice areas. TPG is a leading private investment firm with approximately $55 billion in assets under management. Before joining TPG in 2005, he worked for Bain Capital in its industrials practice since 2001. Mr. Liaw also serves on the board of directors of Armstrong World Industries, Inc. and Oncor Holdings. Mr. Liaw was appointed by the Sponsor Group as a member of our board of directors pursuant to the Sponsor Group’s right in the Limited Liability Company Agreement to designate two directors. As a former investment professional in the energy and industrial investing practice of TPG and a current chief financial officer of a large company, Mr. Liaw provides his valuable insights and knowledge regarding energy-related and financial matters.
Rheal R. Ranger (1)	54	Rheal R. Ranger has served as our Director since October 2012. Mr. Ranger currently serves as Executive Vice President with Borealis Infrastructure Management Inc. (Borealis), the infrastructure investment arm of Canada’s OMERS pension plan, a position he has held since January 2012. In such role, he is responsible for leading and managing Borealis’s transaction team in New York. Prior to assuming this role, he was Borealis’s Executive Vice President and Chief Financial Officer, a position that he fulfilled since joining Borealis in June, 2004. From 1987 to 2004, he served in various executive management positions (including CFO and CEO) within the Standard Broadcasting group of companies, one of Canada’s largest broadcast companies, and from 1982 to 1987 he served as a Tax Manager with Arthur Andersen, a large international accounting firm. In his role as an officer of Borealis, Mr. Rheal has been appointed as an officer and director of several Borealis affiliates and companies in which Borealis invests. He has served as a director for Midland Co-Generation Venture, a 1633MW gas fired power plant located in Midland, Michigan, since December 2012. Mr. Ranger was appointed as a member of our board of directors by Texas Transmission pursuant to Texas Transmission’s right under the Limited Liability Company Agreement to designate two directors. Mr. Ranger has extensive experience in structuring multi-layered investment structures in different regulatory and tax jurisdictions and has actively participated in a number of Borealis’s acquisitions and asset management activities. We believe Mr. Ranger’s extensive business, financial and management experience in the energy industry brings great value to our board of directors, particularly with respect to management and financial matters.

77

Name	Age	Business Experience and Qualifications
Robert S. Shapard	57	Robert S. Shapard has served as the Chairman of our Board of Directors and Chief Executive since April 2007. Mr. Shapard joined EFH Corp.’s predecessor in October 2005 as a strategic advisor, helping implement and execute growth and development strategies for Oncor. Between March and October 2005, he served as Chief Financial Officer of Tenet Healthcare Corporation, one of the largest for-profit hospital groups in the United States, and was Executive Vice President and Chief Financial Officer of Exelon Corporation, a large electricity generator and utility operator, from 2002 to February 2005. Before joining Exelon, he was executive vice president and chief financial officer of Ultramar Diamond Shamrock, a North American refining and marketing company, since 2000. Previously, from 1998 to 2000, Mr. Shapard was CEO and managing director of TXU Australia Pty. Ltd., a subsidiary of the former TXU Corp., which owned and operated electric generation, wholesale trading, retail, and electric and gas regulated utility businesses. Mr. Shapard is also a director of Oncor Holdings and a manager of Bondco. He also serves as chairman of the board of directors of Gridwise® Alliance, the nation’s foremost smart grid organization. As our chief executive, Mr. Shapard brings his unique knowledge of our company and our industry to the board of directors. His prior experience with EFH Corp., Exelon and as CEO of TXU Australia gives him extensive leadership experience in the electric industry in both regulated and unregulated markets. Mr. Shapard’s previous experience as chief financial officer of Tenet Healthcare Corporation and Ultramar Diamond Shamrock provided him with substantial experience in other complex financial and business environments.
Richard W. Wortham III (2) (3)	74	Richard W. Wortham III has served as our Director since October 2007. Since 1976 he has served as Trustee of The Wortham Foundation, Inc., a private philanthropic foundation with assets of approximately $260 million dedicated to the support and development of Houston’s cultural fabric. Mr. Wortham has served as President of the Wortham Foundation, Inc. since November 2011 and served as Secretary and Treasurer from November 2008 until November 2011. From November 2005 to November 2008, he was Chairman and Chief Executive Officer of that foundation. Mr. Wortham also serves as a Trustee and member of the audit committee of HC Capital Trust, a $10 billion family of mutual funds, and the Center for Curatorial Studies at Bard College and is a Life Trustee and Treasurer of The Museum of Fine Arts, Houston. Mr. Wortham is also a director of Oncor Holdings. Additionally, Mr. Wortham has held a leadership role in several companies, including a founding role in several national banks. We believe Mr. Wortham’s over 31 years of extensive business and civic experience qualify him to serve on our board of directors and chair our O&C Committee. Mr. Wortham also currently serves on the executive, finance, audit and investment committees of the Museum of Fine Arts, Houston, which presently has an endowment of approximately $1 billion. Mr. Wortham’s experience has given him substantial and significant knowledge and experience regarding financial management and corporate governance matters relevant to our board of directors.

78

Name	Age	Business Experience and Qualifications
Steven J. Zucchet (2) (3)	47	Steven J. Zucchet has served as our Director since November 2008. Mr. Zucchet is a Senior Vice President of Borealis Infrastructure Management, Inc. (Borealis), an investment arm of Canada’s OMERS pension plan, a position he has held since November 2003. From 1996 until joining Borealis, Mr. Zucchet served as Chief Operating Officer of Enwave Energy Ltd., where he was responsible for operations and major infrastructure projects. In his role as an officer of Borealis, Mr. Zucchet has been appointed as an officer and director of several Borealis affiliates and companies in which Borealis invests. His focus at Borealis is in the energy sector, where he leads the pursuit of investment opportunities in the energy sector and is responsible for asset management. Mr. Zucchet was appointed as a member of our board of directors by Texas Transmission pursuant to Texas Transmission’s right under the Limited Liability Company Agreement to designate two directors. Mr. Zucchet has extensive experience in the energy industry. Through Borealis, he serves on the board of directors for Bruce Power A, a four reactor nuclear site located in Ontario, Canada. His experience prior to joining Borealis also focused in the energy industry, serving as Chief Operating Officer of Enwave Energy Ltd. for seven years. Prior to joining Enwave Energy Ltd., he spent seven years with an international consulting firm where he worked primarily on transportation and energy related projects. We believe Mr. Zucchet’s experience in the energy industry gives him an important and valuable understanding of our business.

(1) Member of Audit Committee.

(2) Member of Nominating and Governance Committee.

(3) Member of Organization and Compensation Committee.

Director Appointments

Pursuant to our Limited Liability Company Agreement, the Sponsor Group (through Oncor Holdings) has a right to designate two individuals to serve on our board of directors. Mr. Ferguson, a managing director of Goldman, Sachs & Co., and Mr. Liaw, a former TPG principal, are each managers of the sole general partner of Texas Holdings and were each designated to serve on our board of directors by the Sponsor Group. Our Limited Liability Company Agreement also grants Texas Transmission the right to designate two individuals to serve on our board of directors. Rheal R. Ranger and Steven J. Zucchet, each of whom is an officer of Borealis, an affiliate of Texas Transmission, were designated to serve on our board of directors by Texas Transmission. Directors appointed by the Sponsor Group and Texas Transmission are referred to as member directors.

Our Limited Liability Company Agreement also provides that six of our directors will be independent directors under the standards set forth in Section 303A of the New York Stock Exchange Manual and other standards in our Limited Liability Company Agreement, and that two of those independent directors will be special independent directors under the standards set forth in our Limited Liability Company Agreement. See “Certain Relationships and Related Transactions, and Director Independence — Director Independence” for a discussion of the independent director and special independent director qualifications. Our board of directors has determined that Ms. Brownell and Messrs. Estrada, Dunning, Ford, Hill and Wortham are independent directors and that each of Ms. Brownell and Mr. Hill qualifies as a special independent director. Independent directors are appointed by the nominating committee of Oncor’s Holdings’ board of directors. The nominating committee of Oncor Holdings is required to consist of a majority of independent directors.

The board of directors of the sole member of Oncor Holdings has the right, pursuant to the terms of our Limited Liability Company Agreement, to designate one director that is an officer of Oncor. Mr. Shapard, our Chairman and Chief Executive, serves as this director.

79

Audit Committee

The Audit Committee is a separately-designated standing audit committee, established in accordance with section 3(a)(58)(A) of the Securities Exchange Act of 1934, as amended. Our Audit Committee is composed of Ms. Brownell, Mr. Ranger and Mr. Estrada. Mr. Estrada and Mr. Ranger are each an “audit committee financial expert” as defined in Item 407(d)(5) of SEC Regulation S-K. Mr. Estrada is an independent director under the standards set forth in our Limited Liability Company Agreement. Mr. Ranger is a member director, appointed by Texas Transmission.

80

Executive Officers

The names of our executive officers and information about them, as furnished by the executive officers themselves, are set forth below:

Name	Age	Positions and Offices Presently Held	Business Experience (Preceding Five Years)
Robert S. Shapard	57	Chairman of the Board and Chief Executive	Robert S. Shapard has served as the Chairman of our Board of Directors and Chief Executive since April 2007. Mr. Shapard joined EFH Corp.’s predecessor in October 2005 as a strategic advisor, helping implement and execute growth and development strategies for Oncor. Between March and October 2005, he served as Chief Financial Officer of Tenet Healthcare Corporation, one of the largest for-profit hospital groups in the United States, and was Executive Vice President and Chief Financial Officer of Exelon Corporation, a large electricity generator and utility operator, from 2002 to February 2005. Before joining Exelon, he was executive vice president and chief financial officer of Ultramar Diamond Shamrock, a North American refining and marketing company, since 2000. Previously, from 1998 to 2000, Mr. Shapard was CEO and managing director of TXU Australia Pty. Ltd., a subsidiary of the former TXU Corp., which owned and operated electric generation, wholesale trading, retail, and electric and gas regulated utility businesses. Mr. Shapard is also a director of Oncor Holdings and a manager of Bondco. He also serves as chairman of the board of directors of Gridwise® Alliance, the nation’s foremost smart grid organization.
Walter Mark Carpenter	60	Senior Vice President, Transmission Grid Management and System Operations	Walter Mark Carpenter has served as our Senior Vice President, Transmission Grid Management and System Operations since October 2011, and in such role is responsible for overseeing transmission grid management operations and Oncor’s interface with ERCOT. He also oversees the system’s distribution operation centers, as well as Oncor’s outage management system, the deployment of the advanced meter system and its integration into operations. From February 2010 until October 2011 he served as our Vice President and Chief Technology Officer, and from 2008 until February 2010 he served as our Vice President and Chief Information Officer. Mr. Carpenter has served EFH Corp’s predecessor and Oncor for 38 years and has held various field management and engineering management positions in transmission and distribution. Mr. Carpenter is a registered Professional Engineer in the State of Texas and is a member of the Institute of Electrical and Electronic Engineers (IEEE) Power System Relaying Committee and the Texas Society of Professional Engineers.

81

Name	Age	Positions and Offices Presently Held	Business Experience (Preceding Five Years)
Don J. Clevenger	42	Senior Vice President, External Affairs	Don J. Clevenger has served as our Senior Vice President, Strategy, since January 2013. From February 2010 through December 2012, he served as our Senior Vice President, External Affairs and before that, served as our Vice President, External Affairs from June 2008 until February 2010, Mr. Clevenger served as our Vice President, Legal and Corporate Secretary from December 2007 to June 2008. Between November 2005 and December 2007, Mr. Clevenger held a leadership position in our company with various legal and regulatory responsibilities. Prior to his transfer to Oncor in November 2005, he was Senior Counsel of the Business Services unit of EFH Corp. since April 2004. Mr. Clevenger was a partner in the law firm of Hunton & Williams LLP before he joined EFH Corp.’s predecessor. Mr. Clevenger is also a manager of Bondco and serves as a member of the board of directors of the Association of Electric Companies of Texas, Inc.
David M. Davis	55	Senior Vice President and Chief Financial Officer	David M. Davis has served as our Senior Vice President and Chief Financial Officer since February 2010. From July 2006 until February 2010, he served as Vice President and Chief Financial Officer. Prior to July 2006, he held a leadership position in the finance and financial planning function since joining Oncor in 2004. From 1991 to 2004, Mr. Davis served in various positions at EFH Corp.’s predecessor including roles in accounting, information technology and financial planning. Mr. Davis is a certified public accountant. Mr. Davis is also a manager of Bondco.
Deborah L. Dennis	58	Senior Vice President, Human Resources & Corporate Affairs	Deborah L. Dennis has served as our Senior Vice President, Human Resources & Corporate Affairs since January 2013. Ms. Dennis has been employed with Oncor and its predecessors and affiliates for 34 years in a number of corporate and customer service functions, including 13 years as a Vice President, most recently serving as Vice President of Corporate Affairs from 2011 to December 2012, and Vice President—Dallas Customer Operations from 2007 to 2011. Ms. Dennis has extensive experience in human resources, customer service, supply chain, outsourcing management and corporate philanthropy.
Debra L. Elmer	56	Senior Vice President	Debra L. Elmer has served as our Senior Vice President since January 2013. She served as our Senior Vice President, Human Resources from February 2010 through December 2012, and as our Vice President, Human Resources from September 2006 until February 2010. From her transfer to Oncor from EFH Corp. in 2004 to September 2006, she served as the director responsible for our performance management. Ms. Elmer joined EFH Corp.’s predecessor in 1982 and has held a number of positions within EFH Corp., principally in the leadership of human resources activities. Ms. Elmer has notified our board of directors and management that she intends to retire effective April 2013.

82

Name	Age	Positions and Offices Presently Held	Business Experience (Preceding Five Years)
James A. Greer	52	Senior Vice President and Chief Operating Officer	James A. Greer has served as our Senior Vice President and Chief Operating Officer since October 2011. From October 2007 until October 2011 he served as our Senior Vice President, Asset Management and Engineering and in such role was responsible for the development of strategies, policies and plans for optimizing the value and performance of electric delivery systems and related assets. From 2004 to 2007, Mr. Greer served a similar role as our Vice President. Since joining EFH Corp.’s predecessor in 1984, Mr. Greer has held a number of leadership positions within Oncor and EFH Corp. in such areas as engineering, operations and governmental relations. Mr. Greer also serves as a member of the Board of Directors of the Texas Board of Professional Engineers and is a registered Professional Engineer in the State of Texas.
Michael E. Guyton	54	Senior Vice President	Michael E. Guyton has served as our Senior Vice President since January 2013. Mr. Guyton has extensive experience in customer operations, having served in various customer operations positions with Oncor and its predecessors and affiliates for 35 years, including 11 years as a Vice President. Prior to assuming his current role, Mr. Guyton served as our Vice President of Customer Operations with responsibility for customer operations in the city of Fort Worth and Tarrant County since July 2006. In his current role, Mr. Guyton focuses on transitioning the responsibilities of his customer operations role and preparing to assume the role of Senior Vice President and Chief Customer Officer as our board of directors has named him to assume such new role upon Brenda Jackson’s planned retirement effective July 2013.
Brenda L. Jackson	62	Senior Vice President and Chief Customer Officer	Brenda L. Jackson has served as our Senior Vice President and Chief Customer Officer since May 2010, overseeing activities including customer operations and service, community relations and economic development initiatives. From October 2004 until May 2010, Ms. Jackson served as Senior Vice President, Business Operations. From April 2003 until October 2004 she held the position of Senior Vice President, Customer and Community Relations. Ms. Jackson has served EFH Corp.’s predecessor and Oncor for 41 years and has held leadership positions related to customer operations, customer service and community relations functions, human resources, procurement and information technology. Ms. Jackson has notified our board of directors and management that she intends to retire effective July 2013.
E. Allen Nye, Jr.	45	Senior Vice President, General Counsel & Secretary	E. Allen Nye, Jr. has served as our Senior Vice President, General Counsel and Secretary since January 2011. From June 2008 until joining Oncor, Mr. Nye practiced law as a partner in the Dallas office of Vinson & Elkins LLP, where he focused on representation of regulated energy companies before state and federal government agencies, including the PUCT, the State Office of Administrative Hearings and the FERC. Prior to Vinson & Elkins, Mr. Nye was a partner in the law firm of Hunton & Williams from January 2002 until May 2008.

83

Name	Age	Positions and Offices Presently Held	Business Experience (Preceding Five Years)
Brenda J. Pulis	54	Senior Vice President	Brenda J. Pulis has served as our Senior Vice President since January 2013. She served as Senior Vice President, Asset Management and Engineering from October 2011 through December 2012, and in such role was responsible for optimizing the value and performance of electric delivery systems and related assets. Ms. Pulis originally joined us in 1978 and has served in a number of areas during her tenure, including Senior Vice President, Transmission and Distribution System Operations & Measurement Services from November 2010 to October 2011, Senior Vice President of Distribution from August 2004 to October 2010, and Vice President in our distribution organization from 2001 until July 2004. Ms. Pulis has notified our board of directors and management that she intends to retire in late 2013.

There is no family relationship between any of our executive officers, between any of our directors, or between any executive officer and any director.

Code of Conduct

We maintain certain corporate governance documents on our website at www.oncor.com. Our Code of Conduct can be accessed by selecting “Corporate Governance” under the “Investors” tab on the website. Our Code of Conduct applies to all of our employees and officers, including our Chief Executive, Chief Operating Officer, Chief Financial Officer and Controller, and it also applies to our directors, except for provisions pertinent only to employees. Any amendments to our Code of Conduct will be posted on our website promptly. Printed copies of the corporate governance documents that are posted on our website are available to any person without charge upon written request to the Corporate Secretary of Oncor Electric Delivery Company LLC at 1616 Woodall Rodgers Freeway, Suite 7E-002, Dallas, Texas 75202-1234.

84

Item 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Overview

Our board of directors has designated an Organization and Compensation Committee of the board of directors (O&C Committee) to establish and assess our executive compensation policies, which include participation in Oncor-sponsored programs as well as certain employee benefit programs sponsored by EFH Corp. The O&C Committee met six times in 2012.

The responsibilities of the O&C Committee include:

• Determining and overseeing executive compensation programs, including making recommendations to our board of directors, when and if its approval is required, with respect to the adoption, amendment or termination of incentive compensation, equity-based and other executive compensation and benefit plans, policies and practices;

• Establishing, reviewing and approving corporate goals and objectives relevant to executive compensation and evaluating the performance of our Chief Executive (CEO) and other executive officers in light of those goals and objectives and ultimately approving executive compensation based on those evaluations; and

• Advising our board of directors with respect to compensation of its independent directors.

The O&C Committee conducts a review of total direct compensation for our executive officers, including the executive officers named in the Summary Compensation Table below (collectively with the CEO, the Named Executive Officers, and each, a Named Executive Officer) from time to time as it deems appropriate. In determining the total direct compensation of our executive officers, the O&C Committee considers the performance of the executives, a competitive market analysis of executive compensation provided by a compensation consultant engaged by the O&C Committee and a peer group analysis. The O&C Committee obtains the input of the CEO on the performance of executive officers reporting to the CEO. The CEO assesses the performance of each executive reporting to him against the executive’s business unit and function and presents a performance evaluation and compensation recommendation for each of these individuals to the O&C Committee. The CEO also reviews and considers the competitive market analysis in making his recommendation. The O&C Committee also evaluates the CEO’s performance. The O&C Committee then determines total compensation, including base salary, annual incentive awards and long-term incentive awards, for each of our executive officers as it deems appropriate.

In the first quarter of each fiscal year, the O&C Committee approves corporate goals and objectives under the annual incentive program for our executive officers for the current fiscal year, as well as the annual incentive payouts relating to the previous fiscal year’s performance. Following the completion of each fiscal year, in connection with the annual determination of the incentive awards to be paid to our executive officers reporting to the CEO, the CEO conducts an annual performance review of each such executive officer and evaluates each executive’s performance relative to the corporate goals and objectives for the completed fiscal year set by the O&C Committee. The CEO then makes recommendations to the O&C Committee with respect to other executive officers’ annual incentive compensation. The O&C Committee considers the CEO’s recommendations when determining annual incentive award payouts to those executive officers for the previous fiscal year, as well as goals and objectives under the annual incentive programs for the current fiscal year. The O&C Committee also annually evaluates the CEO’s performance in light of the goals and objectives for the applicable year and, after considering this evaluation, determines the CEO’s annual incentive award payout, as well as goals and objectives under the annual incentive programs for the current fiscal year.

Compensation Philosophy

Our compensation philosophy, principles and practices are intended to compensate executives appropriately for their contribution to the attainment of key strategic objectives, and to strongly align the interests of executives and equity holders through equity-based plans and performance goals. We believe that:

• Levels of executive compensation should be based upon an evaluation of the performance of our business (through operational metrics including safety, reliability, operational efficiency and infrastructure readiness and financial performance) and individual executives as well as a comparison to compensation levels of persons with comparable responsibilities in business enterprises of similar size, scale, complexity, risk and performance;

85

• Compensation plans should balance both short-term and long-term objectives, and

• The overall compensation program should emphasize variable compensation elements that have a direct link to company and individual performance.

Objectives of Compensation Philosophy

Our compensation philosophy is designed to meet the following objectives:

• Attracting and retaining high performers;

• Rewarding company and individual performance by providing compensation levels consistent with the level of contribution and degree of accountability;

• Aligning performance measures with our goals and allocating a significant portion of the compensation to incentive compensation in order to drive the performance of our business;

• Basing incentive compensation in part on the satisfaction of company operational metrics (including safety, reliability, operational efficiency and infrastructure readiness) with the goal of motivating performance towards improving the services we provide our customers, and

• Creating value for our equity holders and promoting the long-term performance of the company by strengthening the correlation between the long-term interests of our executives and the interests of our equity holders.

Elements of Compensation

In an effort to achieve our compensation objectives, we have established a compensation program for our executives that principally consists of:

• Base salary;

• Short-term incentives through the opportunity to earn an annual performance bonus pursuant to the Oncor Third Amended and Restated Executive Annual Incentive Plan (Executive Annual Incentive Plan);

• Long-term incentives through (a) the opportunity to purchase equity interests in Investment LLC, granted at the O&C Committee’s discretion pursuant to the 2008 Equity Interests Plan for Key Employees of Oncor Electric Delivery Company LLC and its Affiliates (Equity Interests Plan), (b) until the third quarter of 2012, the opportunity to receive stock appreciation rights (SARs) granted pursuant to the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan (SARs Plan), and (c), effective January 1, 2013, the opportunity to receive grants under the Oncor Electric Delivery Company LLC Long-Term Incentive Plan (Long-Term Incentive Plan);

• Deferred compensation and retirement plans through (a) the opportunity to participate in a 401(k) savings plan (EFH Thrift Plan) sponsored by EFH Corp. and a salary deferral program (Salary Deferral Program) and receive certain company matching contributions, (b) the opportunity to participate in a defined benefit retirement plan and a supplemental retirement plan, and (c) an employer-paid subsidy for health coverage upon the executive’s retirement from Oncor for executives hired prior to January 1, 2002;

• Perquisites and other benefits, including, for executives elected prior to January 1, 2004, the opportunity to participate in a split-dollar life insurance plan (EFH Split-Dollar Life Insurance Plan) sponsored by EFH Corp.; and

• Contingent payments through a change of control policy and a severance plan.

For more information about each of the incentive and other benefit plans available to our executive officers see the compensation tables and the accompanying narratives immediately following “– Compensation Discussion and Analysis.”

Compensation Consultant

In the third quarter of 2012, the O&C Committee engaged Towers Watson, a compensation consultant, to advise and report directly to the O&C Committee on executive compensation issues including a competitive market analyses of executive compensation and independent directors’ compensation. The O&C Committee engaged Towers Watson again in the first quarter of 2013 to update its competitive analysis of executive compensation for certain executives as a result of changes to the scope of responsibilities for certain executives effective January 1, 2013. The O&C Committee also engaged PricewaterhouseCoopers LLP in the third quarter of 2012 as a compensation consultant to advise and report directly to the O&C Committee with respect to Oncor’s long-term incentive programs for employees, specifically the development of a new long-term incentive plan. Towers Watson also provides consulting and other services to Oncor’s human resources department and PricewaterhouseCoopers LLP provides certain information-technology related internal audit services to Oncor.

86

Market Data

While we try to ensure that the greater part of an executive officer’s compensation is directly linked to the executive’s individual performance and Oncor’s financial and operational performance, we also seek to set our executive compensation program in the manner that is competitive with that of our peer group in order to reduce the risk of losing key personnel and to attract high-performing executives from outside our company. In 2012, the O&C Committee assessed compensation of our executives against a number of companies in the transmission/distribution industry and fully integrated utilities. For purposes of the 2012 assessment, Towers Watson completed a competitive market analysis of executive compensation for the O&C Committee in October 2012. This analysis involved national utility industry market survey data targeted at both the 50^th and 75^th percentiles based on compensation information for utilities in the United States with respect to base salary, target cash annual incentives, and long-term incentives, and the resulting target total cash compensation (base salary and target cash annual incentives) and total direct compensation (base salary, target cash annual incentives and long-term incentives). The survey data was aged from the reporting date to January 1, 2013, using an annual rate of 2.8%, which was the average 2012 merit increase for executives based on the market survey data. Market values were also size-adjusted to $3.1 billion in annual revenues.

In addition to the market data for utilities in the national marketplace, Towers Watson also provided publicly available data for a subset of these utilities, a peer group of transmission/distribution utility companies as well as fully integrated utility companies. Towers Watson provided information on total target direct compensation, base salary, annual incentive targets and long-term incentives with respect to the five highest paid executives at each of those companies, along with comparisons of each such executive to the comparable Oncor executive. We include both transmission/distribution utility companies as well as fully integrated utility companies in our peer group because we compete with both for qualified executive personnel. The primary peer group consisted of the following 12 companies:

American Electric Power Co., Inc.	El Paso Electric Co.	OGE Energy Corp.
Consolidated Edison, Inc.	IdaCorp Inc.	Pepco Holdings Inc.
CenterPoint Energy. Inc.	ITC Holdings Corp.	Portland General Electric Co.
Cleco Corp.	Northeast Utilities	TECO Energy, Inc.

In the first quarter of 2013, the O&C Committee commissioned an updated study, relying on the same data and standards as the October 2012 study, solely with respect to two executive officers whose responsibilities were increased effective January 1, 2013 and to include an evaluation of cash-based long-term incentives. In February 2013, the O&C Committee reviewed both the 2012 and updated 2013 Towers Watson studies. The O&C Committee considered both peer group data and the competitive market survey data, along with individual performance and responsibilities, when determining total direct executive compensation, as well as each element of total direct compensation (base salary, annual incentives and long-term incentives). The O&C Committee targeted total direct compensation around the 50th percentile of the competitive market survey group. The 2012 competitive market analysis (as updated in 2013) indicated that aggregate target total direct compensation of our executives was comparable to the 50^th percentile of the competitive market survey group. As a result of the Towers Watson study, which indicated that the base salary of our Senior Vice President and Chief Operating Officer, James A. Greer, was significantly below the 50^th percentile of the competitive market for his position, the O&C Committee increased his base salary to $375,000 in February 2013. No other changes were made to the compensation of our Named Executive Officers as a result of the Towers Watson study.

Compensation Elements

A significant portion of each executive officer’s compensation is variable, at-risk and directly linked to achieving company performance objectives set by the O&C Committee and the alignment with equity owner interests in order to achieve long-term success of our company. Other factors impacting compensation include individual performance, retention risk, and market compensation data. None of these other factors are assigned individual weights, but are considered together. The company has no policies or formula for allocating compensation among the various elements. The following is a description of the principal compensation components provided to our executives.

87

Base Salary

We believe that base salary should be commensurate with the scope and complexity of each executive’s position, the level of responsibility required, and demonstrated performance. We also believe that a competitive level of base salary is required to attract and retain qualified talent.

As part of its review of total direct compensation for our executives officers, the O&C Committee reviews and determines executive officers’ base salaries periodically as it deems appropriate. The periodic review includes the O&C Committee’s review of the most recent analysis of our executive compensation against competitive market data and comparison to our peer group. Our CEO also reviews this analysis, along with the performance and level of responsibility of each executive officer, reporting to him, and makes recommendations to the O&C Committee regarding any salary changes for such executive officers. The O&C Committee may also approve salary increases as a result of an executive’s promotion or a significant change in an executive’s responsibilities. As a result of the Towers Watson study, which indicated that the base salary of our Senior Vice President and Chief Operating Officer, Mr. Greer, was significantly below the 50^th percentile of the competitive market for his position, the O&C Committee increased his base salary in February 2013 to $375,000. No other changes were made to the base salaries of our Named Executive Officers as a result of the Towers Watson study.

Annual Base Salary for Named Executive Officers

The annual base salaries of Named Executive Officers at December 31, 2012 were as follows:

Name	Title	At December 31,  2012
Robert S. Shapard	Chairman of the Board and Chief Executive Officer	$	700,000
David M. Davis	Senior Vice President and Chief Financial Officer	$	375,000
James A. Greer (1)	Senior Vice President and Chief Operating Officer	$	350,000
Brenda L. Jackson	Senior Vice President and Chief Customer Officer	$	290,000
Brenda J. Pulis (2)	Senior Vice President, Asset Management & Engineering	$	300,000

(1) In connection with the O&C Committee’s review of total direct compensation, Mr. Greer’s annual base salary was increased by the O&C Committee from $350,000 to $375,000 in February 2013.

(2) Ms. Pulis served as Senior Vice President, Asset Management & Engineering until December 31, 2012. In connection with her announcement of her intention to retire in 2013, the Asset Management & Engineering group was reorganized and absorbed into two different departments effective January 1, 2013. Ms. Pulis will remain a Senior Vice President until her retirement, assisting in the transition of the Asset Management & Engineering group to the new groups and serving as a senior advisor to our CEO.

Executive Annual Incentive Plan

The O&C Committee and our CEO are responsible for administering the Executive Annual Incentive Plan. The award targets under the plan are established on a company-wide basis and the O&C Committee seeks to set these targets at performance challenging levels. The O&C Committee determines annual target award percentages for executives based on an evaluation of the most recent competitive market analysis conducted by their independent compensation consultant and, with respect to executives other than our CEO, recommendations from our CEO. In making his recommendations to the O&C Committee regarding target award percentages, our CEO assesses the performance goals of each executive reporting to him against the goals of the executive’s business unit and function and reviews the competitive market analysis. Executive Annual Incentive Plan awards are based on a target payout, which is a percentage of the applicable executive’s base salary during the performance period. Target award levels are set as a percentage of a participant’s base salary and are based on target performance of Oncor and individual participant performance. The target payout for each executive is set near the

88

median of executives with similar responsibilities among our competitive market survey group. Elected officers of the Company having a title of vice president or above and other specified key employees are eligible to participate in the Executive Annual Incentive Plan provided they are employed by us for a period of at least three full months during a plan year. Participants who die, become disabled or retire during a plan year are eligible to receive prorated awards under the plan for that plan year provided they completed at least three full months of employment in such plan year. Any awards to executive officers are in the sole discretion of the O&C Committee, and such awards are prorated for the number of months in which the individual was employed by the company.

The aggregate amount of funding for awards payable in any given plan year is determined based on (1) the target award levels of all participants in the Executive Annual Incentive Plan (Aggregate Incentive Pool), (2) achievement of a threshold and target “EBITDA,” consisting of Oncor’s earnings before interest, taxes, depreciation and amortization, excluding securitization revenue and amortization of purchase accounting adjustments, and including such other adjustments as approved by the O&C Committee, which adjustments in 2013 included costs related to the early exercise of SARs under the SARs Plan (as discussed under “— Long-Term Incentives” below), and (3) any additional operational, financial or other metrics that the O&C Committee elects to apply in determining the aggregate amount of awards (Additional Metrics). Based on the level of attainment of these EBITDA and any Additional Metrics targets, the O&C Committee determines an aggregate performance final funding percentage. This final funding percentage is applied to the Aggregate Incentive Pool to provide the initial amount of funds available for awards to participants under the Executive Annual Incentive Plan, which may then be adjusted by individual performance modifiers. The O&C Committee sets Additional Metrics, performance goals, target awards and individual performance modifiers in its discretion, and also has broad discretion to adjust funding percentages and individual awards.

For 2012, the O&C Committee exercised the discretion granted it in the plan and established Additional Metrics based on operational targets relating to (1) a safety metric based on the number of employee injuries using a Days Away, Restricted or Transfer (DART) system, (2) a reliability metric as measured by the System Average Interruption Duration Index (SAIDI), (3) an operational efficiency metric based on the achievement of targeted operation and maintenance expense (O&M) and sales, general and administrative expense (SG&A) levels determined on a per customer cost basis, and (4) an infrastructure readiness metric based on the capital expenditure per three year average kW peak. The purpose of these operational targets, which are based on safety, reliability, operational efficiency and infrastructure readiness metrics, is to promote enhancement of our services to customers. The safety metric is important to our operations because it promotes the health and welfare of our employees. In addition, lowering the number of accidents reduces our operating costs, which in turn contributes to lower rates for our customers. Reliability is measured by SAIDI, which measures the average number of minutes electric service is interrupted per customer in a year. This metric promotes our commitment to minimizing service interruptions to our customers as the lower the SAIDI level for the year, the greater the funding percentage under the Executive Annual Incentive Plan. Since weather can greatly impact reliability and is outside of our control, the reliability metric measures SAIDI on a non-storm basis. The purpose of the operational efficiency metric is to promote lower expenditures relative to customers served, which in turn contributes to lower rates for our customers. The purpose of the infrastructure readiness metric is to promote capital expenditures in line with the previously set capital plan. While this metric discourages exceeding the budget, it also discourages spending that is too far below the capital plan, as we believe expenditures to improve our facilities and other capital expenditures are important to maintaining the quality of and enhancing our services to our customers.

Funding of the Aggregate Incentive Pool is based first on the achievement of stated EBITDA thresholds and targets set by the O&C Committee for that year and then, assuming the EBIDTA threshold is met, the operational funding percentage based on achievement of the Additional Metrics. Incentives are only payable under the Executive Annual Incentive Plan in the event the threshold EBITDA is achieved. If the threshold EBITDA is achieved, then the EBITDA funding percentage is 50%. If the target EBITDA is achieved, the EBITDA funding percentage is 100%. If actual EBITDA exceeds the target EBITDA, then funding equals the operational funding percentage, up to 150%. If actual EBITDA is less than or is equal to the target EBITDA, then funding of the Aggregate Incentive Pool is the lesser of the EBITDA funding percentage or the operational funding percentage. For 2012, our EBITDA for purposes of the Executive Annual Incentive Plan met the threshold EBITDA but did not meet the target EBITDA, resulting in an EBITDA funding percentage of 96.3%. Our operational funding percentage was 130%. As a result, funding of the Aggregate Incentive Pool was based on the lesser of the two percentages, resulting in an Aggregate Incentive Pool funding percentage 96.3%. For more detailed information on the calculation of the 2012 EBITDA funding percentage and the operational funding percentage, see the narrative that follows the Grants of Plan Based Awards table.

89

To calculate an executive officer’s award amount, the final funding percentage is first multiplied by the executive officer’s target award, which is computed as a percentage of actual base salary. Based on the executive officer’s performance, an individual performance modifier is then applied to the calculated award to determine the final incentive payment. An individual performance modifier is based on reviews and evaluations of the executive officer’s performance by the CEO and the O&C Committee (or solely the O&C Committee in the case of our CEO). Factors used in determining individual performance modifiers may include operational measures (including the safety, reliability, operational efficiency and infrastructure readiness metrics discussed above), company objectives, individual management and other goals, specific job objectives and competencies, the demonstration of team building and support attributes and general demeanor and behavior. Each executive officer’s individual performance modifier is set by the O&C Committee within a range determined in its discretion. For 2012 plan year awards, the O&C Committee set this range at plus fifty percent (+50%) to minus fifty percent (-50%). However, the O&C Committee elected not to apply individual performance modifiers to adjust any executive officer’s 2012 Executive Annual Incentive Plan award.

The following table provides a summary of the 2012 targets and actual awards for each Named Executive Officer. All awards under the Executive Annual Incentive Plan are made in the form of lump sum cash payments to participants by March 15 of the year following the plan year to which the award relates.

2012 Annual Incentives (Payable in 2013) for Named Executive Officers

Name	Target Payout Opportunity (% of Salary)			Target Award ($ Value)		Actual Award ($)		Actual Award (% of Target)
Robert S. Shapard		75	%		525,000		505,575		96.3	%
David M. Davis		50	%		187,500		180,563		96.3	%
James A. Greer		50	%		175,000		168,525		96.3	%
Brenda L. Jackson		40	%		116,000		111,708		96.3	%
Brenda J. Pulis		40	%		120,000		115,560		96.3	%

Long-Term Incentives

Our long-term incentive program currently consists of the Equity Interests Plan and the Long-Term Incentive Plan. Until November 2012, the SARs Plan served as an additional long-term incentive component of executive compensation. In November 2012 our board of directors accepted for early exercise all outstanding SARs under the SARs Plan, as discussed in more detail below, and indicated its intention to issue no further SARs awards under the SARs Plan. The Long-Term Incentive Plan was adopted in February 2013, to be effective as of January 1, 2013, as a replacement long-term incentive program to the SARs Plan. The purpose of our long-term incentive program is to promote the long-term financial interests and growth of Oncor by attracting and retaining management and other personnel and key service providers. Our long-term incentive program was developed to enable us to be competitive in our compensation practices and because we believe that equity ownership in Oncor under the Equity Interests Plan and the opportunity to benefit from positive long-term performance of the company under our plans motivate our management to work towards the long-term success of our business and align management’s interests with those of our equity holders. In addition, we believe that certain employment-related conditions and time-based vesting restrictions of these programs, as discussed in more detail below, provide significant retentive value to us.

Equity Interests Plan and Management Investment Opportunity

The Equity Interests Plan allows our board of directors to offer non-employee directors, management and other personnel and key service providers of Oncor the right to invest in Class B membership units of Investment LLC (each, a Class B Interest), an entity whose only assets consist of equity interests in Oncor. As a result, each holder of Class B Interests holds an indirect ownership interest in Oncor. Any dividends received by Investment LLC from Oncor in respect of its membership interests in Oncor are subsequently distributed by Investment LLC to the holders of Class B Interests in proportion to the number of Class B Interests held by such holders.

90

In November 2008 and August 2011, pursuant to the terms of the Equity Interests Plan, our board of directors offered certain officers and key employees the opportunity to invest in Investment LLC and purchase Class B Interests in Investment LLC for the fair market value of Class B Interests on such date, as determined by our board of directors (collectively, the Management Investment Opportunity). In addition to the opportunity to purchase Class B Interests in Investment LLC such officers and key employees also received an amount of SARs based on the aggregate amount invested. SARs received in connection with the Management Investment Opportunity are subject to the terms of the SARs Plan described below. Participants in the Management Investment Opportunity were also given the option to fund any or all of their investment in Investment LLC using funds in their Salary Deferral Program accounts. Any Class B Interests purchased by an executive officer using funds in his or her Salary Deferral Program account are held of record by the Salary Deferral Program for the benefit of such officer.

Pursuant to its limited liability company agreement, Investment LLC must at all times ensure that for each outstanding Class B Interest it issues, Investment LLC holds a corresponding number of units of Oncor’s equity interests. As a result, any future issuances under the Equity Interests Plan will require Investment LLC to purchase from Oncor Holdings additional equity interests of Oncor. Investment LLC has entered into a revolving stock purchase agreement with Oncor Holdings pursuant to which Investment LLC may purchase units of Oncor’s equity interests held by Oncor Holdings in the event Investment LLC proposes to issue additional Class B Interests pursuant to the Equity Interests Plan. However, the aggregate number of equity interests sold by Oncor Holdings pursuant to the revolving stock purchase agreement cannot result in Oncor Holdings owning less than 80% of Oncor’s outstanding equity interests, or 508,000,000 units. At February 12, 2013, Investment LLC may purchase from Oncor Holdings up to an additional 191,492 units of Oncor and issue up to a corresponding number of Class B Interests.

For a more detailed description of the Equity Interests Plan and the Management Investment Opportunity, refer to the narrative that follows the Grants of Plan-Based Awards – 2012 table.

Long-Term Incentive Plan

On February 13, 2013, our board of directors adopted the Long-Term Incentive Plan, to be effective as of January 1, 2013, as a replacement long-term incentive program to the SARs Plan. Our board of directors delegated administration of the Long-Term Incentive Plan to the O&C Committee. Our executive officers and any other key employees of the company or its subsidiaries designated by the O&C Committee are eligible to participate. The plan provides for cash awards to be paid after completion of a performance period based on achievement of certain stated performance goals. A performance period under the Long-Term Incentive Plan is the 36 month period beginning each January 1, unless otherwise determined by the O&C Committee in its sole discretion, and the participants for each performance period shall be determined by the O&C Committee not later than the 90^th day after commencement of such performance period. Performance goals are set forth in each participant’s individual award agreement and consist of one or more specific performance objectives established by the O&C Committee in its discretion within the first 90 days of the applicable performance period. Performance goals may be designated with respect to the company as a whole or one or more operating units, and may also be determined on an absolute basis or relative to internal goals, or relative to levels attained in prior years, or relative to other companies or indices, or as ratios expressing relationships between two or more performance goals. The plan also gives the O&C Committee the discretion to adjust long-term awards to prevent unintended dilution or enlargement as a result of certain extraordinary events. For each performance goal, the O&C Committee may set threshold, target and above-target levels of attainment and the manner of calculating the award amounts at each level (such as a specified dollar amount or a percentage or multiple of base salary). However, the Long-Term Incentive Plan provides that the maximum award payable for a performance period shall not exceed 150% of the target award.

The O&C Committee has determined that the performance goals to be used for all Long-Term Incentive Plan awards will consist of the financial and operational metrics set forth in the form of award letter approved on February 13, 2013. Such metrics could be revised for later plan years in the O&C committee’s discretion via revisions to the form of award letter. The form of award letter provides that funding of each Long-Term Incentive Plan award is contingent first upon Oncor achieving a threshold net income level. If Oncor fails to achieve the stated net income level for the performance period, no award is payable. If Oncor achieves the threshold net income level, the percentage of net income achieved is used to determine a funding trigger percentage. Once a funding trigger percentage is determined, an operational goal percentage is determined based on Oncor’s satisfaction of four operational metrics. The operational goals used for the Long-Term Incentive Plan awards mirrors the operational metrics used for awards under the Executive Annual Incentive Plan, specifically goals relating to (1) a safety metric based on the number of employee injuries using a Days Away, Restricted or Transfer (DART) system,

91

(2) a reliability metric as measured by the System Average Interruption Duration Index (SAIDI), (3) an operational efficiency metric based on the achievement of targeted operation and maintenance expense (O&M) and sales, general and administrative expense (SG&A) levels determined on a per customer cost basis, and (4) an infrastructure readiness metric based on the capital expenditure per three year average kW peak. The O&C Committee will set threshold, target and stretch levels for each operational metric, and achievement of those levels results in funding for a specific metric of 50%, 100% and 150%, respectively. Once threshold has been achieved, actual results in between each level results in a funding percentage equal to the percentage of the target achieved. Based on the weighting for each operational metric, an aggregate weighted average of operational goal percentage is determined. The amount of each Long-Term Incentive Plan award is then determined based on the product of (i) the funding trigger percentage, multiplied by (ii) the weighted average of stated operational goal percentages, multiplied by (iii) the target opportunity dollar amount stated in each individual award letter.

Under the terms of the plan, the O&C Committee must measure and certify the levels of attainment of performance goals within 90 days following the completion of the performance period. Any awards for such period shall be paid on or about April 1 following the performance period, but in no event later than the end of the calendar year following the end of the applicable performance period. At the discretion of the O&C Committee, individuals newly hired or promoted into positions that qualify for the Long-Term Incentive Plan may begin participating in the plan for one or more open performance periods on a full or pro-rata basis upon the date of hire or promotion.

The Long-Term Incentive Plan encourages retention of executive officers and key employees by stipulating performance periods of generally 36 months. Participants must be continuously employed by us through the last day of the performance period in order to receive a long-term incentive award for that performance period. If a participant is employed by us on the last day of the performance period but his/her employment terminates for any reason other than by us for cause prior to the payment of the award for that performance period, the participant will be entitled to receive payment of the award. In the event a participant is terminated by us for cause, though, the participant will forfeit any unpaid Long-Term Incentive Plan award. For purposes of the Long-Term Incentive Plan, “cause” has the same meaning as defined in any employment agreement or change-in-control agreement of such participant in effect at the time of termination of employment. If there is no such employment or change-in-control agreement, “cause” means the indictment on or pleading guilty or no contendere to, a felony or misdemeanor involving moral turpitude of such participant, or upon the participant, in the carrying out his or her duties to the company, (i) engaging in conduct that causes a breach of his/her fiduciary duties to us, our subsidiaries or our investors, (ii) committing an act of gross negligence, or (iii) committing gross misconduct resulting in material economic harm to us. If a participant’s employment is terminated for reasons other than death, disability, retirement or following a change in control, all of such participant’s outstanding and unpaid Long-Term Incentive Plan awards shall be cancelled. Upon a termination due to death, disability or retirement, for each outstanding Long-Term Incentive Plan unpaid award, the participant (or his/her beneficiary in the case of death) shall be entitled to a prorated award based on the number of days the participant was employed during the performance period and the actual achievement the performance goals. In the event of a termination following a change in control, a participant shall be entitled to receive, within 60 days following the separation from service, an award equal to the product of (i) a fraction, the numerator of which is the number of days in the performance period up to and including the date of the separation of service and the denominator of which is the number of days in the entire performance period, and (ii) the Long-Term Incentive Plan award for such performance period based on target performance.

For purposes of the Long-Term Incentive Plan, a “change in control” means, in one or a series of related transactions, (i) the sale of all or substantially all of the consolidated assets or capital stock of EFH Corp., Oncor Holdings, or Oncor to a person (or group of persons acting in concert) who is not an affiliate of any member of the Sponsor Group; (ii) a merger, recapitalization or other sale by EFH Corp., any member of the Sponsor Group or their affiliates, to a person (or group of persons acting in concert) that results in more than 50% of EFH Corp.’s common stock (or any resulting company after a merger) being held by a person (or group of persons acting in concert) that does not include any member of the Sponsor Group or any of their respective affiliates; or (iii) a merger, recapitalization or other sale of common stock by EFH Corp., any member of the Sponsor Group or their affiliates, after which the Sponsor Group owns less than 20% of the common stock of, and has the ability to appoint less than a majority of the directors to the board of directors of, EFH Corp. (or any resulting company after a merger); and with respect to any of the events described in clauses (i) and (ii) above, such event results in any person (or group of persons acting in concert) gaining control of more seats on the board of directors of EFH Corp. than the Sponsor Group. However, the Long-Term Incentive Plan also provides that should a change in control occur under clauses (i) through (iii) above with respect to the assets or capital stock of EFH Corp., a Change in control will not be deemed to have occurred unless such change in control would result in the material amendment or interference with the Separateness undertakings set forth under Section 10(i)(vi) of our Limited Liability Company Agreement, or would adversely change or modify the definition of an independent director in our Limited Liability Company Agreement.

92

As the administrator of the Long-Term Incentive Plan, the O&C Committee has the authority to prescribe, amend and rescind rules and regulations relating to the plan, determine the terms and conditions of any awards and make all other determinations deemed necessary or advisable for the administration of the plan. The O&C Committee has broad discretion under the plan and may delegate to one or more officers of the company the authority to grant Long-Term Incentive Plan awards to employees who are not executive officers. Our board of directors may at any time terminate, alter, amend or suspend the Long-Term Incentive Plan and any awards granted pursuant to it, subject to certain limitations. In the event of a change in control, our board of directors may, in its discretion, terminate the plan and cancel all outstanding and unpaid awards, except that in the event of a termination of the plan in connection with a change in control, participants shall be entitled, within 90 days following the termination of the plan, to payment of each outstanding and unpaid award in an amount equal to the product of: (i) a fraction, the numerator of which is the number of days in the performance period up to and including the date of the separation of service and the denominator of which is the number of days in the entire performance period, and (ii) the Long-Term Incentive Plan award for such performance period based on target performance.

Stock Appreciation Rights

The O&C Committee adopted and implemented the SARs Plan in 2008 and from 2008 to 2011 awarded 14,478,219 SARs pursuant to the SARs Plan to certain employees of Oncor, including the Named Executive Officers. SARs issued under the plan are subject to certain time-vesting and performance-vesting conditions, and are only exercisable upon the occurrence of certain events. These events generally include a change of control, an EFH realization event (as defined in the SARs Plan), a liquidity event or the achievement of certain financial returns as described in the SARs Plan. The SARs Plan also grants the board of directors and the O&C Committee the right to accelerate vesting and exercisability of a participant’s award under the SARs Plan at any time in their respective discretion. Under the SARs Plan, SARs may only be exercised for cash, in an amount equal to the product of (1) the difference between the fair market value per Oncor equity interest on the date giving rise to the payment and the fair market value as of the date of the award grant, and (2) the number of SARs exercised by the participant. In addition, the SARs Plan provides that dividends that are paid in respect of Oncor membership interests while the SARs are outstanding are credited to the SARs holder’s account as if the SARs were units of Investment LLC, payable upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control.

During 2012, the O&C Committee evaluated whether, in light of future business plans and our overall compensation structure, it would be appropriate to wind down the SARs Plan and create a new long term incentive plan to compensate management. To that end, the O&C Committee (i) worked with management to develop equitable scenarios under which management would have an opportunity to exercise their SARs, (ii) engaged outside advisors to assist in the development and execution of such scenarios, and (iii) engaged PricewaterhouseCoopers to develop a new long-term incentive plan to replace the SARs Plan for purposes of long-term incentive compensation after 2012.

In 2012, our board of directors offered all participants in the SARs Plan the opportunity to participate in an early exercise of all outstanding SARs (vested and unvested) issued under the SARs Plan (SARs Exercise Opportunity), pursuant to the provision of the SARs Plan that permits the board to accelerate the vesting and exercisability of SARs. At the time of the SARs Exercise Opportunity, 90% of the aggregate SARs granted under the program were vested (only the tranche performance-based SARs eligible to vest for 2012 were unvested as of the time of the SARs Exercise Opportunity). All participants in the SARs Plan accepted the SARs Exercise Opportunity in November 2012, and as a result all outstanding SARs under the SARs Plan were exercised. While the SARs Plan remains in effect, the O&C Committee has indicated that it does not currently plan to issue any additional SARs under the SARs Plan. As discussed above, the Long-Term Incentive Plan was developed to replace the SARs Plan as a long-term incentive component of executive compensation.

The SARs Exercise Opportunity entitled each participant in the SARs Plan, including our Named Executive Officers, to: (1) an exercise payment (Exercise Payment) equal to the number of SARs exercised multiplied by the difference between $14.54 and the base price of the SARs ($10.00 for each Named Executive Officer); and (2) the accrual of interest on all dividends declared to date with respect to the SARs, and no further dividend accruals. As a result of the SARs Exercise Opportunity, the Named Executive Officers received the following Exercise Payments, less withholding for applicable taxes: Mr. Shapard, $17,025,000; Mr. Davis, $2,724,000; Mr. Greer, $3,541,200; Ms. Jackson, $3,541,200; and Ms. Pulis, $4,449,200. Additionally, we began to accrue interest for the Named Executive on the following amounts of dividends: Mr. Shapard, $5,109,935; Mr. Davis, $817,590; Mr. Greer, $1,062,866; Ms. Jackson, $1,062,866; and Ms. Pulis, $1,335,396.

93

In addition, certain Named Executive Officers, other than Ms. Jackson, who had previously informed management of her intention to retire in 2013, agreed to defer payment of a portion of their Exercise Payments. After the withholding of all applicable taxes, Messrs. Shapard, Davis, Greer and Ms. Pulis agreed to defer from his/her Exercise Payments the following amounts, to be paid at a later date as described below: Mr. Shapard, $2,957,400; Mr. Davis, $473,184; Mr. Greer, $615,139 and Ms. Pulis, $772,867. These Named Executive Officers agreed to defer such amounts until the earlier of November 7, 2016 or the occurrence of an event triggering SAR exercisability. These events generally include a change of control, an EFH realization event, a liquidity event or the achievement of certain financial returns as described in the SARs Plan.

For a more detailed discussion of SARs and the SARs Plan, refer to the narrative that follows the Option Exercises – 2012 table.

Deferred Compensation and Retirement Plans

Our executive compensation package includes the ability to participate in the Salary Deferral Program, the EFH Thrift Plan, the Retirement Plan and the Supplemental Retirement Plan and for executives hired before January 1, 2002, subsidized retiree health care coverage. We believe that these programs, which are common among companies in the utility industry, are important to attract and retain qualified executives. Although some of these plans are sponsored by EFH Corp., Oncor is directly responsible for the costs of any matching awards, premiums and other payments relating to Oncor employees pursuant to these programs.

Salary Deferral Program

Oncor executive officers are eligible to participate in a Salary Deferral Program that allows employees to defer a portion of their salary and annual incentive award and to receive a matching award based on their salary deferrals. Executives can currently defer up to 50% of their base salary and up to 85% of any annual incentive award. At the executive officer’s option the deferral period can be set for seven years, until retirement or a combination of both. Oncor generally matches 100% of deferrals up to 8% of salary deferred under the program. Oncor does not match deferred annual incentive awards. Matching contributions vest at the earliest of seven years after the deferral date, executive’s retirement or a change in control of Oncor (as defined in the Salary Deferral Program). The program encourages employee retention as, generally, participants who terminate their employment with us prior to the seven year vesting period forfeit our matching contribution to the program.

Participants in the Management Investment Opportunity were also given the option to fund any or all of their investment in Investment LLC using funds in their Salary Deferral Program accounts. The Salary Deferral Program is the record holder of Class B Interests purchased by executives using funds in their Salary Deferral Program accounts.

Refer to the narrative that follows the Nonqualified Deferred Compensation table below for a more detailed description of the Salary Deferral Program.

Thrift Plan

Under the EFH Thrift Plan, all eligible employees of EFH Corp. and any of its participating subsidiaries, including Oncor, may contribute a portion of their regular salary or wages to the plan. Under the EFH Thrift Plan, Oncor matches a portion of an employee’s contributions. This matching contribution is 75% of the employee’s contribution up to the first 6% of the employee’s salary for employees covered under the traditional defined benefit component of the Retirement Plan, and 100% of the employee’s contribution up to 6% of the employee’s salary for employees covered under the cash balance component of the Retirement Plan. All matching contributions are invested in EFH Thrift Plan investments as directed by the participant and are immediately vested.

94

Retirement Plan

All Oncor employees are eligible to participate in a retirement plan, which is qualified under applicable provisions of the Code. Until January 1, 2013, Oncor was a participating employer in the EFH Retirement Plan. In August 2012, EFH Corp. announced various changes to the EFH Retirement Plan, including splitting off into a new plan all of the assets and liabilities associated with Oncor employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Effective January 1, 2013, Oncor assumed sponsorship of the new plan, which is referred to in this Annual Report as the Oncor Retirement Plan. See Footnote 10 to Financial Statements for additional information on the EFH Retirement Plan and the Oncor Retirement Plan. Since the benefits to Oncor employees are identical under the EFH Retirement Plan and the Oncor Retirement Plan, we refer to the plans collectively as the “Retirement Plan.”

The Retirement Plan contains both a traditional defined benefit component and a cash balance component. Effective January 1, 2002, the defined benefit plan changed from a traditional final average pay design to a cash balance design. This change was made to better align the retirement program with competitive practices. All participants were extended an opportunity to remain in the traditional program component or transition to the cash balance component. Messrs. Davis and Greer and Mses. Jackson and Pulis elected to remain in the traditional program.

All employees employed after January 1, 2002 are eligible to participate only in the cash balance component. As a result, Mr. Shapard is covered only under the cash balance component. For a more detailed description of the Retirement Plan, refer to the narrative that follows the Pension Benefits table.

Supplemental Retirement Plan

Oncor executives participate in the Supplemental Retirement Plan. The Supplemental Retirement Plan provides for the payment of retirement benefits that:

• Would otherwise be capped by the Code’s statutory limits for qualified retirement plans;

• Include Executive Annual Incentive Plan awards in the definition of earnings (for participants in the traditional program component only), and/or

• Oncor is obligated to pay under contractual arrangements.

For a more detailed description of the Supplemental Retirement Plan, please refer to the narrative that follows the Pension Benefits table below.

Retiree Health Care

Employees hired by Oncor (or EFH Corp’s predecessor) prior to January 1, 2002 are generally entitled to receive an employer-paid subsidy for retiree health care coverage upon their retirement from Oncor. As such, Messrs. Davis and Greer, and Mses. Pulis and Jackson will be entitled to receive a subsidy from Oncor for retiree health care coverage upon their retirement from Oncor. Mr. Shapard was hired after January 1, 2002 and is not eligible for the employer subsidy.

Perquisites and Other Benefits

Perquisites provided to our executive officers are intended to serve as part of a competitive total compensation program and to enhance our executives’ ability to conduct company business. These benefits include financial planning, a preventive physical health exam, reimbursements for certain business-related country club and/or luncheon club membership costs. For a more detailed description of the perquisites, refer to footnote 6 in the Summary Compensation Table below.

The following is a summary of benefits offered to our executive officers that are not available to all employees:

Executive Financial Planning: All executive officers are eligible to receive executive financial planning services. These services are intended to support them in managing their financial affairs, which we consider especially important given the high level of time commitment and performance expectation required of our executives. Furthermore, these services help ensure greater accuracy and compliance with individual tax regulations.

Executive Physical Health Exam: All executive officers are also eligible to receive an annual physical examination. We recognize the importance of the health of our senior management team and the vital leadership role they play in directing and operating the company. The executive officers are important assets of the company and this benefit is designed to help ensure their health and long-term ability to serve our equity holders.

95

Country Club/Luncheon Club Membership: Certain executive officers are entitled to reimbursement of country club or luncheon club memberships if the company determines that a business need exists for such executive’s memberships, as such clubs provide those officers with a setting for cultivating business relationships and interaction with key community leaders and officials.

Split-Dollar Life Insurance: As a participating subsidiary in the EFH Corp. Split-Dollar Life Insurance Program (Split-Dollar Life Insurance Program), split-dollar life insurance policies were purchased for eligible executives of Oncor. The eligibility provisions of this program were modified in 2003 so that no new participants were added after December 31, 2003. Accordingly, Messrs. Shapard, Davis, and Greer are not eligible to participate in the Split-Dollar Life Insurance Program. The death benefits of participants’ insurance policies are equal to two, three or four times their annual EFH Split-Dollar Life Insurance Program compensation, depending on their executive category. Individuals who first became eligible to participate in the Split-Dollar Life Insurance Program after October 15, 1996, vested in the insurance policies issued under the Split-Dollar Life Insurance Program over a six-year period. Oncor pays the premiums for the policies and has received a collateral assignment of the policies equal in value to the sum of all of its insurance premium payments. Although the Split-Dollar Life Insurance Program is terminable at any time, it is designed so that if it is continued, EFH Corp./Oncor will fully recover all of the insurance premium payments covered by the collateral assignments either upon the death of the participant or, if the assumptions made as to policy yield are realized, upon the later of 15 years of participation or the participant’s attainment of age 65. At the Merger, the Split-Dollar Life Insurance Program was amended to freeze the death benefits at the then current level.

Spouse Travel Expenses: From time to time we pay for an executive officer’s spouse to travel with the executive officer when taking a business trip, if their presence contributes to the business purpose.

In addition to the benefits described above, Oncor offers its executive officers the ability to participate in benefit plans for medical, dental and vision insurance, group term life insurance and accidental death and disability, which are generally made available to all employees at the company.

Individual Named Executive Officers Compensation

Oncor has not entered into employment agreements with any of the Named Executive Officers.

CEO Compensation

Robert S. Shapard

The following is a summary of Mr. Shapard’s individual compensation for 2012.

Base Salary: Mr. Shapard’s base salary as Chairman and CEO continued unchanged in 2012 at $700,000.

Annual Incentive: In 2013, the O&C Committee awarded Mr. Shapard $505,575 pursuant to the Executive Annual Incentive Plan, reflecting the result of Oncor’s 2012 performance, as previously discussed, as well as Mr. Shapard’s overall leadership of the company in 2012. In particular, the O&C Committee considered his leadership of the company through several operational and financial matters, including (i) our construction of transmission and distribution projects and filings with the PUCT with respect to these projects, (ii) our development and maintenance of customer relationships and community involvement in our service territory, and (iii) our financial ability to plan, construct and operate one of the largest transmission and distribution utilities in the country.

Long-Term Incentives: Mr. Shapard did not receive new long-term incentives in 2012, but Mr. Shapard did elect to participate in the SARs Exercise Opportunity with respect to his outstanding SARs. As a result, Mr. Shapard was entitled to a lump sum pre-tax payment of $17,025,000, of which he agreed to defer $2,957,400.

96

Compensation of Other Named Executive Officers

David M. Davis

The following is a summary of Mr. Davis’s individual compensation for 2012.

Base Salary: Mr. Davis’ base salary in 2012 as Senior Vice President and Chief Financial Officer continued unchanged at $375,000.

Annual Incentive: In 2013, the O&C Committee awarded Mr. Davis $180,563 pursuant to the Executive Annual Incentive Plan, reflecting the result of Oncor’s 2012 performance, as previously discussed, as well as Mr. Davis’s individual performance in 2012. Specifically, the O&C Committee and the CEO considered his management of the company’s financial systems, operations and initiatives, including the maintenance of planning, budgeting, accounting, and treasury functions and his management of the liquidity of Oncor’s maintenance and construction programs.

Long-Term Incentives: Mr. Davis did not receive new long-term incentives in 2012, but Mr. Davis did participate in the SARs Exercise Opportunity with respect to his outstanding SARs. As a result, Mr. Davis was entitled to a lump sum pre-tax payment of $2,724,000, of which he agreed to defer $473,184.

James A. Greer

The following is a summary of Mr. Greer’s individual compensation for 2012.

Base Salary: Mr. Greer’s base salary as Senior Vice President, Chief Operating Officer continued unchanged in 2012 at $350,000.

Annual Incentive: In 2013, the O&C Committee awarded Mr. Greer $168,525 pursuant to the Executive Annual Incentive Plan, reflecting the result of Oncor’s 2012 performance, as previously discussed, as well as Mr. Greer’s individual performance in 2012 overseeing the operations of Oncor’s entire transmission and distribution system, one of the largest such systems in the country,

Long-Term Incentives: Mr. Greer did not receive new long-term incentives in 2012, but he did participate in the SARs Exercise Opportunity with respect to his outstanding SARs. As a result, Mr. Greer was entitled to a lump sum pre-tax payment of $3,541,200, of which he agreed to defer $615,139.

Brenda L. Jackson

The following is a summary of Ms. Jackson’s individual compensation for 2012.

Base Salary: Ms. Jackson’s base salary as Senior Vice President and Chief Customer Officer continued unchanged in 2012 at $290,000.

Annual Incentive: In 2013, the O&C Committee awarded Ms. Jackson $111,708 pursuant to the Executive Annual Incentive Plan, reflecting the result of Oncor’s 2012 performance, as previously discussed, as well as Ms. Jackson’s individual performance in 2012 overseeing all of Oncor’s customer operations.

Long-Term Incentives: Ms. Jackson did not receive new long-term incentives in 2012, but she did participate in the SARs Exercise Opportunity with respect to her outstanding SARs. As a result, Ms. Jackson was entitled to a lump sum pre-tax payment of $3,541,200. As Ms. Jackson had previously announced her intention to retire in 2013, she did not defer any portion of her SARs exercise payments.

Brenda J. Pulis

The following is a summary of Ms. Pulis’ individual compensation for 2012.

Base Salary: Ms. Pulis’ base salary as Senior Vice President continued unchanged in 2012 at $300,000.

97

Annual Incentive: In 2013, the O&C Committee awarded Ms. Pulis $115,560 pursuant to the Executive Annual Incentive Plan, reflecting the result of Oncor’s 2012 performance, as previously discussed, as well as Ms. Pulis’ individual performance in 2012 overseeing the development of strategies, policies and plans for optimizing the value and performance of electric delivery systems and related assets.

Long-Term Incentives: Ms. Pulis did not receive new long-term incentives in 2012, but she did participate in the SARs Exercise Opportunity with respect to her outstanding SARs. As a result, Ms. Pulis was entitled to a lump sum pre-tax payment of $4,449,200, of which she agreed to defer $772,867.

Contingent Payments

Change in Control Policy

Oncor makes available a change in control policy (the Change in Control Policy) for its eligible executives. The purpose of the Change in Control Policy is to provide the payment of transition benefits to eligible executives if:

• Their employment with the company or a successor is terminated within twenty-four months following a change in control of the company; and

• They:

• are terminated without cause, or

• resign for good reason due to a reduction in salary or a material reduction in the aggregate level or value of benefits for which they are eligible.

The terms “change in control,” “without cause” and “good reason” are defined in the Change in Control Policy.

We believe these payments, to be triggered upon meeting the criteria above, provide incentive for executives to fully consider potential changes that are in the best interest of Oncor and our equity holders, even if such changes would result in the executives’ termination. We also believe it is important to have a competitive change in control program to attract and retain the caliber of executives that our business requires and to foster an environment of relative security within which we believe our executives will be able to focus on achieving company goals. Refer to the “Potential Payments upon Termination” for detailed information about payments and benefits that our executive officers are eligible to receive under the Change in Control Policy.

Severance Plan

Oncor also makes available a Severance Plan (the Severance Plan) to provide certain benefits to eligible executives. The purpose of the Severance Plan is to provide benefits to eligible executives who are not eligible for severance pursuant to another plan or agreement (including an employment agreement) and whose employment is involuntarily terminated for reasons other than:

• Cause (as defined in the Severance Plan);

• Disability of the employee, if the employee is a participant in our long-term disability plan, or

• A transaction involving the company or any of its affiliates in which the employee is offered employment with a company involved in, or related to, the transaction.

We believe it is important to have a severance plan in place to attract and retain the caliber of executives that our business requires and to foster an environment of relative security within which we believe our executives will be able to focus on achieving company goals. Refer to the “Potential Payments upon Termination” for detailed information about payments and benefits that our executive officers are eligible to receive under the Severance Plan.

98

Accounting and Tax Considerations

Accounting Considerations

Based on accounting guidance for compensation arrangements, no compensation expense is recognized with respect to Class B Interests issued pursuant to the Management Investment Opportunity as the units were purchased by participants for fair value.

Since SARs are issued with a base price of the then-current fair market value of our equity interests, no compensation expense is recognized for SARs until a condition under which the SARs would become exercisable becomes probable at a point in time when the fair market value of our equity interests exceeds the base price. In November 2012, early exercise was permitted by our board of directors pursuant to the provision of the SARs Plan that permits the board to accelerate the vesting and exercisability of SARs and we accepted the early exercise of all outstanding SARs (both vested and unvested) issued to date pursuant to the terms of the SARs Exercise Opportunity. As a result of the 2012 SARs Exercise Opportunity, we recognized as compensation the entire payment to each current executive officer to settle their outstanding SARs, including the deferred portion paid directly to an external trust.

Under the SARs Plan, amounts equal to dividends that are paid in respect of Oncor membership interests while the SARs are outstanding are credited to the SARs holder’s account as if the SARs were units of Oncor, payable upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control. As payments under the dividend provision are not contingent upon a future liquidity event, the liability related to the declared dividends is accrued as vested. For accounting purposes, the liability is discounted based on an employee’s expected retirement date.

Income Tax Considerations

Section 162(m) of the Code limits the tax deductibility by a publicly held company of compensation in excess of $1 million paid to the CEO or any other of its three most highly compensated executive officers other than the principal financial officer. Because we are a privately-held limited liability company, Section 162(m) will not limit the tax deductibility of any executive compensation for 2012.

The O&C Committee administers our compensation programs with the good faith intention of complying with Section 409A of the Code.

99

The information contained herein under the heading “Organization and Compensation Committee Report” is not to be deemed to be “soliciting material” or “filed” with the SEC pursuant to Section 407(e)(5) of SEC Regulation S-K.

Organization and Compensation Committee Report

The Organization and Compensation Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth in this Form 10-K. Based on such review and discussions, the committee recommended to the board of directors that the Compensation Discussion and Analysis be included in this Form 10-K.

Organization and Compensation Committee

Richard W. Wortham III, Chair

Thomas M. Dunning

Jeffrey Liaw

Steven J. Zucchet

Compensation Committee Interlocks and Insider Participation

Two of our O&C Committee members, Mr. Liaw and Mr. Zucchet, are not classified as independent directors under the standards set forth in the Limited Liability Company Agreement. Mr. Liaw is a former principal of TPG, a member of the Sponsor Group, and is a manager of Texas Energy Future Capital Holdings LLC, the sole general partner of Texas Holdings. Mr. Liaw was appointed to the board of directors by Oncor Holdings, which is a subsidiary of EFH Corp. Mr. Liaw also served as a member of the EFH Corp. board of directors until December 31, 2012. Mr. Zucchet is employed by Borealis Infrastructure Management, Inc., a beneficial owner of Texas Transmission, and serves as an officer and director of Texas Transmission’s parent company. Mr. Zucchet was appointed to the board of directors by Texas Transmission. For a description of the ability of Oncor Holdings and Texas Transmission to appoint directors, see “Directors, Executive Officers and Corporate Governance – Director – Director Appointments.” For a description of Oncor related party transactions involving the Sponsor Group, EFH Corp. and Texas Transmission, see “Certain Relationships and Related Transactions, and Director Independence.”

No member of the O&C Committee is or has ever been one of our officers or employees. No interlocking relationship exists between our executive officers and the board of directors or compensation committee of any other company.

100

The following table provides information, for the fiscal years ended December 31, 2012, 2011, and 2010 regarding the aggregate compensation paid to our Named Executive Officers.

Summary Compensation Table

Name and Principal Position	Year		Salary ($)		Non-Equity Incentive Plan Compensation ($)(3)		Change in Pension Value and Non- qualified Deferred Compensation Earnings ($)(4)(5)(6)		All Other Compensation ($)(7)		Total ($)
Robert S. Shapard Chairman of the Board and Chief Executive		2012 2011 2010		700,000 700,000 654,167		505,575 627,165 563,728		285,531 99,087 129,705		18,486,361 972,443 1,333,753		19,977,467 2,398,695 2,681,353
David M. Davis Senior Vice President and Chief Financial Officer		2012 2011 2010		375,000 352,083 304,167		180,563 210,299 174,744		559,203 376,526 300,382		2,996,698 192,316 221,584		4,111,464 1,131,224 1,000,877
James A. Greer Senior Vice President and Chief Operating Officer		2012		350,000		168,525		556,772		3,874,877		4,950,174
Brenda L. Jackson (1) Senior Vice President and Chief Customer Officer		2012 2011 2010		290,000 276,250 258,500		111,708 132,003 118,807		559,390 475,628 411,946		3,879,628 245,501 309,937		4,840,726 1,129,382 1,099,190
Brenda J. Pulis (2) Senior Vice President		2012		300,000		115,560		486,772		4,853,957		5,756,289

(1) Ms. Jackson has announced her intention to retire effective July 1, 2013 and will serve as Senior Vice President and Chief Customer Officer until such date.

(2) Ms. Pulis served as Senior Vice President, Asset Management & Engineering until December 31, 2012. In connection with her announcement of her intention to retire in 2013, the Asset Management & Engineering group was reorganized and absorbed into two different departments effective January 1, 2013. Ms. Pulis will remain a Senior Vice President until her retirement, serving as a senior advisor to the CEO.

(3) Amounts reported as “Non-Equity Incentive Plan Compensation” were earned by the executive in the respective year and represent amounts related to awards for such years pursuant to the Executive Annual Incentive Plan. Awards under the Executive Annual Incentive Plan for any given year are paid in March of the following year.

(4) Amounts reported under this column reflect the aggregate change in actuarial value at December 31 of the specified year as compared to December 31 of the previous year of each executive’s accumulated benefits under the Retirement Plan and the Supplemental Retirement Plan. For a more detailed description of these plans, see “– Compensation Discussion and Analysis – Compensation Elements – Deferred Compensation and Retirement Plans” and the narrative that follows the Pension Benefits table below. With respect to the Retirement Plan, Messrs. Davis and Greer and Mses. Jackson and Pulis are covered under the traditional defined benefit component and Mr. Shapard is covered under the cash balance component. There are no above-market or preferential earnings for nonqualified deferred compensation.

(5) Amount reported for Mr. Shapard for 2012 largely reflects increases in his Retirement Plan and Supplemental Retirement Plan accumulated benefits as a result of $218,771 of non-compensation transfers into his accounts under such plans. Through 2012, Mr. Shapard accumulated benefits in two EFH Corp.-sponsored retirement plans as a result of his service as an employee of EFH Corp.’s predecessor prior to joining Oncor. Those benefits were paid solely by EFH Corp. In connection with various changes made by EFH Corp. to its retirement plans in 2012, EFH Corp. transferred $75,906 from a supplemental retirement plan sponsored by EFH Corp. into Mr. Shapard’s account in the Retirement Plan and $142,865 from a second EFH Corp.-sponsored retirement plan into Mr. Shapard’s account in the Supplemental Retirement Plan.

101

(6) Amount reported for Mr. Davis at December 31, 2012 largely reflects an increase in the actuarial value of his Retirement Plan and Supplemental Retirement Plan accumulated benefits due to his turning age 55. Early retirement is available under both plans to participants upon their attainment of age 55 and achievement of 15 years of accredited service, and Mr. Davis fulfilled such requirements in 2012.

(7) Amounts reported as “All Other Compensation” for 2012 are attributable to the executive’s receipt of compensation as described in the following table:

2012 All Other Compensation Components for Named Executive Officers

Name	EFH  Thrift Plan Company Match ($)		Salary Deferral Program Company Match ($) (a)		Split- Dollar Life Insurance Program Payments ($) (b)		SARs Plan payments and accruals ($)(c)		Perquisites ($) (d)		Total ($)
Robert S. Shapard		15,000		56,000		—		18,376,641		38,720		18,486,361
David M. Davis		11,250		30,000		—		2,940,262		15,186		2,996,698
James A. Greer		11,250		28,000		—		3,822,341		13,286		3,874,877
Brenda L. Jackson		11,250		23,200		8,476		3,822,341		14,361		3,879,628
Brenda J. Pulis		11,250		24,000		1,944		4,802,429		14,334		4,853,957

(a) Amounts represent company matching amounts under the Salary Deferral Program. Refer to the narrative that follows the Nonqualified Deferred Compensation table below for a more detailed description of the Salary Deferral Program and the matching formula.

(b) Amounts represent premium and tax gross-up payments pursuant to the Split-Dollar Life Insurance Program. Messrs. Shapard, Davis and Greer are not eligible to participate in the program because the program was frozen to new participants prior to their qualifying for participation. Amounts in this column for Mses. Jackson and Pulis represent the aggregate amount of payments and attributions pursuant to the program and tax regulations. Because premium payments for Mses. Jackson and Pulis were made on a split-dollar life insurance basis during 2012, interest on the plan-to-date cumulative premiums was taxable to Mses. Jackson and Pulis, and Oncor provided tax gross-up payments to offset the effect of such taxes. The amounts reported attributable to the interest on the aggregate amount of premiums totaled $6,234 for Ms. Jackson and $1,430 for Ms. Pulis.The amounts reported also include tax gross-ups provided to offset the effect of taxes on the interest during 2012 totaling $2,242 for Ms. Jackson and $514 for Ms. Pulis. For a discussion of the Split-Dollar Life Insurance Program, see “– Compensation Discussion and Analysis – Compensation Elements – Perquisites and Other Benefits.”

(c) Amounts reported under this column reflect certain payments and accruals with respect to the SARs Plan set forth in the following table. For more information regarding the SARs Plan and these payments and accruals, see “– Compensation Discussion and Analysis – Compensation Elements – Long-Term Incentives – Stock Appreciation Rights.”

102

2012 SARs Plan Payments and Accruals

Name	November 2012 SARs Exercise Opportunity Exercise Payment ($) (i)		SARs Plan 2012 Dividend Accrual ($)(ii)		SARs Exercise Opportunity Interest Accrual on Dividends ($)(iii)		Total ($)
Robert S. Shapard		17,025,000		1,328,476		23,165		18,376,641
David M. Davis		2,724,000		212,556		3,706		2,940,262
James A. Greer		3,541,200		276,323		4,818		3,822,341
Brenda L. Jackson		3,541,200		276,323		4,818		3,822,341
Brenda J. Pulis		4,449,200		347,175		6,054		4,802,429

(i) Amounts reflect pre-tax payments received in connection with the November 2012 SARs Exercise Opportunity under the SARs Plan at an exercise price of $14.54 per SAR, as discussed in more detail under “– Compensation Discussion and Analysis – Compensation Elements – Long-Term Incentives – Stock Appreciation Rights.” Amounts include the following amounts that certain Named Executive Officers agreed to defer until the earlier of November 7, 2016 or an event that would have triggered SARs exercisability under the SARs Plan: Mr. Shapard, $2,957,400; Mr. Davis, $473,184; Mr. Greer, $615,139; and Ms. Pulis, $772,867.

(ii) Under the SARs Plan, dividends that are paid in respect of Oncor membership interests while the SARs are outstanding are credited to the SARs holder’s account as if the SARs were units of Investment LLC, payable upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control. Amounts in this column represent the dividend accrual for 2012.

(iii) As discussed under “Compensation Discussion and Analysis – Compensation Elements – Long-Term Incentives – Stock Appreciation Rights,” in connection with the SARs Exercise Opportunity participants agreed that no further dividends would accrue, but that interest would be paid on dividends accrued to date. Amounts in this column reflect such interest accruals through December 31, 2012.

(d) Amounts reported under this column represent the aggregate amount of perquisites received by each Named Executive Officer. Those perquisites are detailed in the following table. Amounts reported below represent the actual cost to Oncor for the perquisites provided. For a discussion of the perquisites received by our executive officers, see “– Compensation Discussion and Analysis – Compensation Elements – Perquisites and Other Benefits.”

2012 Perquisites for Named Executive Officers

Name	Financial Planning ($)		Executive Physical ($)		Country Club and/or Luncheon Club Dues ($)		Spouse Travel ($) (i)		Other ($) (ii)		Total ($)
Robert S. Shapard		10,520		2,674		12,152		7,984		5,390		38,720
David M. Davis		9,230		1,930		2,533		1,493		—		15,186
James A. Greer		9,230		2,132		—		1,924		—		13,286
Brenda L. Jackson		—		—		14,361		—		—		14,361
Brenda J. Pulis		9,230		—		5,104		—		—		14,334

(i) Amounts in this column represent spouse expenses for accompanying the Named Executive Officer on business travel.

(ii) Amounts in this column represent the cost of event tickets for personal entertainment.

103

Grants of Plan-Based Awards – 2012

The following table sets forth information regarding grants of plan-based awards to Named Executive Officers under Executive Annual Incentive Plan during the fiscal year ended December 31, 2012.

Name	Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)
	Threshold ($)		Target ($)		Max. ($)
Robert S. Shapard		262,500		525,000		787,500
David M. Davis		93,750		187,500		281,250
James A. Greer		87,500		175,000		262,500
Brenda L. Jackson		58,000		116,000		174,000
Brenda J. Pulis		60,000		120,000		180,000

(1) The amounts reported in these columns reflect the threshold, target and maximum amounts available under the Executive Annual Incentive Plan. Threshold, target and maximum amounts were determined by the O&C Committee in February 2012 and final awards were granted by the O&C Committee in February 2013. The actual awards for the 2012 plan year will be paid in March 2013 and are reported in the Summary Compensation Table under the heading “Non-Equity Incentive Plan Compensation.”

Equity Interests Plan and Management Investment Opportunity

The Equity Interests Plan allows our board of directors to offer non-employee directors, management and other personnel and key service providers of Oncor the right to invest in Class B membership units of Investment LLC (each, a Class B Interest), an entity whose only assets consist of equity interests in Oncor. As a result, each holder of Class B Interests holds an indirect ownership interest in Oncor. Any dividends received by Investment LLC from Oncor in respect of its membership interests in Oncor are subsequently distributed by Investment LLC to the holders of Class B Interests in proportion to the number of Class B Interests held by such holders.

Our board of directors administers the Equity Interests Plan. As the plan administrator, our board of directors determines the participants, the number of Class B Interests offered to any participant, the purchase price of the Class B Interests and the other terms of the award. Our board of directors may also amend, suspend or terminate the Equity Interests Plan at any time. Upon purchasing any Class B Interests, participants may be required to enter into certain agreements with the Company and Investment LLC, including a management stockholder’s agreement and a sale participation agreement described below. The Equity Interests Plan will terminate on November 5, 2018 or an earlier or a later date determined by our board of directors.

In 2008, our executive officers and certain key employees were given the option to purchase Class B Interests of Investment LLC pursuant to the 2008 Management Investment Opportunity offered under the Equity Interests Plan. Each participant in the 2008 Management Investment Opportunity purchased Class B Interests at a price of $10.00 per unit, which was the same price per unit as paid by Texas Transmission in connection with its November 2008 investment in Oncor. Because the Class B Interests were purchased for fair market value, they are not included in the Summary Compensation Table or the Outstanding Equity Awards at Fiscal Year-End Table below as stock awards. Refer to “– Compensation Discussion and Analysis – Compensation Elements – Long Term Incentives – Equity Interests Plan and Management Investment Opportunity” for a more detailed discussion of the Equity Interests Plan and Management Investment Opportunity.

In connection with the Management Investment Opportunity, each participant entered into a management stockholder’s agreement and a sale participation agreement. The management stockholder’s agreement, among others things, gives Oncor the right to repurchase a participant’s Class B Interests in the event of specified terminations of a participant’s employment or violation by a participant of certain of his or her non-compete obligations. We believe this repurchase right provides significant retentive value to our business. For a more detailed description of the terms of the management stockholder’s agreement and sale participation agreement, see “Certain Relationships and Related Transactions, and Director Independence – Related Party Transactions – Agreements with Management and Directors.”

104

The Named Executive Officers beneficially own the following amounts of Class B Interests: Mr. Shapard: 300,000; Mr. Davis: 50,000; Mr. Greer: 75,000; Ms. Jackson: 75,000; and Ms. Pulis: 90,000. The amounts of Class B Interests each participant could purchase were determined by the O&C Committee. Each participant was permitted to use his funds in the Salary Deferral Program to purchase the Class B Interests. All Class B Interests purchased using funds held in the Salary Deferral Program are held of record by the Salary Deferral Program for the benefit of the respective participants. Messrs. Davis, Greer, and Ms. Pulis each elected to purchase Class B Interests using Salary Deferral Program funds. As a result, 19,868 of Mr. Davis’s Class B Interests, 25,000 of Mr. Greer’s Class B Interests and 27,425 of Ms. Pulis’s Class B Interests are held of record by the Salary Deferral Program.

Executive Annual Incentive Plan

The Executive Annual Incentive Plan is a cash bonus plan intended to provide a performance-based annual reward for the successful attainment of certain annual performance goals and business objectives that are established by the O&C Committee. Elected officers of the Company having a title of vice president or above and other specified key employees are eligible to participate in the Executive Annual Incentive Plan provided they are employed by us for a period of at least three full months during a January 1 to December 31 plan year. The O&C Committee and our CEO are responsible for administering the Executive Annual Incentive Plan.

The aggregate amount of funding for awards payable in any given plan year is determined based on (1) the target award levels of all participants in the Executive Annual Incentive Plan (Aggregate Incentive Pool), (2) Oncor’s EBITDA and (3) any additional operational, financial or other metrics that the O&C Committee elects to apply in determining the aggregate amount of awards (Additional Metrics). Target award levels are set as a percentage of a participant’s base salary and are based on target performance of Oncor and individual participant performance. Additional Metrics are determined by the O&C Committee in its discretion and may include, among other things, safety, reliability, operational efficiency, and infrastructure readiness measures. The O&C Committee also determines the threshold EBITDA and the thresholds relating to any Additional Metrics that are necessary to fund awards for each plan year. Based on the level of attainment of these EBITDA and Additional Metrics targets, the O&C Committee determines an aggregate performance final funding percentage. This final funding percentage is applied to the Aggregate Incentive Pool to provide the total amount of funds available for awards to participants under the Executive Annual Incentive Plan.

2012 Funding Percentage

As described above, the funding percentage is based on EBITDA and any Additional Metrics the O&C Committee elects to apply in any given plan year, which we refer to as the operational funding percentage. For 2012, the O&C Committee exercised the discretion granted it in the plan and established Additional Metrics based on operational targets relating to (1) a safety metric based on the number of employee injuries using a Days Away, Restricted or Transfer (DART) system, (2) a reliability metric as measured by the System Average Interruption Duration Index (SAIDI), (3) an operational efficiency metric based on the achievement of targeted operation and maintenance expense (O&M) and sales, general and administrative expense (SG&A) levels determined on a per customer cost basis and (4) an infrastructure readiness metric based on the capital expenditure per three year average kW peak. The purpose of these operational targets, which are based on safety, reliability, operational efficiency and infrastructure readiness metrics, is to promote enhancement of our services to customers.

Funding of the Aggregate Incentive Pool is based first on the achievement of stated EBITDA thresholds and targets set by the O&C Committee for that year and then, assuming the EBIDTA threshold is met, the achievement of the operational targets. The final Aggregate Incentive Pool funding percentage is determined based on both EBITDA and operational achievement, as described below.

Step 1: EBITDA Achievement

Incentives are only payable under the Executive Annual Incentive Plan in the event the threshold EBITDA is achieved. If the threshold EBITDA is achieved, then the EBITDA funding percentage is 50%. If the target EBITDA is achieved, the EBITDA funding percentage is 100%. If actual EBITDA exceeds the target EBITDA, then funding equals the operational funding percentage, up to 150%. If actual EBITDA is an amount between the threshold and target, the EBITDA funding percentage equals 50% plus the product of (i) 50%, multiplied by (ii) a fraction, the numerator of which equals the difference between actual EBITDA and threshold EBITDA and the denominator of which equals the difference between threshold EBITDA and target EBITDA.

105

For 2012, the EBITDA funding triggers (threshold and target), actual results and funding percentage under the Executive Annual Incentive Plan were as follows:

	Threshold ($ in millions)  (1)		Target ($ in millions)  (2)		Actual Results ($ in millions)		EBITDA Funding Percentage (3)
EBITDA		1,504		1,671		1,659		96.3	%

(1) Achievement of the threshold EBITDA level results in a 50% funding percentage.

(2) Achievement of the target EBITDA level results in a 100% funding percentage.

(3) Provided that the threshold has been met, the EBITDA funding percentage equals the percentage of target EBITDA achieved. For 2012, since actual results exceeded the threshold but were lower than the target, the EBITDA funding percentage is 96.3%.

Step 2: Operational Achievement

If the threshold EBITDA is achieved, then once the EBITDA funding percentage is determined, the operational metrics set by the O&C Committee are then applied to determine an operational funding percentage. The operational funding percentage can increase or decrease the funding percentage of the Aggregate Incentive Pool. If actual EBITDA exceeds the target EBITDA, then funding equals the operational funding percentage, up to 150%. If actual EBITDA is less than or is equal to the target EBITDA, then funding of the Aggregate Incentive Pool is the lesser of the EBITDA funding percentage or the operational funding percentage. For 2012, since actual EBITDA exceeded the threshold but was lower than the target EBITDA and the operational funding was 130%, the Aggregate Incentive Pool funding percentage was the EBITDA funding percentage of 96.3%.

The O&C determines the operational metrics to be applied to the operational funding percentage, and the weighting of each of those metrics within the final operational funding percentage. As with the EBITDA funding percentage, each operational metric must meet a threshold level in order to provide any funding for that metric. Meeting the threshold amount results in 50% of the available funding for that specific metric. The O&C Committee also sets target and superior levels for each operational metric, and achievement of those levels results in funding for a specific metric of 100% and 150%, respectively. Once threshold has been achieved, actual results in between each level results in a funding percentage equal to the percentage of the target achieved (up to 150%, for achievement of the superior performance level).

For 2012, the operational funding triggers, actual results and funding percentages under the Executive Annual Incentive Plan were as follows:

Goal	Weighting			Threshold (1)		Target (2)		Superior (3)		Actual Results			Operational Funding Percentage
Safety
DART		30	%		1.10		0.90		0.75		0.83			37	%
Reliability
Non-storm SAIDI (in minutes)		30	%		115.0		98.0		90.0		90.0			45	%
Operational Efficiency – O&M
O&M ($ per customer)		30	%		174.73		163.30		151.87		156.93			38	%
Operational Efficiency – Infrastructure Readiness
Capital expenditures per three year average kW peak		10	%		97.00%- 97.99% and 103.00%- 105.00%		98.00%- 98.99% and 101.50%- 102.99%		99.00%- 101.49%		101.76	%		10	%
Total Operational Funding Percentage														130	%

106

(1) Achievement of the threshold operational metric level results in funding of 50% of the available funding percentage for that specific operational metric. Failure to achieve the threshold results in no funding for that specific operational metric.

(2) Achievement of the target operational metric level results in funding of 100% of the available funding percentage for that specific operational metric.

(3) Achievement above the superior operational metric level results in funding of up to 150% of the available funding percentage for that specific operational metric.

In 2012, satisfaction of safety metrics comprised 30% of the operational funding percentage. The safety metric measures the number of employee injuries using a DART system, which measures the amount of time our employees are away from their regular employment posts due to injury. DART is measured in the number of injuries per 200,000 hours and does not include employees that are part of the individual performance incentive program offered to our meter readers. The safety metric is important to our operations because it promotes the health and welfare of our employees. In addition, lowering the number of accidents reduces our operating costs, which in turn contributes to lower rates for our customers.

In 2012, satisfaction of reliability metrics comprised 30% of the operational funding percentage. Reliability is measured by SAIDI, which measures the average number of minutes electric service is interrupted per customer in a year. This metric promotes our commitment to minimizing service interruptions to our customers as the lower the SAIDI level for the year, the greater the funding percentage under the Executive Annual Incentive Plan. Since weather can greatly impact reliability and is outside of our control, the reliability metric measures SAIDI on a non-storm basis.

In 2012, satisfaction of operational efficiency metrics related to O&M comprised 30% of the operational funding percentage. Operational efficiency is measured based on O&M per customer, excluding third party network transmission fees and amortization of regulatory assets. The purpose of the O&M metric is to promote lower expenditures relative to customers served, which in turn contributes to lower rates for our customers.

In 2012, satisfaction of operational efficiency metrics related to infrastructure readiness comprised the final 10% of the operational funding percentage. Infrastructure readiness is measured based on Oncor’s capital expenditures (including capital expenditures and net removal costs, but excluding allowance for funds used during construction) for the preceding three years’ average kW peak loads. The purpose of the infrastructure readiness metric is to promote capital expenditures in line with the previously set capital plan. While this metric discourages exceeding the budget, it also discourages spending that is too far below the capital plan, as we believe expenditures to improve our facilities and other capital expenditures are important to maintaining the quality of and enhancing our services to our customers.

As discussed above, an aggregate operational funding percentage amount for all participants was determined based on the level of attainment of the above operational targets.

Step 3: Applying Operational Funding Percentage to EBITDA Funding Percentage

The operational funding percentage can increase or decrease the funding percentage of the Aggregate Incentive Pool. If actual EBITDA exceeds the target EBITDA, then funding equals the operational funding percentage, up to 150%. If actual EBITDA is less than or equals the target EBITDA, then funding of the Aggregate Incentive Pool is the lesser of the EBITDA funding percentage or the operational funding percentage. For 2012, since we did not meet the target EBITDA, the Aggregate Incentive Pool was 96.3%, the lesser of the EBITDA funding percentage and the operational funding percentage.

Individual Performance Modifier and Determination

To calculate an executive officer’s award amount, the final funding percentage is first multiplied by the executive officer’s target award, which is computed as a percentage of actual base salary. Based on the executive officer’s performance, an individual performance modifier is then applied to the calculated award to determine the final incentive payment. An individual performance modifier is based on reviews and evaluations of the executive officer’s performance by

107

the CEO and the O&C Committee (or solely the O&C Committee in the case of our CEO) and may adjust an award upward or downward. The individual performance modifier is determined on a subjective basis. Factors used in determining individual performance modifiers may include operational measures (including the safety, reliability, operational efficiency metrics and infrastructure readiness discussed above), company objectives, individual management and other goals, specific job objectives and competencies, the demonstration of team building and support attributes and general demeanor and behavior. For the 2012 plan year, the O&C Committee elected not to adjust any executive officers’ Executive Annual Incentive Plan awards with individual performance modifiers.

108

The following table sets forth information regarding SARs awards exercised by Named Executive Officers in 2012. All exercises were completed in connection with the November 2012 SARs Exercise Opportunity discussed below.

Option Exercises – 2012

	Option Awards
Name	Value Realized on  Exercise ($) (1)(2)
Robert S. Shapard		17,025,000
David M. Davis		2,724,000
James A. Greer		3,541,200
Brenda L. Jackson		3,541,200
Brenda J. Pulis		4,449,200

(1) The amounts in this column reflect pre-tax amounts received by each executive in connection with the SARs Exercise Opportunity, as discussed under “Compensation Discussion and Analysis – Compensation Elements – Long-Term Incentives – Stock Appreciation Rights.”

(2) Amounts listed in this column include the following amounts that each executive agreed to defer until the earlier of November 7, 2016 or an event that would trigger exercisability of SARs under the SARs Plan: Mr. Shapard, $2,957,400; Mr. Davis, $473,184; Mr. Greer, $615,139 and Ms. Pulis, $772,867.

In November 2012, our board of directors accepted for early exercise all outstanding SARs (vested and unvested) issued under the SARs Plan, pursuant to the provision of the SARs Plan that permits the board to accelerate the vesting and exercisability of SARs. Ninety percent of the aggregate outstanding SARs granted under the SARs Plan (all except the tranche of performance-based SARs that were eligible to vest for 2012) were vested as of November 2012. The SARs Exercise Opportunity entitled each participant in the SARs Plan, including our Named Executive Officers, to: (1) an exercise payment equal to the number of SARs exercised multiplied by the difference between $14.54 and the base price of the SARs ($10.00 for each Named Executive Officer); and (2) the accrual of interest on all dividends declared to date with respect to the SARs, and no further dividend accruals. As a result of the SARs Exercise Opportunity, we paid approximately $64 million in aggregate exercise payments to participants in the SARs Plan. Of that amount, the Named Executive Officers received the following exercise payment amounts, less withholding for applicable taxes: Mr. Shapard, $17,025,000; Mr. Davis, $2,724,000; Mr. Greer, $3,541,200; Ms. Jackson, $3,541,200; and Ms. Pulis, $4,449,200.

Additionally, the Named Executive Officers, other than Ms. Jackson, who previously announced her intention to retire in 2013, agreed to defer payments of a portion of his/her Exercise Payment in the following amounts: Mr. Shapard, $2,957,400; Mr. Davis, $473,184; Mr. Greer, $615,139; and Ms. Pulis, $772,867. These Named Executive Officers agreed to defer such amounts until the earlier of November 7, 2016 or the occurrence of an event triggering SAR exercisability. These events generally include a change of control, an EFH Realization Event (as defined in the SARs Plan), a liquidity event or the achievement of certain financial returns as described in the SARs Plan.

In addition, Oncor began to accrue interest for the Named Executive Officers on the following amounts of dividends: Mr. Shapard, $5,109,935; Mr. Davis, $817,590; Mr. Greer, $1,062,866; Ms. Jackson, $1,062,866; and Ms. Pulis, $1,335,396. Interest on the dividend accounts for the Named Executive Officers has been accrued in the following amounts as of December 31, 2012: Mr. Shapard, $23,165; Mr. Davis, $3,706; Mr. Greer, $4,818; Ms. Jackson, $4,818; and Ms. Pulis, $6,054.

SARs Plan

The SARs Plan remains in effect, although the O&C Committee has indicated that it does not currently plan to issue any additional SARs under the SARs Plan. Instead, the O&C Committee intends for the Long-Term Incentive Plan to replace the SARs Plan as a long-term incentive component of executive compensation.

The O&C Committee adopted and implemented the SARs Plan in 2008. The O&C Committee determines the participants and can include certain employees of Oncor or other persons having a relationship with Oncor, its subsidiaries or affiliates. SARs granted under the SARs Plan have a base price equal to the fair market value (as set by our board of directors) per unit of Oncor’s equity interests on the date of the grant and will allow participants to participate in the economic equivalent of the appreciation of the Oncor equity interests. The O&C Committee administers the SARs Plan and makes awards under the SARs Plan at its discretion, subject to the receipt of necessary consents from Oncor’s majority owner as required under the Limited Liability Company Agreement.

109

Under the SARs Plan, the O&C Committee may grant either time-vesting awards (time-based SARs) and/or performance-vesting awards (performance-based SARs). The O&C Committee granted both time-based and performance-based SARs to certain executive officers and other key employees through 2011. The number of SARs granted to the individual was based in part upon the size of the individual’s investment in Investment LLC pursuant to the Management Investment Opportunity. Each participant’s SARs award consisted of (1) 50% of time-based SARs and (2) 50% of performance-based SARs. Time-based SARs vested in equal increments each year starting with October 10 of the grant year through October 10, 2012. Performance-based SARs were to vest in equal increments each year starting with December 31 of the grant year through December 31, 2012, provided that Oncor meets specified financial targets. The SARs Plan provides that in the event we fail to meet a specified financial target in a given fiscal year, under certain circumstances the applicable award may vest in a subsequent year if cumulative targets including such year are met. As of the time of the SARs Exercise Opportunity in November 2012, all time-based SARs were vested and all performance based SARs due to vest through December 31, 2011 had been vested.

Pursuant to the SARs Plan, the vesting of the SARs does not entitle the grantee to exercise the SARs until certain events occur as described below: (1) all time-based SARs vest and become exercisable upon the termination of the participant’s employment by Oncor without “cause” or by the participant with “good reason” following a “change in control” (as those terms are defined in the SARs Plan); (2) except as otherwise provided in an award letter and subject to the participant’s employment on the date of the applicable event, vested time-based SARs and vested performance-based SARs become exercisable as to the Oncor equity interests subject to such vested SARs immediately prior to an “EFH realization event” (as defined in the SARs Plan) in the same proportion as EFH Corp. or certain associated persons realize liquidity in connection with such event; (3) all unvested performance-based SARs become vested and exercisable, subject to certain conditions, upon any “liquidity event” (as defined in the SARs Plan), so long as the participant is still employed by Oncor on such date; and (4) if a participant retires or his or her employment is terminated by Oncor without cause or by the participant for good reason, vested, but unexercisable, awards as of the date of the participant’s termination or retirement may become exercisable at a later date, in the percentages set forth in the SARs Plan, following the occurrence of certain events. In addition to the foregoing, our board of directors and the O&C Committee have the right to accelerate vesting and exercisability of a participant’s award under the SARs Plan at any time in their respective discretion. Our board of directors used its authority under this provision to declare the SARs exercisable in connection with the November 2012 SARs Exercise Opportunity.

Subject to the terms described in the previous paragraph, the SARs may be exercised in part or in full prior to their termination. Upon the exercise of an award, the participant will be entitled to receive a cash payment equal to the product of (1) the difference between the fair market value per Oncor equity interest on the date giving rise to the payment and the fair market value as of the date of the award grant, and (2) the number of SARs exercised by the participant. In the event of an initial public offering of Oncor’s equity interests or equity interests of a successor vehicle, the awards may be satisfied in equity interests of the public company, cash or a combination of both, at the election of our board of directors.

Generally, awards under the SARs Plan terminate on the tenth anniversary of the grant, unless the participant’s employment is earlier terminated under certain circumstances. The SARs Plan will terminate on the later of November 5, 2018 or such other date determined by our board of directors.

In addition, under the SARs Plan, dividends that are paid in respect of Oncor membership interests while the SARs are outstanding are credited to the SARs holder’s account as if the SARs were units of Investment LLC, payable upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control. Approximately $18.1 million of actual dividends had been accrued as of the date of the SARs Exercise Opportunity in November 2012, of which approximately $9.4 million were attributable to our named executive officers.

110

The following table sets forth information regarding Oncor’s participation in the retirement plans that provide for benefits, in connection with, or following, the retirement of Named Executive Officers for the fiscal year ended December 31, 2012:

Pension Benefits – 2012

Name	Plan Name	Number of Years Accredited Service (#) (1)		Present Value  of Accumulated Benefit ($)(2)		Payments During Last Fiscal Year ($)
Robert S. Shapard	Retirement Plan Supplemental Retirement Plan		27.0833 27.0833		784,087 221,540		— —
David M. Davis	Retirement Plan Supplemental Retirement Plan		20.5000 20.5000		1,031,702 790,873		— —
James A. Greer	Retirement Plan Supplemental Retirement Plan		27.5000 27.5000		1,327,497 406,424		— —
Brenda L. Jackson	Retirement Plan Supplemental Retirement Plan		37.1667 37.1667		2,621,058 723,263		— —
Brenda J. Pulis	Retirement Plan Supplemental Retirement Plan		29.1667 29.1667		1,483,696 322,333		— —

(1) Accredited service for each of the plans is determined based on an employee’s age and hire date. Employees hired by Oncor or an EFH Corp. affiliate prior to January 1, 1985 became eligible to participate in the plan the month after their completion of one year of service and attainment of age 25. Employees hired after January 1, 1985 became eligible to participate in the plan the month after their completion of one year of service and attainment of age 21.

(2) Through 2012, Mr. Shapard accumulated benefits in two EFH Corp.-sponsored supplemental retirement plans as a result of his service as an employee of EFH Corp.’s predecessor prior to joining Oncor. Those benefits were paid solely by EFH Corp. In connection with various changes made by EFH Corp. to its retirement plans in 2012, EFH Corp. transferred $75,906 from a supplemental retirement plan sponsored by EFH Corp. into Mr. Shapard’s account in the Retirement Plan and $142,865 from a second EFH Corp.-sponsored retirement plan into Mr. Shapard’s account in the Supplemental Retirement Plan. Amounts reported in this column for Mr. Shapard include such transferred amounts.

Until January 1, 2013, Oncor was a participating employer in the EFH Retirement Plan. In August 2012, EFH Corp. made various changes to the EFH Retirement Plan, including splitting off into a new plan all of the assets and liabilities associated with Oncor employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Effective January 1, 2013, Oncor assumed sponsorship of the new plan, referred to in this Annual Report as the Oncor Retirement Plan. See Footnote 10 to Financial Statements for additional information on the EFH Retirement Plan and the Oncor Retirement Plan. Since the benefits to Oncor employees are identical under the EFH Retirement Plan and the Oncor Retirement Plan, we refer to the plans collectively as the “Retirement Plan.”

The Retirement Plan contains both a traditional defined benefit component and a cash balance component. Only employees hired before January 1, 2002 may participate in the traditional defined benefit component. All new employees hired after January 1, 2002 participate in the cash balance component. In addition, the cash balance component covers employees previously covered under the traditional defined benefit component who elected to convert the actuarial equivalent of their accrued traditional defined benefit to the cash balance component during a special one-time election opportunity effective in 2002. The employees that participate in the traditional defined benefit component do not participate in the cash balance component.

Annual retirement benefits under the traditional defined benefit component, which applied during 2012 to Messrs. Davis and Greer and Mses. Jackson and Pulis are computed as follows: for each year of accredited service up to a total of 40 years, 1.3% of the first $7,800, plus 1.5% of the excess over $7,800, of the participant’s average annual earnings (base salary) during his/her three years of highest earnings. Under the cash balance component, which covers Mr. Shapard, a hypothetical account is established for participants and credited with monthly contribution credits equal to a percentage of the participant’s compensation (3.5%, 4.5%, 5.5% or 6.5% depending on the participant’s combined age and years of accredited service), plus interest credits based on the average yield of the 30-year Treasury bond for the 12 months ending November 30 of the prior year. Benefits paid under the traditional defined benefit component of the EFH Retirement Plan are not subject to any reduction for Social Security payments but are limited by provisions of the Code.

111

The Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited by the Code or the definition of earnings under the Retirement Plan, including any retirement compensation required to be paid pursuant to contractual arrangements. Under the Supplemental Retirement Plan, retirement benefits are calculated in accordance with the same formula used under the Retirement Plan, except that, with respect to calculating the portion of the Supplemental Retirement Plan benefit attributable to service under the traditional defined benefit component of the Retirement Plan, earnings also include Executive Annual Incentive Plan awards. The amount of earnings attributable to the Executive Annual Incentive Plan awards is reported under the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

The table set forth above illustrates the present value on December 31, 2012 of each Named Executive Officer’s Retirement Plan benefit and benefits payable under the Supplemental Retirement Plan, based on his or her years of service and remuneration through December 31, 2012. Benefits accrued under the Supplemental Retirement Plan after December 31, 2004 are subject to Section 409A of the Code. Accordingly, certain provisions of the Supplemental Retirement Plan have been modified in order to comply with the requirements of Section 409A and related guidance.

The present value of accumulated benefits for the traditional benefit component of the Retirement Plan was calculated based on the executive’s annuity payable at the earliest age that unreduced benefits are available under the Plans (generally age 62). Unmarried executives are assumed to elect a single life annuity. For married executives, it is assumed that 65% will elect a 100% joint and survivor annuity and 35% will elect a single life annuity. Post-retirement mortality was based on the 2013 Static Mortality Table for Annuitants and Non-Annuitants per Treasury regulation 1.430(h)(3)-1(e). A discount rate of 4.10% was applied, and no pre-retirement mortality or turnover was reflected.

The present value of accumulated benefit for the cash balance component of the Retirement Plan and the Supplemental Retirement Plan was calculated as the value of the executive’s cash balance account projected to age 65 at an assumed growth rate of 3.75% and then discounted back to December 31, 2012 at 4.10%. No mortality or turnover assumptions were applied.

Early retirement benefits under the Retirement Plan are available to all of our employees upon their attainment of age 55 and achievement of 15 years of accredited service. Early retirement results in a retirement benefit payment reduction of 4 percent for each full year (and 0.333% for each additional full calendar month) between the date the participant retires and the date the participant would reach age 62. Benefits under the Supplemental Retirement Plan are subject to the same age and service restrictions, but are only available to our executive officers and certain other key employees.

112

The following table sets forth information regarding the deferral of components of our Named Executive Officers’ compensation on a basis that is not tax-qualified for the fiscal year ended December 31, 2012:

Nonqualified Deferred Compensation – 2012

Name	Executive Contributions in Last Fiscal Year ($)(1)(2)		Registrant Contributions in Last Fiscal Year ($)(3)		Aggregate Earnings (Loss) in Last Fiscal Year ($)		Aggregate Withdrawals/ Distributions ($)		Aggregate Balance at Last Fiscal Year End ($)(4)
Robert S. Shapard Salary Deferral Program SARs Exercise Opportunity Deferral		56,000 2,957,400		56,000 —		99,943 71		—   —		899,371 2,957,471
David M. Davis (5) Salary Deferral Program SARs Exercise Opportunity Deferral		30,000 473,184		30,000 —		29,984 11		—   —		482,124 473,195
James A. Greer (6) Salary Deferral Program SARs Exercise Opportunity Deferral		28,000 615,139		28,000 —		9,221 15		—   —		488,795 615,154
Brenda L. Jackson Salary Deferral Program SARs Exercise Opportunity Deferral		23,200 —		23,200 —		45,366 —		40,997 —		398,468 —
Brenda J. Pulis (7) Salary Deferral Program SARs Exercise Opportunity Deferral		24,000 772,867		24,000 —		36,035 19		—   —		603,542 772,886

(1) Amounts in this column for the Salary Deferral Program represent salary deferrals pursuant to the Salary Deferral Program and are included in the “Salary” amounts in the Summary Compensation Table above.

(2) Amounts in this column for the SARs Exercise Opportunity Deferral represent amounts the respective Named Executive Officer agreed to defer pursuant to the SARs Exercise Opportunity, as discussed in more detail in the narrative immediately following this table.

(3) Amounts in this column represent company-matching awards pursuant to the Salary Deferral Program and are included in the “All Other Compensation” amounts in the Summary Compensation Table above.

(4) Amounts in the “Aggregate Balance at Last Fiscal Year End” column represent the balance of each Named Executive Officer’s account in the Salary Deferral Program. The following amounts were reported as compensation to the listed officers in the Summary Compensation table for 2010 through 2012 (except Mr. Greer and Ms. Pulis, who were not named executive officers in 2010-2011): Mr. Shapard $164,333, Mr. Davis $58,166, and Ms. Jackson $45,300.

(5) $7,039 of Mr. Davis’s aggregate earnings in the last fiscal year are attributable to earnings associated with the Class B Interests he purchased using funds in his Salary Deferral Program account pursuant to the Management Investment Opportunity.

(6) $8,857 of Mr. Greer’s aggregate earnings in the last fiscal year are attributable to earnings associated with the Class B Interests he purchased using funds in his Salary Deferral Program account pursuant to the Management Investment Opportunity.

(7) $9,716 of Ms. Pulis’s aggregate earnings in the last fiscal year are attributable to earnings associated with the Class B Interests she purchased using funds in her Salary Deferral Program account pursuant to the Management Investment Opportunity.

Salary Deferral Program

Under the Salary Deferral Program each employee of Oncor, who is in a designated job level and whose annual salary is equal to or greater than an amount established under the Salary Deferral Program ($116,510 for the program year beginning January 1, 2012) may elect to defer up to 50% of annual base salary, and/or up to 85% of any bonus or incentive award. This deferral may be made for a period of seven years, for a period ending with the retirement of such employee, or for a combination thereof, at the election of the employee. Oncor makes a matching award, subject to forfeiture under certain circumstances, equal to 100% of up to the first 8% of salary deferred under the Salary Deferral Program. Oncor does not match deferred annual incentive awards. Matching contributions vest at the earliest of seven years after the deferral date, executive’s retirement or a change in control of Oncor (as defined in the Salary Deferral Program).

Deferrals are credited with earnings or losses based on the performance of investment alternatives under the Salary Deferral Program selected by each participant. Among the investment alternatives, certain participants were eligible to use funds in the Salary Deferral Program to purchase Class B Interests in November 2008 pursuant to the Equity Interests Plan

113

and Management Investment Opportunity. For additional information regarding the Equity Interests Plan and Management Investment Opportunity, see “Long Term Incentives—Equity Interests Plan and Management Investment Opportunity.” Distributions from Oncor to Investment LLC are distributed pro rata to the holders of Class B Interests in accordance with their proportionate ownership of Class B Interests. Any distributions attributable to Class B Interests purchased using a participant’s funds in the Salary Deferral Program are deposited in such participant’s Salary Deferral Program account as earnings.

At the end of the applicable account maturity period, the trustee for the Salary Deferral Program distributes the deferrals and the applicable earnings in cash as a lump sum or in annual installments at the participant’s election made at the time of deferral. Oncor is financing the retirement option portion of the Salary Deferral Program through the purchase of corporate-owned life insurance on some lives of participants. The proceeds from such insurance are expected to allow us to fully recover the cost of the retirement option.

SARs Exercise Opportunity Deferrals

In connection with the SARs Exercise Opportunity in November 2012, certain Named Executive Officers agreed to defer payments of a portion of his/her Exercise Payment in the following amounts: Mr. Shapard, $2,957,400; Mr. Davis, $473,184; Mr. Greer, $615,139; and Ms. Pulis, $772,867. These Named Executive Officers agreed to defer the amounts until the earlier of November 7, 2016 or the occurrence of an event triggering SAR exercisability. These events generally include a change of control, an EFH realization event, a liquidity event or the achievement of certain financial returns as described in the SARs Plan. The deferred amounts were placed in a bankruptcy-remote trust. Ms. Jackson, who had previously informed management of her intention to retire in 2013, did not defer any portion of her SARs exercise payments. For more information on the SARs Exercise Opportunity, see “Compensation Discussion and Analysis – Long-Term Incentives – Stock Appreciation Rights.”

Potential Payments upon Termination or Change in Control

The tables and narrative below provide information for payments to Oncor’s Named Executive Officers (or, as applicable, enhancements to payments or benefits) in the event of termination including retirement, voluntary, for cause, death, disability, without cause or change in control of Oncor. The amounts shown below assume that such a termination of employment and/or change in control occurred on December 31, 2012.

In 2012, all of our executive officers were eligible to receive benefits under the terms of the Change in Control Policy and the Severance Plan, as more fully described following the tables below. In addition to the provisions of those plans, the Salary Deferral Program provides that all company-matching awards will become automatically vested in the event of a change in control. The amounts listed in the tables below regarding the Salary Deferral Program only represent the immediate vesting of company matching contributions resulting from death, disability or the occurrence of a change in control. Vested amounts and contributions made to such plan by each Named Executive Officer are disclosed in the Nonqualified Deferred Compensation table above. For a more detailed discussion of the Salary Deferral Program, see the Nonqualified Deferred Compensation table above and the narrative following the Nonqualified Deferred Compensation table.

Early retirement benefits under the Retirement Plan are available to all of our employees upon their attainment of age 55 and achievement of 15 years of accredited service. Early retirement results in a retirement benefit payment reduction of 4 percent for each full year (and 0.333% for each additional full calendar month) between the date the participant retires and the date the participant would reach age 62. Benefits under the Supplemental Retirement Plan are subject to the same age and service restrictions, but are only available to our executive officers and certain other key employees. At December 31, 2012 Mr. Greer was not eligible to retire because he has not met the age requirement. However, because Mr. Shapard participates in the cash balance component of the retirement plans, and because he has satisfied both the age requirement and 10 years of accredited service, he may withdraw his full account balances under each plan upon termination of his employment. Upon achievement of the age and service requirements, executive officers are entitled to receive their full cash account balance upon termination. No additional potential payments will be triggered by any termination of employment or change in control, and as a result no amounts are reported in the tables below for such retirement plans. For a more detailed discussion of the retirement plans, see the Pension Benefits table above and the narrative following the Pension Benefits table.

114

All our Named Executive Officers participate in benefit plans for group term life insurance and accidental death and disability. Additionally, Mses. Jackson and Pulis are participants in the EFH Split-Dollar Life Insurance Plan. Any benefits received under these policies are paid to the beneficiary by a third-party provider.

In addition, under the SARs Plan, dividends that are paid in respect of Oncor membership interests while the SARs are outstanding are credited to the SARs holder’s account as if the SARs were units of Investment LLC, payable upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control. In connection with the November 2012 SARs Exercise Opportunity each SARs holder agreed that no further dividends would accumulate following such exercise, and that interest would accrue on their existing dividend accounts until such dividends were paid in accordance with the terms of the SARs Plan. Approximately $9.4 million of actual dividends were accrued for our named executive officers as of the SARs Exercise Opportunity.

No Named Executive Officer is party to any employment or other agreement that provides for additional benefits upon a termination of employment or change in control.

115

1. Mr. Shapard

Potential Payments to Mr. Shapard Upon Termination ($)

Benefit	Retirement (1)		Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance		—		—		—		—		—		1,925,000		2,450,000
Executive Annual Incentive Plan		525,000		—		—		525,000		525,000		—		—
Salary Deferral Program (2)		287,063		—		—		354,399		354,399		—		354,399
SARs Plan dividends (3)		5,133,100		5,133,100		5,133,100		5,133,100		5,133,100		5,133,100		5,133,100
SARs Exercise Deferral (4)		—		—		—		—		—		—		2,957,400
Health & Welfare
—Medical/COBRA		—		—		—		—		—		49,325		49,325
—Dental/COBRA		—		—		—		—		—		3,803		3,803
Outplacement Assistance		—		—		—		—		—		183,750		183,750
Totals		5,945,163		5,133,100		5,133,100		6,012,499		6,012,499		7,294,978		11,131,777

(1) Mr. Shapard participates in the cash balance component of the Retirement Plan and the Supplemental Retirement Plan, and because he has achieved 10 years of plan participation, he may withdraw his full account balances under each plan upon termination of his employment for any reason.

(2) Amounts reported reflect the immediate vesting of company matching contributions resulting from retirement, death, disability or the occurrence of a change in control.

(3) Amounts reported reflect amounts payable in connection with dividends accrued with respect to SARs in accordance with the SARs Plan, which dividends are payable in a lump sum upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control. In connection with the November 2012 SARs Exercise Opportunity, these dividend accounts ceased accruing dividends as of the date of such exercise but will accrue interest until the dividend account is payable. Amounts above include interest accumulated on Mr. Shapard’s dividend account from November 2012 through December 31, 2012.

(4) In connection with the November 2012 SARs Exercise Opportunity, Mr. Shapard agreed to defer $2,957,400 of his Exercise Payment until the earlier of November 7, 2016 or certain events that would trigger SARs exercisability under the SARs Plan. These events generally include a change of control, an EFH Realization Event (as defined in the SARs Plan), a liquidity event or the achievement of certain financial returns as described in the SARs Plan.

116

2. Mr. Davis

Potential Payments to Mr. Davis Upon Termination ($)

Benefit	Retirement		Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance		—		—		—		—		—		562,500		562,500
Executive Annual Incentive Plan		187,500		—		—		187,500		187,500		—		—
Salary Deferral Program (1)		92,681		—		—		123,028		123,028		—		123,028
SARs Plan dividends (2)		821,296		821,296		821,296		821,296		821,296		821,296		821,296
SARs Exercise Deferral (3)		—		—		—		—		—		—		473,184
Health & Welfare
—Medical/COBRA		—		—		—		—		—		32,883		32,883
—Dental/COBRA		—		—		—		—		—		2,535		2,535
Outplacement Assistance		—		—		—		—		—		84,375		84,375
Totals		1,101,477		821,296		821,296		1,131,824		1,131,824		1,503,589		2,099,801

(1) Amounts reported reflect the immediate vesting of company matching contributions resulting from retirement, death, disability or the occurrence of a change in control.

(2) Amounts reported reflect amounts payable in connection with dividends accrued with respect to SARs in accordance with the SARs Plan, which dividends are payable in a lump sum upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control. In connection with the November 2012 SARs Exercise Opportunity, these dividend accounts ceased accruing dividends as of the date of such exercise but will accrue interest until the dividend account is payable. Amounts above include interest accumulated on Mr. Davis’s dividend account from November 2012 through December 31, 2012.

(3) In connection with the November 2012 SARs Exercise Opportunity, Mr. Davis agreed to defer $473,184 of his Exercise Payment until the earlier of November 7, 2016 or certain events that would trigger SARs exercisability under the SARs Plan. These events generally include a change of control, an EFH Realization Event (as defined in the SARs Plan), a liquidity event or the achievement of certain financial returns as described in the SARs Plan.

117

3. Mr. Greer

Potential Payments to Mr. Greer Upon Termination ($)

Benefit	Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance		—		—		—		—		525,000		525,000
Executive Annual Incentive Plan		—		—		175,000		175,000		—		—
Salary Deferral Program (1)		—		—		96,933		96,933		—		96,933
SARs Plan dividends (2)		1,067,684		1,067,684		1,067,684		1,067,684		1,067,684		1,067,684
SARs Exercise Opportunity Deferral (3)		—		—		—		—		—		615,139
Health & Welfare
—Medical/COBRA		—		—		—		—		32,883		32,883
—Dental/COBRA		—		—		—		—		2,521		2,521
Outplacement Assistance		—		—		—		—		78,750		78,750
Totals		1,067,684		1,067,684		1,339,617		1,339,617		1,706,838		2,418,910

(1) Amounts reported reflect the immediate vesting of company matching contributions resulting from death, disability or the occurrence of a change in control.

(2) Amounts reported reflect amounts payable in connection with dividends accrued with respect to SARs in accordance with the SARs Plan, which dividends are payable in a lump sum upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control. In connection with the November 2012 SARs Exercise Opportunity, these dividend accounts ceased accruing dividends as of the date of such exercise but will accrue interest until the dividend account is payable. Amounts above include interest accumulated on Mr. Greer’s dividend account from November 2012 through December 31, 2012.

(3) In connection with the November 2012 SARs Exercise Opportunity, Mr. Greer agreed to defer $615,139 of his Exercise Payment until the earlier of November 7, 2016 or certain events that would trigger SARs exercisability under the SARs Plan. These events generally include a change of control, an EFH Realization Event (as defined in the SARs Plan), a liquidity event or the achievement of certain financial returns as described in the SARs Plan.

118

4. Ms. Jackson

Potential Payments to Ms. Jackson Upon Termination ($)

Benefit	Retirement (1)		Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance (2)		—		—		—		—		—		557,692		557,692
Executive Annual Incentive Plan		116,000		—		—		116,000		116,000		—		—
Salary Deferral Program (3)		95,123		—		—		95,123		95,123		—		95,123
SARs Plan dividends (4)		1,067,684		1,067,684		1,067,684		1,067,684		1,067,684		1,067,684		1,067,684
Health & Welfare
—Medical/COBRA		—		—		—		—		—		9,950		9,950
—Dental/COBRA		—		—		—		—		—		763		763
Outplacement Assistance		—		—		—		—		—		60,900		60,900
TOTAL		1,278,807		1,067,684		1,067,684		1,278,807		1,278,807		1,696,989		1,792,112

(1) At December 31, 2012, Ms. Jackson met the age and service requirements for early retirement under the Retirement Plan and the Supplemental Retirement Plan. Ms. Jackson has notified Oncor that she intends to retire effective July 1, 2013. Amounts in this column assume Ms. Jackson elected to retire as of December 31, 2012.

(2) Both the change in control policy and Severance Plan provide for a one-time lump sum cash severance payment in an amount equal to the greater of (i) a multiple (2 times for the CEO and 1 time for each other executive officer) of the sum of the executive’s (a) annualized base salary and (b) annual target incentive award for the year of termination or resignation, or (ii) the amount determined under Oncor’s severance plan for non-executive employees (which pays two weeks of an employee’s pay for every year of service up to the 20^th year of service, and three weeks of pay for every year of service above 20 years of service). Because Ms. Jackson had accumulated 40 years of service, she would receive more under the non-executive employee severance plan and amounts reported reflect that amount.

(3) Amounts reported reflect the immediate vesting of company matching contributions resulting from retirement, death, disability or the occurrence of a change in control.

(4) Amounts reported reflect amounts payable in connection with dividends accrued with respect to SARs in accordance with the SARs Plan, which dividends are payable in a lump sum upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control. In connection with the November 2012 SARs Exercise Opportunity, these dividend accounts ceased accruing dividends as of the date of such exercise but will accrue interest until the dividend account is payable. Amounts above include interest accumulated on Ms. Jackson’s dividend account from November 2012 through December 31, 2012.

119

5. Ms. Pulis

Potential Payments to Ms. Pulis Upon Termination ($)

Benefit	Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance (1)		—		—		—		—		421,154		421,154
Executive Annual Incentive Plan		—		—		120,000		120,000		—		—
Salary Deferral Program (2)		—		—		139,825		139,825		—		139,825
SARs Plan Dividends (3)		1,341,450		1,341,450		1,341,450		1,341,450		1,341,450		1,341,450
SARs Exercise Deferral (4)		—		—		—		—		—		772,867
Health & Welfare
—Medical/COBRA		—		—		—		—		18,671		18,671
—Dental/COBRA		—		—		—		—		1,428		1,428
Outplacement Assistance		—		—		—		—		63,000		63,000
Totals		1,341,450		1,341,450		1,601,275		1,601,275		1,845,703		2,758,395

(1) Both the change in control policy and Severance Plan provide for a one-time lump sum cash severance payment in an amount equal to the greater of (i) a multiple (2 times for the CEO and 1 time for each other executive officer) of the sum of the executive’s (a) annualized base salary and (b) annual target incentive award for the year of termination or resignation, or (ii) the amount determined under Oncor’s severance plan for non-executive employees (which pays two weeks of an employee’s pay for every year of service up to the 20^th year of service, and three weeks of pay for every year of service above 20 years of service). Because Ms. Pulis had accumulated 31 years of service, she would receive more under the non-executive employee severance plan and amounts reported reflect that amount.

(2) Amounts reported reflect the immediate vesting of company matching contributions resulting from death, disability or the occurrence of a change in control.

(3) Amounts reported reflect amounts payable in connection with dividends accrued with respect to SARs in accordance with the SARs Plan, which dividends are payable in a lump sum upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control. In connection with the November 2012 SARs Exercise Opportunity, these dividend accounts ceased accruing dividends as of the date of such exercise but will accrue interest until the dividend account is payable. Amounts above include interest accumulated on Ms. Pulis’s dividend account from November 2012 through December 31, 2012.

(4) In connection with the November 2012 SARs Exercise Opportunity, Ms. Pulis agreed to defer $772,867 of her Exercise Payment until the earlier of November 7, 2016 or certain events that would trigger SARs exercisability under the SARs Plan. These events generally include a change of control, an EFH Realization Event (as defined in the SARs Plan), a liquidity event or the achievement of certain financial returns as described in the SARs Plan.

120

Change in Control Policy

We maintain a Change in Control Policy for our executive team, which consists of our executive officers and certain non-executive vice presidents. The purpose of this Change in Control Policy is to provide the payment of transition benefits to eligible executives if:

• Their employment with the company or a successor is terminated within twenty-four months following a change in control of the company; and

• They:

• are terminated without cause, or

• resign for good reason due to a reduction in salary or a material reduction in the aggregate level or value of benefits for which they are eligible.

The Change in Control Policy provides for the payment of transition benefits to eligible executives if any of the following occur within 24 months following a change in control:

• The executive is terminated without cause. Cause is defined as either (a) the definition in any executive’s applicable employment agreement or change in control agreement or (b) if there is no such employment or change in control agreement, cause exists: (i) if, in carrying out his or her duties to Oncor, an executive engages in conduct that constitutes (A) a breach of his or her fiduciary duty to Oncor, its subsidiaries or shareholders, (B) gross neglect or (C) gross misconduct resulting in material economic harm to Oncor or its subsidiaries, taken as a whole, or (ii) upon the indictment of the executive, or the plea of guilty or nolo contendere by the executive to, a felony or a misdemeanor involving moral turpitude.

• The executive resigns for good reason. Good reason is defined as any of the following being taken without the executive’s consent: (a) a reduction in the executive’s base salary, other than a broad-based reduction of base salaries of all similarly situated executives of the surviving corporation after a change in control, or subsidiary, as applicable, unless such broad-based reduction only applies to former executives of Oncor; (b) a material reduction in the aggregate level or value of benefits for which the executive is eligible, immediately prior to the change in control (as defined below), other than a broad-based reduction applicable on a comparable basis to all similarly situated executives; or (c) the executive is required to permanently relocate outside of a fifty (50) mile radius of the executive’s principal residence.

“Change in control” is defined in the Change in Control Policy as the occurrence of the following, in one or a series of related transactions, (i) the sale of all or substantially all of the consolidated assets or capital stock of EFH Corp., Oncor Holdings or Oncor to a person (or group of persons acting in concert) who is not an affiliate of any member of the Sponsor Group; (ii) a merger, recapitalization or other sale by EFH Corp., any member of the Sponsor Group or their affiliates, to a person (or group of persons acting in concert) of the common stock of EFH Corp., no par value (“EFH Common Stock”) that results in more than 50% of the EFH Common Stock (or any resulting company after a merger) being held by a person (or group of persons acting in concert) that does not include any member of the Sponsor Group or any of their respective affiliates;or (iii) a merger, recapitalization or other sale of EFH Common Stock by EFH Corp., any member of the Sponsor Group or their affiliates, after which the Sponsor Group owns less than 20% of the EFH Common Stock, and has the ability to appoint less than a majority of the directors to the board of directors of EFH Corp. (or of any resulting company after a merger); and with respect to any of the events described in clauses (i) and (ii) above, such event results in any person (or group of persons acting in concert) gaining control of more seats on the board of directors of EFH Corp. than the Sponsor Group; provided however, that notwithstanding the foregoing, (x) clause (i) above shall be deemed not to include any reference to EFH Corp., and clauses (ii) and (iii) shall not apply, in each case, for purposes of interpreting the termination or applicability of any puts, calls or release from transfer restrictions upon transfers of equity interests of Oncor or Oncor Holdings, (y) clause (i) above shall be deemed not to include any reference to Oncor Holdings for purposes of interpreting the termination or applicability of any puts, calls or release from transfer restrictions upon transfers of equity interests of Oncor and (z) clause (i) above shall be deemed not to include any reference to Oncor for the purposes of interpreting the termination or applicability of any puts, calls or release from transfer restrictions upon the transfer of equity units of Oncor Holdings. In addition, should a change in control occur under clauses (i) through (iii) above with respect to the assets or capital stock of EFH Corp., a change in control will not be deemed to have occurred unless such change in control would result in the material amendment or interference with the separateness undertakings under our Limited Liability Company Agreement, or would adversely change or modify the definition of an independent director in our Limited Liability Company Agreement.

121

Our executive officers are eligible to receive the following under the Change in Control Policy:

• A one-time lump sum cash severance payment in an amount equal to the greater of (i) a multiple (2 times for Mr. Shapard and 1 time for each other executive officer) of the sum of the executive’s (a) annualized base salary and (b) annual target incentive award for the year of termination or resignation, or (ii) the amount determined under Oncor’s severance plan for non-executive employees (which pays two weeks of an employee’s pay for every year of service up to the 20^th year of service, and three weeks pay for every year of service above 20 years of service);

• If the executive is terminated or resigns pursuant to the Oncor Change in Control Policy prior to October 10, 2012, a one-time lump sum cash severance payment equal to the product of the number of SARs held by such executive immediately prior to the change in control, multiplied by the fair market value of such SARs (as defined in the SARs Plan) on the date of termination/resignation minus the base price (as defined in the SARs Plan);

• Continued eligibility for distribution of already-granted equity awards at maturity; however, any such distribution will be prorated for the period of employment during the relevant performance or restriction period prior to termination;

• Continued coverage at our expense under our health care benefit plans for the applicable COBRA period with the executive’s contribution for such plans being at the applicable employee rate for 18 months (unless and until the executive becomes eligible for benefits with another employer) and, if the executive is covered under our healthcare plans through the end of such period, at the end of such continued coverage the executive may continue participation in our health care plans at the applicable COBRA rate for 18 months, in the case of Mr. Shapard, or six months, in the case of each other executive, and Oncor will reimburse the executive the monthly difference between the applicable employee rate for such coverage and the COBRA rate paid by the executive for such period;

• Outplacement assistance at our expense for 18 months, in the case of Mr. Shapard, and one year, in the case of the other executive officers;

• Any vested, accrued benefits to which the executive is entitled under our employee benefits plans; and

• If any of the severance benefits described in the Change in Control Policy shall result in an excise tax pursuant to Code Sections 280G or 4999 of the Code, payable by the executive, a tax gross-up payment to cover such additional taxes, subject to reduction for certain Section 280G purposes.

Severance Plan

We maintain a Severance Plan (Severance Plan) for our executive team, which consists of our executive officers and certain non-executive vice presidents. The purpose of this Severance Plan is to provide benefits to eligible executives who are not eligible for severance pursuant to another plan or agreement (including an employment agreement) and whose employment is involuntarily terminated for reasons other than:

• Cause (as defined in the Severance Plan);

• Disability of the employee, if the employee is a participant in our long-term disability plan; or

• A transaction involving the company or any of its affiliates in which the employee is offered employment with a company involved in, or related to, the transaction.

The Severance Plan provides for severance payments to executives whose employment is involuntarily terminated for reasons other than:

• Cause, which is defined as either (a) the definition in any executive’s applicable employment agreement or change in control agreement or, (b) if there is no such employment or change in control agreement, cause exists: (i) if, in carrying out his or her duties to the Company, an executive engages in conduct that constitutes (A) a breach of his or her fiduciary duty to Oncor, its subsidiaries or shareholders (including a breach or attempted breach of the restrictive covenants under the Severance Plan), (B) gross neglect or (C) gross misconduct resulting in material economic harm to Oncor or its subsidiaries, taken as a whole, or (ii) upon the indictment of the executive, or the plea of guilty or nolo contendere by the executive to a felony or a misdemeanor involving moral turpitude;

• Participation in the EFH Corp.-sponsored long-term disability plan or any successor plan; or

• A transaction involving the Company or any of its affiliates in which the executive is offered employment with a company involved in, or related to, the transaction.

122

Our executive officers are eligible to receive the following under the Severance Plan:

• A one-time lump sum cash severance payment in an amount equal to the greater of (i) the sum of (a) a multiple of two times for Mr. Shapard and one time for each other Named Executive Officer of the executive’s annualized base salary and (b) a prorated portion of the executive’s annual target incentive award for the year of termination, or (ii) the amount determined under Oncor’s severance plan for non-executive employees;

• Continued coverage at our expense under the Company’s health care benefit plans for 18 months, with the executive’s contribution for such plans being at the applicable employee rate (unless and until the executive becomes eligible for coverage for benefits through employment with another employer, at which time the executive’s required contribution shall be the applicable COBRA rate) and, if the executive is covered under our healthcare plans through the end of such period, at the end of such continued coverage the executive may continue participation in our health care plans at the applicable COBRA rate for 18 months, in the case of Mr. Shapard, or six months, in the case of each other executive, and Oncor will reimburse the executive the monthly difference between the applicable employee rate for such coverage and the COBRA rate paid by the executive for such period;

• Outplacement assistance at the company’s expense for 18 months, in the case of Mr. Shapard, and one year, in the case of other executive officers; and

• Any vested accrued benefits to which the executive is entitled under Oncor’s or EFH Corp.’s employee benefits plans.

In order to receive benefits under the plan, a participant must enter into an agreement and release within 45 days of being notified by us of such participant’s eligibility to receive benefits under the plan. The Severance Plan also provides that for a period of one year after a termination contemplated by the plan, a participant may not recruit, solicit, induce or in any way cause any employee, consultant or contractor engaged by Oncor to terminate his/her relationship with Oncor.

Risk Assessment of Compensation Policies and Practices

The O&C Committee reviews the compensation policies and practices applicable to Oncor’s employees (both executive and non-executive) annually each February in order to determine whether such compensation policies and practices create risks that are reasonably likely to have a material adverse effect on Oncor. In February 2012 and February 2013 the O&C Committee concluded that current compensatory policies and practices do not create risks that are reasonably likely to have a material adverse effect on Oncor. In arriving at this conclusion, the O&C Committee discussed with management the various compensation policies and practices of the company and the compensation payable pursuant to each, and evaluated whether the compensation payable under each plan or policy could result in (i) incenting employees to take risks that could result in a material adverse effect to Oncor, or (ii) payments by the company significant enough to cause a material adverse effect to Oncor.

We believe that the following factors in our employee compensation program limit risks that could be reasonably likely to have a material adverse effect on the company:

• Our compensation program is designed to provide a mix of base salary, annual cash incentives and (for eligible employees) long-term equity and cash incentives, which we believe motivates employees to perform at high levels while mitigating any incentive for short-term risk-taking that could be detrimental to our company’s long-term best interests.

• Our annual cash incentive plans for both executives and non-executives contain maximum payout levels, which helps avoid excessive total compensation and reduces the incentive to engage in unnecessarily risky behavior.

• The funding percentages under the Executive Annual Incentive Plan and the non-executive employee annual incentive plan are based on the performance of our total company, which mitigates any incentive to pursue strategies that might maximize the performance of a single business group to the detriment of the company as a whole.

• We place an emphasis on individual, non-financial performance metrics in determining individual compensation amounts, serving to restrain the influence of objective factors on incentive pay and providing management (in the case of non-executive employees) and the O&C Committee (in the case of executive employees) the discretion to adjust compensation downward if behaviors are not consistent with Oncor’s business values and objectives.

123

• Long-term incentives for eligible employees (under the SARs Plan until 2012 and the Long-Term Incentive Plan beginning in 2013) fully vest or are measured over a minimum of five years, in the case of the SARs Plan and three years, in the case of the Long-Term Incentive Plan, to ensure employees have significant value tied to the long-term performance of the company.

• Our executive officers and other senior members of management purchased equity through the Management Investment Opportunity, which we believe motivates them to consider the long-term interests of the company and its equity owners and discourages excessive risk-taking that could negatively impact the value of their equity interests.

• We have internal controls over financial reporting and other financial, operational and compliance policies and practices designed to keep our compensation programs from being susceptible to manipulation by any employee, including our executive officers.

124

Director Compensation

The table below sets forth information regarding the aggregate compensation paid to the members of the board of directors during the fiscal year ended December 31, 2012. Directors who are officers of Oncor and directors who are not independent directors (as defined in the Limited Liability Company Agreement), do not receive any fees for service as a director. Oncor reimburses all directors for reasonable expenses incurred in connection with their services as directors.

Name	Fees Earned or Paid in Cash ($) (2)		All Other Compensation ($) (3)		Total ($)
Nora Mead Brownell		155,000		—		155,000
Thomas M. Dunning		185,000		98,004		283,004
Robert A. Estrada		150,000		24,501		174,501
Monte E. Ford		135,000		98,004		233,004
William T. Hill, Jr.		170,000		—		170,000
Richard W. Wortham III		150,000		49,002		199,002
Richard C. Byers (1)		—		—		—
Thomas D. Ferguson		—		—		—
Jeffrey Liaw		—		—		—
Rheal R. Ranger (1)		—		—		—
Robert S. Shapard		—		—		—
Steven J. Zucchet		—		—		—

(1) Mr. Ranger joined our board of directors effective October 24, 2012, replacing Richard C. Byers as one of the directors appointed by Texas Transmission pursuant to its rights set forth in the LLC Agreement. Neither Mr. Ranger nor Mr. Byers received any compensation from Oncor for serving on our board of directors.

(2) Amounts reflect the following director fees paid to independent directors quarterly, in arrears: (a) $33,750 for service as a director, (b) an additional $3,750 director’s fee for each of Messrs. Estrada (Audit Committee), Hill (Nominating & Governance Committee) and Wortham (O&C Committee) for serving as committee chairs, (c) an additional $5,000 for each of Ms. Brownell and Mr. Hill for serving as special independent directors, and (d) an additional $12,500 for Mr. Dunning for serving as our lead independent director. Non-independent directors do not receive any fees for serving on our board of directors. Amounts above do not include an additional $15,000 annual fee (paid in quarterly installments, in arrears), paid to each independent director as a fee for serving on the Oncor Holdings board of directors.

(3) Amounts in this column reflect the following amounts received in connection with the early exercise of SARs under the Oncor Electric Delivery Company LLC Director Stock Appreciation Rights Plan (Director SARs Plan), as discussed in more detail under “— Director SARs Plan” below:

Director SARs Plan Participant	November 2012 SARs Exercise Opportunity Exercise Payment ($) (a)		Director SARs Plan 2012 Dividend Accrual ($) (b)		SARs Exercise Opportunity Interest Accrual on Dividends ($)(c)		Total ($)
Thomas M. Dunning		90,800		7,085		119		98,004
Robert A. Estrada		22,700		1,771		30		24,501
Monte E. Ford		90,800		7,085		119		98,004
Richard Wortham IIII		45,400		3,543		59		49,002

(a) In November 2012 our board of directors accepted for early exercise all outstanding SARs issued under the Director SARs Plan upon the same terms as the SARs Exercise Opportunity offered to management. As a result of such exercise, each participant in the Director SARs Plan received a pre-tax payment equal to the difference between $14.54 and the SARs base price of $10.00, multiplied by the number of SARs held by such director. Amounts in this column reflect that exercise payment for each participant.

125

(b) Under the Director SARs Plan, dividends that are paid in respect of Oncor membership interests while the SARs are outstanding are credited to the SARs holder’s account as if the SARs were units of Investment LLC, payable upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control. Amounts in this column represent the 2012 dividend accrual.

(c) As part of the SARs early exercise in November 2012, each participant in the Director SARs Plan agreed that he would be entitled to no further dividend accruals after the date of such exercise, but that the dividend account would accumulate interest until such dividends became payable pursuant to the SARs Plan. Amounts in this column include interest accruals through December 31, 2012 for each Director SARs Plan participant.

The O&C Committee determines compensation for independent directors that serve on the board of directors. All director fees are paid quarterly, in arrears. Each of our independent directors receives a quarterly fee of $33,750 for service on our board of directors, and an additional quarterly fee of $3,750 for service on the Oncor Holdings’ board of directors. Each board committee chair receives an additional $3,750 quarterly fee for the extra responsibilities associated with such position, and our lead independent director (Mr. Dunning) receives an additional $12,500 quarterly fee for the additional duties associated with that position. In February 2012, our board of directors approved an additional quarterly fee of $5,000 to each of our Special Independent Directors (as defined in our Limited Liability Company Agreement) to compensate for their additional responsibilities as Special Independent Directors. The Special Independent Director fee was effective beginning with each Special Independent Director’s service as of January 1, 2012. For a description of the independence standards applicable to our independent directors, see “Certain Relationships and Related Transactions, and Director Independence.”

Our LLC Agreement provides that each of the Sponsor Group and Texas Transmission has the right to appoint two directors to our board of directors. None of those four directors (Messrs. Ferguson, Liaw, Ranger and Zucchet) receives compensation from us for his service as a director. In addition, Mr. Shapard, our CEO, does not receive additional compensation for serving on the board of directors.

Purchases of Class B Interests

Eligible participants in the Equity Interests Plan include non-employee directors, and our board of directors has granted independent directors the option to purchase Class B Interests pursuant to the Equity Interests Plan. For a description of the Equity Interests Plan, see “– Elements of Compensation – Long-Term Incentives – Equity Interests Plan and Management Investment Opportunity.”

Effective January 2009 four of our independent directors, Messrs. Dunning, Estrada, Ford and Wortham, purchased the following amounts of Class B Interests pursuant to the Equity Interests Plan: Dunning: 20,000, Estrada: 5,000, Ford: 20,000 and Wortham: 10,000. Similar to the Management Investment Opportunity, these Class B Interests were purchased at a price of $10.00 per unit. Because the Class B Interests were purchased for fair market value, they are not included in the Director Compensation Table as stock awards. In connection with their investments, these directors entered into director stockholder agreements and sale participation agreements. For a description of the material terms of these agreements, see “Certain Relationships and Related Transactions, and Director Independence – Related Party Transactions – Agreements with Management and Directors.”

In connection with these investments, Oncor Holdings sold 55,000 of its equity interests in Oncor to Investment LLC at a price of $10.00 per unit pursuant to the terms of a revolving stock purchase agreement. For a description of the revolving stock purchase agreement, see “– Elements of Compensation – Long-Term Incentives – Equity Interests Plan and Management Investment Opportunity.”

Director SARs Plan

On February 25, 2009, Oncor implemented the Director SARs Plan to allow participants to participate in the economic equivalent of the appreciation of Oncor’s LLC Units. Each of the independent directors who purchased Class B Interests in January 2009 received one SAR for each Class B Interest purchased. Each SARs award was subject to time vesting provisions and upon the occurrence of certain conditions could be exercised for a cash payment equal to the number of SARs exercised multiplied by the difference between the fair market value per LLC Unit on the date giving rise to the payment and the fair market value as of the date of the award grant. Under the Director SARs Plan, dividends that are paid in respect of Oncor membership interests while the SARs are outstanding are credited to the SARs holder’s account as if the SARs were units of Investment LLC, payable upon the earliest to occur of death, disability, separation from service, unforeseeable emergency or a change in control.

126

In November 2012, in connection with the SARs Exercise Opportunity offered to management, our board of directors accepted for early exercise all outstanding SARs issued under the Director SARs Plan, pursuant to the provision of the Director SARs Plan that permits the board to accelerate the vesting and exercisability of SARs. At the time of such exercise, all outstanding SARs under the Director SARs Plan were vested. The November 2012 exercise of SARs entitled each participant in the Director SARs Plan, to: (1) an exercise payment equal to the number of SARs exercised multiplied by the difference between $14.54 and the $10.00 base price of the SARs; and (2) the accrual of interest on all dividends declared to date with respect to the SARs, and no further dividend accruals. As a result, each of the Director SARs Plan participants received cash payments in the amounts set forth in the “November 2012 SARs Exercise Opportunity Exercise Payment” column of the table in footnote 3 of the Director Compensation table above, and we began accruing interest on the following amounts of dividends: Mr. Dunning, $26,140, Mr. Estrada, $6,535; Mr. Ford, $26,140; and Mr. Wortham, $13,070. These interest payments are payable in connection with payment of the dividends under the Director SARs Plan.

Although the Director SARs Plan remains in effect, our board of directors has indicated it has no current intention to grant any new SARs awards under such plan.

127

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED EQUITY HOLDER MATTERS

Equity Compensation Plan Information

The following table presents information concerning the Stock Appreciation Rights Plan and Director Stock Appreciation Rights Plan (collectively, the Plans) at December 31, 2012. For a discussion of the Plans and the stock appreciation rights (SARs) issuable under the Plans, see “Executive Compensation — Compensation Discussion & Analysis — Compensation Elements — Long-Term Incentives — Stock Appreciation Rights” and “Executive Compensation – Director Compensation – Director SARs Plan.”

	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)		Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders (1)(2)		—		—		—
Equity compensation plans not approved by security holders		—		—		—
Total		—		—		—

(1) As required by the terms of our Limited Liability Company Agreement, we obtained the consent of EFIH to issue SARs under the Plans. Consents from our other members were not solicited as they are not required under the Limited Liability Company Agreement.

(2) Neither of the Plans results in the issuance of equity. Rather, SARs issued under the Plans give the holders the right to receive the economic value of the appreciation of our equity interests. All outstanding SARs under the Plans were accepted for early exercise in November 2012, and while both Plans continue to remain in effect our board of directors has indicated it does not intend to issue additional SARs under either of the Plans. For more information, see “Executive Compensation – Compensation Discussion and Analysis – Compensation Elements – Long-Term Incentives – Stock Appreciation Rights” and “Executive Compensation – Director Compensation – Director SARs Plan.”

Our executive officers, certain key employees and independent members of our board of directors were given the option to purchase Class B Interests of Investment LLC in 2008 pursuant to the 2008 Management Investment Opportunity offered under the Equity Interests Plan. Each participant in the 2008 Management Investment Opportunity purchased Class B Interests at a price of $10.00 per unit, which was the same price per unit as the price per unit paid by Texas Transmission in connection with its November 2008 investment in Oncor. In August 2011, Mr. Nye purchased Class B Interests in Investment LLC for $12.25 per unit (the fair market value of the Class B Interests, as determined by our board of directors based on a third party independent analysis) pursuant to the 2011 Management Investment Opportunity. Because the Class B Interests in each of the 2011 and the 2008 Management Investment Opportunity were purchased for fair market value, and it is expected that any future issuances under the Equity Interests Plan will be subject to the same purchase requirement, we do not consider the grants to be compensation. Refer to “Directors, Executive Officers and Corporate Governance — Compensation Discussion and Analysis — Compensation Elements — Long Term Incentives — Equity Interests Plan and Management Investment Opportunity” for a more detailed discussion of the Equity Interests Plan and Management Investment Opportunity.

128

Security Ownership of Equity Interests of Oncor of Certain Beneficial Owners and Management

The following table lists the number of limited liability company units (LLC Units) of Oncor beneficially owned by our directors and current executive officers and the holders of more than 5% of our LLC Units at February 15, 2013.

The amounts and percentages of LLC Units beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power or investment power, which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed to be a beneficial owner of the same securities and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest.

Name	Amount and Nature of Beneficial Ownership		Percent of Class
Oncor Electric Delivery Holdings Company LLC (1)(2)(3)(4)(5)		508,191,492		80.03	%
Texas Transmission Investment LLC (6)		125,412,500		19.75	%
Name of Director or Executive Officer
Nora Mead Brownell		—		—
David M. Davis (7)		1,396,008		(11	)
Thomas M. Dunning (7)		1,396,008		(11	)
Robert A. Estrada (7)		1,396,008		(11	)
Thomas D. Ferguson (4)		508,191,492		80.03	%
Monte E. Ford (7)		1,396,008		(11	)
James A. Greer (7)		1,396,008		(11	)
William T. Hill, Jr.		—		—
Brenda L. Jackson (7)		1,396,008		(11	)
Jeffrey Liaw (8)		—		—
Brenda J. Pulis (7)		1,396,008		(11	)
Rheal R. Ranger (9)		—		—
Robert S. Shapard (7)		1,396,008		(11	)
Richard W. Wortham III (7)		1,396,008		(11	)
Steven J. Zucchet (10)		—		—
All directors and current executive officers as a group (22 persons)		509,587,500		80.25	%

(1) Oncor Electric Delivery Holdings Company LLC (Oncor Holdings) beneficially owns 508,191,492 LLC Units of Oncor. The sole member of Oncor Holdings is EFIH, whose sole member is EFH Corp. The address of Oncor Holdings is 1616 Woodall Rodgers Freeway, Dallas, TX 75202 and each of EFIH and EFH Corp. is 1601 Bryan Street, Dallas, TX 75201. Texas Holdings beneficially owns 98.99% of the outstanding shares of EFH Corp. The sole general partner of Texas Holdings is Texas Energy Future Capital Holdings LLC (Texas Capital), which, pursuant to the Amended and Restated Limited Partnership Agreement of Texas Holdings, has the right to vote all of the EFH Corp. shares owned by Texas Holdings. The TPG Funds, the Goldman Entities and the KKR Entities (each as defined below, and collectively, the Texas Capital Funds) collectively own 91.08% of the outstanding units of Texas Capital. The Texas Capital Funds exercise control over Texas Capital and each has the right to designate and remove the managers of Texas Capital appointed by such Texas Capital Fund. Because of these relationships, each of the Texas Capital Funds may be deemed to have beneficial ownership of the shares of EFH Corp. owned by Texas Holdings and the LLC Units owned by Oncor Holdings, but each disclaims beneficial ownership of such shares of EFH Corp. and LLC Units. The address of both Texas Holdings and Texas Capital is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

129

(2) EFIH has pledged 100% of its equity interests in Oncor Holdings to holders of certain of its secured notes as security for such notes. In the event of certain defaults by EFIH under its related obligations, these holders could exercise their pledge rights and a change in control of Oncor could occur.

(3) The TPG Funds beneficially own 302,923,439.752 units of Texas Capital, representing 27.01% of the outstanding units, including (i) 271,639,218.931 units held by TPG Partners V, L.P., a Delaware limited partnership (TPG Partners V), whose general partner is TPG GenPar V, L.P., a Delaware limited partnership (TPG GenPar V), whose general partner is TPG GenPar V Advisors, LLC, a Delaware limited liability company, whose sole member is TPG Holdings I, L.P., a Delaware limited partnership (TPG Holdings), (ii) 29,999,994.650 units held by TPG Partners IV, L.P., a Delaware limited partnership (TPG Partners IV), whose general partner is TPG GenPar IV, L.P., a Delaware limited partnership, whose general partner is TPG GenPar IV Advisors, LLC, a Delaware limited liability company, whose sole member is TPG Holdings, (iii) 710,942.673 units held by TPG FOF V-A, L.P., a Delaware limited partnership (TPG FOF A), whose general partner is TPG GenPar V and (iv) 573,283.498 units held by TPG FOF V-B, L.P., a Delaware limited partnership (TPG FOF B and, together with TPG Partners V, TPG Partners IV and TPG FOF A, the TPG Funds), whose general partner is TPG GenPar V. The general partner of TPG Holdings is TPG Holdings I-A, LLC, a Delaware limited liability company, whose sole member is TPG Group Holdings (SBS), L.P., a Delaware limited partnership, whose general partner is TPG Group Holdings (SBS) Advisors, Inc., a Delaware corporation (Group Advisors). David Bonderman and James G. Coulter are directors, officers and sole shareholders of Group Advisors and may therefore be deemed to beneficially own the units held by the TPG Funds. David Bonderman is also a manager of Texas Capital. Messrs. Bonderman and Coulter disclaim beneficial ownership of the LLC Units held by Texas Holdings except to the extent of their pecuniary interest therein. The address of Group Advisors and Messrs. Bonderman and Coulter is c/o TPG Global LLC, 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

(4) GS Capital Partners VI Fund, L.P., GSCP VI Offshore TXU Holdings, L.P., GSCP VI Germany TXU Holdings, L.P., GS Capital Partners VI Parallel, L.P., GS Global Infrastructure Partners I, L.P., GS Infrastructure Offshore TXU Holdings, L.P. (GSIP International Fund), GS Institutional Infrastructure Partners I, L.P., Goldman Sachs TXU Investors L.P. and Goldman Sachs TXU Investors Offshore Holdings, L.P. (collectively, Goldman Entities) beneficially own 303,094,945.954 units of Texas Capital, representing 27.02% of the outstanding units. Affiliates of The Goldman Sachs Group, Inc. (Goldman Sachs) are the general partner, managing general partner or investment manager of each of the Goldman Entities, and each of the Goldman Entities shares voting and investment power with certain of their respective affiliates. Each of Goldman Sachs and the Goldman Entities disclaims beneficial ownership of such shares of EFH Corp. and LLC Units except to the extent of its pecuniary interest therein. Mr. Ferguson is a manager of Texas Capital and an executive with an affiliate of Goldman Sachs. By virtue of his position in relation to Texas Capital and the Goldman Entities, Mr. Ferguson may be deemed to have beneficial ownership with respect to the units of Texas Capital held by the Goldman Entities. Mr. Ferguson disclaims beneficial ownership of the LLC Units held by Oncor Holdings except to the extent of his pecuniary interest in those units. The address of each entity and individual listed in this footnote is c/o Goldman, Sachs & Co., 85 Broad Street, New York, New York 10004.

(5) KKR 2006 Fund L.P., KKR PEI Investments, L.P., KKR Partners III, L.P., KKR North American Co-Invest Fund I L.P. and TEF TFO Co-Invest, LP (collectively, KKR Entities) beneficially own 415,473,419.680 units of Texas Capital, representing 37.05% of the outstanding units. The KKR Entities disclaim beneficial ownership of any shares of EFH Corp. and LLC Units in which they do not have a pecuniary interest. KKR & Co. L.P., as the holding company of affiliates that directly or indirectly control the KKR Entities, other than KKR Partners III, LP., may be deemed to share voting and dispositive power with respect to the shares of EFH Corp. and LLC Units beneficially owned by such KKR Entities, but disclaims beneficial ownership of such shares of EFH Corp. and LLC Units except to the extent of their pecuniary interest in those shares of EFH Corp. and LLC Units. As the designated members of KKR Management LLC (which is the general partner of KKR & Co. L.P.) and the managing members of KKR III GP LLC (which is the general partner of KKR Partners III, L.P.), Henry R. Kravis and George R. Roberts may be deemed to share voting and dispositive power with respect to the shares of EFH Corp. and LLC Units beneficially owned by the KKR Entities but disclaim beneficial ownership of such shares of EFH Corp. and LLC Units except to the extent of their pecuniary interest in those shares of EFH Corp. and LLC Units. The address of each entity and individual listed in this footnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, New York 10019

(6) Texas Transmission Investment LLC (Texas Transmission) beneficially owns 125,412,500 LLC Units of Oncor. The sole member of Texas Transmission is Texas Transmission Holdings Corporation (TTHC). The address of each of Texas Transmission and TTHC is 1105 North Market Street, Suite 1300, Wilmington, DE 19801. BPC Health Corporation (BPC Health) and Borealis Power Holdings Inc. (Borealis Power) may be deemed, as a result of their ownership of 49.5% of the shares of Class A Common Stock of TTHC (Class A Shares) and 49.5% of the shares of Class B Common Stock of TTHC (Class B Shares), respectively, and certain provisions of TTHC’s Shareholders Agreement (which provide that BPC Health and Borealis Power, when acting together with Cheyne Walk Investment Pte Ltd (Cheyne Walk) or Hunt Strategic Utility Investment, L.L.C. (Hunt Strategic), may direct TTHC in certain matters), to have beneficial ownership of the 125,412,500 LLC Units owned by Texas Transmission. OMERS Administration Corporation (OAC) beneficially owns BPC Health and, therefore, OAC may also be deemed to have beneficial ownership of such LLC Units. Borealis Power is wholly-owned by Borealis Infrastructure Corporation and Borealis Management Trust owns 70% of the voting shares of Borealis Infrastructure Corporation. The trustee of Borealis Management Trust is Borealis Infrastructure Holdings Corporation and, therefore, Borealis Infrastructure Holdings Corporation may also be deemed to have beneficial ownership of such LLC Units. The address of OAC is One University Avenue, Suite 700, Toronto, Ontario M5J 2P1, Canada. The address of Borealis Infrastructure Holdings Corporation is 66 Wellington Street West, Suite 3600, Toronto, Ontario, M5K 1N6, Canada. Cheyne Walk Investment Pte Ltd (Cheyne Walk) may be deemed, as a result of its ownership of 49.5% of each of the Class A Shares and the Class B Shares, and certain provisions of TTHC’s Shareholders Agreement (which provide that Cheyne Walk, when acting together with BPC Health and Borealis Power or Hunt Strategic, may direct TTHC in certain matters), to have beneficial ownership of the

130

125,412,500 LLC Units owned by Texas Transmission. Government of Singapore Investment Corporation Pte Ltd (GIC) beneficially owns Cheyne Walk and therefore GIC may also be deemed to have beneficial ownership of such LLC Units. The address of each of Cheyne Walk and GIC is 168 Robinson Road, #37-01, Capital Tower, Singapore 068912. Hunt Strategic Utility Investment, L.L.C. (Hunt Strategic) may be deemed, as a result of its ownership of 1% of each of the Class A Shares and the Class B Shares, and certain provisions of TTHC’s Shareholders Agreement (which provide that Hunt Strategic, when acting together with BPC Health and Borealis Power or Cheyne Walk, may direct TTHC in certain matters), to have beneficial ownership of the 125,412,500 LLC Units owned by Texas Transmission. Ray L. Hunt (Hunt) beneficially owns Hunt Strategic and therefore Hunt may also be deemed to have beneficial ownership of such LLC Units. The address of each of Hunt Strategic and Hunt is 1900 North Akard, Dallas, Texas 75201.

(7) Includes the 1,396,008 equity interests owned by Oncor Management Investment LLC (Investment LLC). The managing member of Investment LLC is Oncor, which holds all of the outstanding voting interests of Investment LLC. The management and board of directors of Oncor may be deemed, as a result of their management of Oncor, to have shared voting or dispositive power. The following Named Executive Officers and directors each beneficially own the following amounts of the outstanding non-voting membership interests of Investment LLC: Mr. Davis: 50,000 (including 19,868.4 of the aggregate outstanding non-voting membership interests that are held by the Salary Deferral Program on Mr. Davis’s behalf), Mr. Dunning: 20,000 (held by a family limited partnership, of which Mr. Dunning serves as managing general partner), Mr. Estrada: 5,000, Mr. Ford: 20,000, Mr. Greer: 75,000 (including 25,000 of the aggregate outstanding non-voting membership interests that are held by the Salary Deferral Program on Mr. Greer’s behalf), Ms. Jackson: 75,000, Ms. Pulis: 90,000 (including 27,425 of the aggregate outstanding non-voting membership interests that are held by the Salary Deferral Program on Ms. Pulis’s behalf), Mr. Shapard: 300,000 (held by a family limited partnership, of which Mr. Shapard serves as general partner) and Mr. Wortham: 10,000 (held by a revocable trust, of which Mr. Wortham serves as trustee and beneficiary). Each of the persons referenced in this footnote disclaims beneficial ownership of such equity interests except to the extent of their pecuniary interest in those equity interests. See “Executive Compensation – Compensation Discussion and Analysis — Compensation Elements — Long-Term Incentives — Equity Interests Plan and Management Investment Opportunity” for a discussion of investments in Investment LLC by certain of Oncor’s executive officers and “Executive Compensation – Director Compensation – Purchases of Class B Interests” for a discussion of investments in Investment LLC by certain of Oncor’s independent directors. The address of each individual named in this footnote is c/o Oncor Management Investment LLC, c/o Oncor Electric Delivery Company LLC, 1616 Woodall Rodgers Freeway, Dallas, Texas, 75202, Attn: Legal Department.

(8) Jeffrey Liaw is a former TPG principal and a manager of Texas Capital. Mr. Liaw does not have voting or investment power over, and disclaims beneficial ownership of, the LLC Units held by Oncor Holdings. The address of Mr. Liaw is c/o FleetPride, Inc., 8401 New Trails, Suite 150, The Woodlands, TX 77381

(9) Rheal R. Ranger is Executive Vice President of Borealis Infrastructure Management Inc., a Director of TTHC, a Director and Executive Vice President of Borealis Power and Executive Vice President of BPC Health. Mr. Ranger does not have voting or investment power over, and disclaims beneficial ownership of, the LLC Units held by Texas Transmission. The address of Mr. Ranger is c/o Borealis Infrastructure Management Inc., 320 Park Avenue, 17^th Floor, New York, NY 10022.

(10) Steven Zucchet is Senior Vice President of Borealis Infrastructure Management Inc., a Director and Senior Vice President of TTHC and a Senior Vice President of Borealis Power. Mr. Zucchet does not have voting or investment power over, and disclaims beneficial ownership of, the LLC Units held by Texas Transmission. The address of Mr. Zucchet is c/o Borealis Infrastructure Management Inc., Royal Bank Plaza, South Tower, 200 Bay Street, Suite 2100, Toronto, ON M5J 2J2.

(11) Less than 1% beneficial ownership.

131

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Policies and Procedures Relating to Related Party Transactions

Our board of directors has adopted a policy regarding related person transactions as part of our corporate governance guidelines. Under this policy, a related person transaction shall be consummated or shall continue only if:

1. the audit committee of the board of directors approves or ratifies such transaction in accordance with the policy and if the transaction is on terms comparable to those that could be obtained in arm’s length dealings with an unrelated third party;

2. the transaction is approved by the disinterested members of the board of directors; or

3. the transaction involves compensation approved by the O&C Committee of the board of directors.

For purposes of this policy, the term “related person” means any related person pursuant to Item 404 of Regulation S-K of the Securities Act, except transactions with EFH Group Members (as defined below), which are subject to restrictions set forth in our Limited Liability Company Agreement

A “related person transaction” is a transaction between us and a related person (including any transactions requiring disclosure under Item 404 of Regulation S-K under the Securities Act, if applicable), other than the types of transactions described below, which are deemed to be pre-approved by the audit committee:

1. any compensation paid to an executive officer or director if the compensation is reported (or would have been reported, in the case of executive officers that are not named executive officers) under Item 402 of Regulation S-K of the Securities Act, provided that such executive officer or director is not an immediate family member of an executive officer or director and provided that the board of directors or the O&C Committee has approved such compensation;

2. any transaction with another company at which a related person’s only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company’s ownership interests;

3. any charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which a related person’s only relationship is as an employee (other than an executive officer) or director;

4. any transaction with a partnership in which a related person’s only relationship is as a limited partner, and the related person is not a general partner and does not hold another position in the partnership, and all related persons have an interest of less than 10% in the partnership;

5. transactions where the related person’s interest arises solely from the ownership of Oncor’s equity securities and all holders of that class of equity securities received the same benefit on a pro rata basis;

6. transactions involving a related party where the rates or charges involved are determined by competitive bids;

7. any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, as rates or charges fixed in conformity with law or governmental authority;

8. any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar service;

9. transactions available to all employees or customers generally (unless required to be disclosed under Item 404 of Regulation S-K of the Securities Act, if applicable); and

10. transactions involving less than $100,000 when aggregated with all similar transactions;

11. transactions between Oncor and its subsidiaries or between subsidiaries of Oncor;

12. transactions not required to be disclosed under Item 404 of Regulation S-K of the Securities Act; and

13. open market purchases of Oncor or its subsidiaries’ debt or equity securities and interest payments on such debt securities.

132

Our board of directors has determined that it is appropriate for its audit committee to review and approve or ratify related person transactions. In unusual circumstances, we may enter into related person transactions in advance of receiving approval, provided that such related person transactions are reviewed and ratified as soon as reasonably practicable by the audit committee of the board of directors. If the audit committee determines not to ratify such transactions, we shall make all reasonable efforts to cancel or otherwise terminate such transactions.

The related person transactions described below under the heading “Related Party Transactions” were generally approved prior to the adoption of our related party transactions policy. Except as otherwise indicated, these transactions were approved by our board of directors.

The related person transactions policy described above also does not apply to transactions with EFH Group Members (as defined below), which are subject to restrictions set forth in our Limited Liability Company Agreement. Accordingly, the transactions with EFH Corp. or its subsidiaries were not approved by the board of directors or Audit Committee and were approved by our management.

Our Limited Liability Company Agreement requires certain separateness undertakings and provides that we will maintain an arm’s length relationship with EFH Corp., its successors, its subsidiaries and any individual or entity controlling or owning, directly or indirectly, more than 49% of our outstanding equity interests (collectively, the EFH Group Members), other than Oncor Holdings, Texas Transmission and each of their subsidiaries and only enter into transactions, other than certain specified transactions, with the EFH Group Members that are both (i) on a commercially reasonable basis, and (ii) if such transaction is material, approved by (a) a majority of the members of our board of directors, and (b) prior to a Trigger Event (as defined in our Limited Liability Company Agreement), the directors appointed by Texas Transmission, at least one of whom must be present and voting in order to approve the transaction.

Related Party Transactions

Transactions with EFH Corp. and its Subsidiaries

Transactions described below were between us and either EFH Corp. or its wholly-owned subsidiaries (other than the subsidiary described under “– Limited Partnership Interest”) and were approved by our management.

Transactions with TCEH

We record revenue from TCEH, principally for electricity delivery fees, which totaled $1.0 billion for each of the years ended December 31, 2012 and 2011 and $1.1 billion for the year ended December 31, 2010. The fees are based on rates regulated by the PUCT that apply to all REPs. These revenues included approximately $2 million for each of the years ended December 31, 2012, 2011 and 2010 pursuant to a transformer maintenance agreement with TCEH. The balance sheets at December 31, 2012 and 2011 reflect receivables from affiliates totaling $53 million and $138 million, respectively, primarily consisting of trade receivables from TCEH related to these electricity delivery fees.

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 $16 million, $17 million and $16 million for the years ended December 31, 2012, 2011 and 2010, respectively. 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.

133

Prior to 2012, we reflected the difference between the trust fund assets and the decommissioning liability (both reported on TCEH’s balance sheet) in our financial statements as a regulatory liability or asset with an offsetting receivable from or payable to TCEH (the beneficiary of the nuclear decommissioning trust). However, amounts associated with nuclear decommissioning activities were not included in our net income or accumulated other comprehensive income. During 2012, we determined that due to our role as the collection agent of funds, the recording of a regulatory liability or asset in our financial statements was an error. As such, the balance sheet at December 31, 2011 has been restated to remove both the $225 million receivable from TCEH related to the Comanche Peak nuclear plant decommissioning and the associated regulatory liability of $225 million. This restatement reduced the receivable from TCEH to zero and increased regulatory assets $225 million.

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

Sale of TCEH Reimbursement Agreements to EFIH

Until August 2012, we were party to two agreements with TCEH related to certain generation-related regulatory assets that were securitized through the issuance of transition bonds by Bondco. One agreement provided for the reimbursement to us by TCEH of our interest expense on the transition bonds, which we recognized as interest income when received. The interest income, which served to offset our interest expense on the transition bonds, totaled $16 million, $32 million and $37 million for the years ended December 31, 2012, 2011 and 2010, respectively. The second agreement consisted of a noninterest bearing note receivable from TCEH to reimburse us for incremental income taxes payable as a result of delivery fee surcharges to customers related to transition bonds. Our financial statements reflected a note receivable from TCEH that totaled zero and $179 million ($41 million reported as current in trade accounts and other receivables from affiliates) at December 31, 2012 and December 31, 2011, respectively, related to these income taxes.

In August 2012, we sold both agreements to EFIH for an aggregate amount of $159 million. At the time of sale, the remaining principal balance on the note was $159 million, and the remaining interest reimbursements to be received through 2016 totaled $51 million. See Note 11 to Financial Statements for additional information related to the sale to EFIH of our interest and tax reimbursement agreements with TCEH.

This transaction was approved by both our board of directors and, from a related party transactions standpoint, by the Audit Committee of the board of directors.

Services provided by EFH Subsidiaries

EFH Corp. subsidiaries charge us for certain administrative services at cost. These costs, which are reported in operation and maintenance expenses, totaled $32 million, $34 million and $36 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Services provided to EFH Subsidiaries

Subsidiaries of EFH Corp. paid us $173,000, $58,000 and $646,000 for the years ended December 31, 2012, 2011 and 2010, respectively, with respect to services we provided to EFH Corp. subsidiaries (excluding revenue, including electricity delivery fees, collected from TCEH). These services included waste management and other services for the year ended December 31, 2012, waste management and fleet management for the year ended December 31, 2011 and environmental health and safety lab, waste management and fleet management for the year ended December 31, 2010.

Warehouse transactions

We and EFH Corp. subsidiaries occasionally issue materials from our warehouses and bill each other for these transactions. We made no payments to EFH Corp. subsidiaries in the years ended December 31, 2012, 2011 and 2010 related to warehouse transactions. EFH Corp. subsidiaries paid us zero, $210,000 and $1 million related to warehouse transactions for the years ended December 31, 2012, 2011 and 2010, respectively.

134

Real Estate Transactions/Shared Facilities

We and EFH Corp. subsidiaries also bill each other for shared facilities. Our payments to EFH Corp. and/or its subsidiaries with respect to shared facilities (including lease payments, utilities and telecommunications equipment) totaled $5 million for the year ended December 31, 2012 and $4 million for each of the years ended December 31, 2011 and 2010. Payments we received from EFH Corp. and/or its subsidiaries with respect to shared facilities totaled $2 million, $840,000 and $374,000 for the years ended December 31, 2012, 2011 and 2010, respectively.

Pension and OPEB Plans

We participate in the EFH Retirement Plan (a defined benefit pension plan sponsored by EFH Corp.). We also participate in the health care and life insurance benefit plan (OPEB Plan) offered by EFH Corp. to eligible employees of EFH Corp. and its subsidiaries and their eligible dependents upon the retirement of such employees from us. In 2012, 2011 and 2010, we made cash contributions to the EFH Retirement Plan totaling $90 million, $172 million and $40 million, respectively and to the OPEB Plan totaling $11 million, $18 million and $18 million, respectively. These amounts include our payments to the plans with respect to pension and OPEB obligations for certain employees of EFH Corp.’s predecessor at the time of deregulation of the Texas electricity market. PURA allows for our recovery of those costs and, as a result, in 2005 we entered into an agreement with EFH Corp.’s predecessor to assume those costs.

In 2012, EFH Corp. made various changes to the EFH Retirement Plan, including splitting off into a new plan all of the assets and liabilities associated with Oncor employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Effective January 1, 2013, Oncor assumed sponsorship of this new plan, referred to herein as the Oncor Retirement Plan. In connection with assuming sponsorship of the Oncor Retirement Plan, we entered into an agreement with certain TXU Energy Company LLC affiliates to assume primary responsibility for benefits of certain participants for whom EFH Corp. bore primary funding responsibility (a closed group of retired and terminated vested plan participants not related to our regulated utility business) as of December 31, 2012. In December 2012, the Oncor Retirement Plan received approximately $850 million of plan assets in connection with this assumption, which equaled the liabilities we assumed for those participants. In addition, in December 2012 we received an aggregate of approximately $10 million in cash and trust fund transfers with respect to supplemental retirement plan and OPEB obligations we assumed for those participants.

For additional information on the pension and OPEB plans, see Note 9 to Financial Statements.

Limited Partnership Interest

We have a 19.5% limited partnership interest, with a carrying value of less than $1 million at December 31, 2012, 2011 and 2010, in an EFH Corp. subsidiary holding principally software-related assets. Equity losses related to this interest are reported in other deductions and totaled less than $1 million for each of the years ended December 31, 2012 and 2011 and $2 million for the year ended December 31, 2010. These losses primarily represent amortization of software assets held by the subsidiary.

Agreements with Oncor Members

Tax-Sharing Agreement

We are not a member of EFH Corp.’s consolidated tax group, but EFH Corp.’s consolidated federal income tax return includes EFH Corp.’s portion of our results due to EFH Corp.’s equity ownership in us. Under the terms of a tax sharing agreement among us, Oncor Holdings, Texas Transmission, Investment LLC and EFH Corp., we are generally obligated to make payments to Texas Transmission, Investment LLC and EFH Corp., pro rata in accordance with their respective membership interests, in an aggregate amount that is substantially equal to the amount of federal income taxes that we would have been required to pay if we were filing our own corporate income tax return. EFH Corp. also includes our results in its consolidated Texas state margin tax 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 under “Income Taxes.” Under the “in lieu of” tax concept, all in lieu of tax assets and tax liabilities represent amounts that will eventually be settled with our members. At December 31, 2012, we had a current state income tax payable to EFH Corp. under the agreement of $22 million, which was reported as

135

a net current tax payable to members. At December 31, 2011, we had federal income tax-related amounts receivable from members under the agreement totaling $27 million ($22 million from EFH Corp. and $5 million from Texas Transmission and Investment LLC) and a current state income tax payable to EFH Corp. of $22 million, which was reported as a net current tax receivable from members of $5 million. We have recorded liabilities in lieu of deferred income taxes of $2,180 million and $2,018 million and for uncertain tax positions of $169 million and $147 million as of December 31, 2012 and 2011, respectively. On a net basis, we received income tax refunds from members of $2 million (including $4 million in refunds from members other than EFH Corp. and $2 million paid to EFH Corp.) in the year ended December 31, 2012. We received income tax refunds from members totaling $114 million (including $25 million in federal income tax-related refunds from members other than EFH Corp.) in the year ended December 31, 2011.

Pursuant to the terms of Investment LLC’s limited liability company agreement, Investment LLC dividends cash it receives from us to the holders of Class B Interests pro rata in accordance with their Class B Interests. See “Executive Compensation – Compensation Discussion and Analysis – Compensation Elements – Long-Term Incentives – Equity Interests Plan and Management Investment Opportunity” for a discussion of investments in Investment LLC by certain of our executive officers and “Executive Compensation—Director Compensation – Purchases of Class B Interests” for a discussion of investments in Investment LLC by certain of our independent directors. The amounts distributed by Investment LLC to the holders of Class B Interests consist of both (1) Investment LLC’s pro rata share of any dividends we pay to members with respect to our earnings, and (2) Investment LLC’s pro rata share of any amounts we pay to members pursuant to our obligations under the tax sharing agreement.

Second Amended and Restated Limited Liability Company Agreement of Oncor

The Second Amended and Restated Limited Liability Company Agreement of Oncor (as amended, Limited Liability Company Agreement), among other things, sets out the members’ respective governance rights in respect of their ownership interests in Oncor. Among other things, the Limited Liability Company Agreement provides for the management of Oncor by a board of directors consisting of 11 members, including at least six Independent Directors (as defined in the Limited Liability Company Agreement), two directors designated directly or indirectly by Texas Transmission (subject to certain conditions), two directors designated indirectly by EFH Corp. and one director that is also an officer of Oncor. Texas Transmission also has the right to designate one non-voting observer to the board of directors, who is entitled to attend all meetings of the board of directors (subject to certain exceptions) and receive copies of all notices and materials provided to the board of directors.

The Limited Liability Company Agreement prohibits Oncor and its subsidiaries from taking certain material actions outside the ordinary course of business without prior approvals by the members, some or all of the Independent Directors and/or the directors designated by one or more of the members. Additionally, the Limited Liability Company Agreement contains provisions regulating capital accounts of members, allocations of profits and losses and tax allocation and withholding.

The Limited Liability Company Agreement also requires that any changes to Oncor’s procedures and limitations on declaring and paying distributions be approved by (i) a majority of the Independent Directors, (ii) all of the EFH Corp. directors and (iii) the Texas Transmission director(s) present and voting, provided that at least one Texas Transmission director must be present and voting in order to approve such matter. In addition, any annual budget with an aggregate amount of capital and operating and maintenance expenditures that are more than 10% less than the capital and operating and maintenance expenditures in the annual budget for the immediately prior fiscal year must be approved by (a) a majority of the Independent Directors and (b) the Texas Transmission director(s) present and voting, provided that at least one Texas Transmission director must be present and voting in order to approve such action. Also, any acquisition of or investment in any third party which involves the purchase of or investment in assets located outside the State of Texas for consideration in an amount greater than $1.5 billion must be approved by (a) a majority of the Independent Directors and (b) the Texas Transmission director(s) present and voting, provided that at least one Texas Transmission director must be present and voting in order to approve such action.

136

Registration Rights Agreement

In November 2008, we entered into a registration rights agreement (Registration Rights Agreement) by and among us, Oncor Holdings, Texas Transmission and EFH Corp. The Registration Rights Agreement grants customary registration rights to certain of our members. Subject to certain limitations set forth in the Registration Rights Agreement, these rights include, without limitation, the following: (i) the right of Oncor Holdings at any time, and after ten years from the date of the Registration Rights Agreement, the right of Texas Transmission, to demand that we register a specified amount of membership interests in accordance with the Securities Act of 1933, as amended; (ii) the right of both Oncor Holdings and Texas Transmission to demand registration of a specified amount of membership interests following an initial public offering; and (iii) the right of all members that are parties to the Registration Rights Agreement to have their membership interests registered if we propose to file a registration statement relating to an offering of membership interests (with certain exceptions).

Subject to certain exceptions, whenever we are required to effect the registration of any membership interests pursuant to the Registration Rights Agreement, we have agreed to use our best efforts to cause the applicable registration statement to become effective, and to keep each such registration statement effective until the earlier of (a) at least 180 days (or two years for a shelf registration statement) or (b) the time at which all securities registered under such registration statement have been sold.

Investor Rights Agreement

The investor rights agreement dated as of November 5, 2008, by and among Oncor, Oncor Holdings, Texas Transmission, EFH Corp. and any other persons that subsequently become a party thereto (Investor Rights Agreement) governs certain rights of certain members of Oncor and EFH Corp. arising out of their direct or indirect ownership of Oncor membership interests, including, without limitation, transfers of Oncor membership interests and restrictions thereon. Among other transfer restrictions, the Investor Rights Agreement provides that, prior to the earlier of the completion of a qualified initial public offering or seven years from the date of the Investor Rights Agreement, Texas Transmission may transfer its Oncor membership interests only to certain permitted transferees or with the prior approval of Oncor Holdings. Following such time period, Texas Transmission may transfer its Oncor membership interests under a registration statement or pursuant to applicable securities laws. The Investor Rights Agreement also grants Texas Transmission certain “tag-along” rights in relation to certain sales of Oncor membership interests by Oncor Holdings. Subject to certain conditions, these “tag-along” rights allow Texas Transmission to sell a pro-rata portion of its Oncor membership interests in the event of a sale of Oncor membership interests by Oncor Holdings on the same terms as Oncor Holdings would receive for its Oncor membership interests. The agreement further provides that under certain offerings of equity securities occurring before an initial public offering of Oncor, Texas Transmission and Oncor Holdings will receive preemptive rights to purchase their pro-rata share of the equity securities to be sold pursuant to such offerings. The Investor Rights Agreement also provides EFH Corp. with a right of first refusal to purchase any Oncor membership interests to be sold in a permitted sale by Texas Transmission or its permitted transferees.

Additionally, Texas Holdings, EFH Corp., certain of EFH Corp.’s subsidiaries and Oncor Holdings have certain “drag-along” rights in relation to offers from third-parties to purchase their directly or indirectly owned membership interests in Oncor, where the resulting sale would constitute a change of control of Oncor. These “drag-along” rights compel Texas Transmission and all other members of Oncor to sell or otherwise transfer their membership interests in Oncor on substantially the same terms as Texas Holdings, EFH Corp., the EFH Corp. subsidiary or Oncor Holdings (as applicable). Pursuant to the Investor Rights Agreement, all members of Oncor that have entered into such agreement must cooperate with Oncor in connection with an initial public offering of Oncor.

Transactions with the Sponsor Group

In October 2007, we entered into our $2 billion secured revolving credit facility with a syndicate of financial institutions and other lenders. The original syndicate included affiliates of GS Capital Partners, a member of the Sponsor Group. Affiliates of GS Capital Partners have from time to time engaged in commercial banking transactions with us in the normal course of business. On October 11, 2011, we amended and restated the secured revolving credit facility. The syndicate, under the amended and restated revolving credit facility, did not include affiliates of GS Capital Partners or any other member of the Sponsor Group. In May 2012 we requested and received a $400 million increase in commitments under the revolving credit facility, and those additional commitments did not include affiliates of GS Capital Partners or any other member of the Sponsor Group. At December 31, 2012 and 2011, members of the Sponsor Group had no outstanding commitments in the revolving credit facility.

137

During the year-to-date period ending October 10, 2011 and each of the years ended December 31, 2010 and 2009, the largest principal amount outstanding under the revolving credit facility attributable to the lender commitments of affiliates of GS Capital Partners was $76 million, $55 million and $25 million, respectively. Under the terms of the revolving credit facility, their commitments to make loans were and are several and not joint. Interest rates under the revolving credit facility for these periods ranged from 0.46% to 0.54%, 0.52% to 0.75% and 0.58% to 1.98%, respectively. Since October 11, 2011, we have had no outstanding borrowings or commitments under the revolving credit facility attributable to the lender commitments of affiliates of GS Capital Partners.

At each of December 31, 2012, 2011 and 2010, we had outstanding borrowings under the revolving credit facility attributable to the lender commitments of affiliates of GS Capital Partners totaling zero, zero and $15 million, respectively, with an interest rate of 0.53% at December 31, 2010.

See Note 5 to Financial Statements for additional information regarding the revolving credit facility.

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.

Goldman, Sachs & Co. (Goldman), an affiliate of the Sponsor Group, received $285,000 in fees for serving as a senior co-dealer manager in our offer to exchange up to an aggregate of $675 million outstanding senior secured notes for new senior secured notes (New Notes) in a private placement exchange that closed in October 2010 and was subsequently registered pursuant to the terms of a registration rights agreement in April 2011. We also agreed in that registration rights agreement to maintain until October 8, 2020, subject to certain permitted suspensions, an effective market maker registration statement for the benefit of Goldman with respect to the senior secured notes issued in such exchange. This transaction was ratified by our Audit Committee in accordance with our related party transactions policy. See Note 6 to Financial Statements for information regarding the debt exchange. In addition to our market maker registration statement commitments in 2010, in connection with earlier debt offerings in which Goldman participated we agreed to maintain an effective market maker registration statement for the benefit of Goldman with respect to certain other senior secured notes until September 8, 2018.

In September 2010, we completed a $475 million senior secured notes private placement offering. In conjunction with the offering, we entered into a registration rights agreement with various investment banks as representatives of the initial purchasers in the private placement. KKR Capital Markets LLC, an affiliate of KKR (a member of the Sponsor Group), received $125,000 in fees for serving as a co-manager in the offering. Affiliates of KKR Capital Markets LLC collectively own an approximately 37% membership interest in the general partner of Texas Energy Future Holdings Limited Partnership (TEF), the parent of EFH Corp., as well as a limited partnership interest in TEF. Certain KKR Capital Markets LLC executives have interests in such affiliated entities. This transaction was ratified by our Audit Committee in accordance with our related-party transactions policy.

We have entered into, and may continue to enter into, arrangements with members of the Sponsor Group and/or their respective affiliates to use their products and services in the ordinary course of their business, which often result in revenues to members of the Sponsor Group or their respective affiliates in excess of $120,000 annually.

Agreements with Management and Directors

Consulting Agreement

We entered into a consulting agreement with Rob D. Trimble III effective upon his retirement from the company on April 1, 2010. Mr. Trimble served as our President prior to his retirement. Under the consulting agreement, Mr. Trimble serves as an advisor to our executive management and transitions his knowledge and experience to our management. Mr. Trimble was paid $150,000 for the consulting services he provided in 2010 pursuant to the terms of the agreement. The consulting agreement also provides that we will reimburse Mr. Trimble for the cost of financial planning services and an annual physical health examination, and in 2010, we paid Mr. Trimble $8,875 for financial planning services and $1,624 for a physical health examination. Either party may terminate the agreement upon written notice to the other party. In the event Mr. Trimble terminates the consulting agreement, or in the event of certain terminations of the consulting agreement by us, Mr. Trimble will be required to reimburse to us a pro-rated portion of any retainer received for the year in which termination occurs.

138

Management Investment Opportunity

Each executive officer participating in the Management Investment Opportunity entered into a management stockholder’s agreement and sale participation agreement with us. Each director that purchased Class B Interests of Investment LLC in 2009 entered into a director stockholder’s agreement and a sale participation agreement with us. The terms of these agreements, which were approved by the O&C Committee, are detailed below.

Management Stockholder’s Agreement

The management stockholder’s agreement contains restrictions on the participant’s ability to transfer any Class B Interests. Except in certain limited circumstances, any Oncor equity interests or Class B Interests beneficially owned by the participant will be non-transferable prior to the later of (1) October 10, 2012 or (2) with respect to certain interests, a “qualified public offering” (as defined in the management stockholder’s agreement). In addition, the management stockholder’s agreement gives the Company certain rights of first refusal in the event the participant attempts to sell any Oncor equity interests or Class B Interests after October 10, 2012, but prior to the earlier to occur of (1) a “change in control” (as defined in the management stockholder’s agreement) or (2) consummation of a qualified public offering of Oncor.

In addition, the management stockholder’s agreement gives us certain rights to repurchase the participant’s Class B Interests (1) if the participant terminates his employment without “good reason” (as defined in the management stockholder’s agreement) prior to October 10, 2012, at a price equal purchase price paid by the participant for the Class B Interests; or (2) if we terminate the participant’s employment for cause (as defined in the management stockholder’s agreement) or if the participant violates certain of his or her non-compete obligations, at a price equal to the lesser of the fair market value of the Class B Interests or the purchase price paid by the participant for the Class B Interests. The management stockholder’s agreement also gives the participant or the participant’s estate, as applicable, certain rights to compel our company to repurchase its Oncor equity interests and Class B Interests upon the death or disability of the participant for a price equal to the fair market value of the Oncor equity interests and Class B Interests. Generally, these rights will terminate on the earlier of (a) a change in control of Oncor or (b) the later of (i) October 10, 2012, or (ii) a public offering of Oncor or Investment LLC equity.

The management stockholder’s agreement also provides that if the participant terminates his employment without good reason prior to October 10, 2012, we may redeem the vested SARs at a per unit purchase price equal to the excess, if any, of the fair market value over the base price of the SARs, less 20% of the excess. In addition, if the participant so terminates his employment, the participant must pay us 20% of the amount by which any cash payment received in respect of previously vested and exercised SARs exceeded the base price of those SARs. If the participant terminates his employment without good reason on or after October 10, 2012, we may redeem the vested SARs at a per unit purchase price equal to the excess, if any, of the fair market value over the base price of the SARs. Furthermore, the management stockholder’s agreement provides that upon the death or disability of the participant, the participant or participant’s estate, as applicable, will be entitled to receive, in exchange for the vested SARs, a cash payment equal to the product of (1) the excess, if any, of the fair market value over the base price of the SARs and (2) the number of SARs then credited to the participant. Generally, these rights will terminate on the earlier of (a) a change in control of Oncor or (b) the later of (i) October 10, 2012, or (ii) a public offering of Oncor or Investment LLC equity.

Furthermore, the management stockholder’s agreement provides that, subject to certain conditions, the participant will receive certain piggy-back rights to sell its Oncor equity interests and Class B Interests to Oncor if there is a proposed sale by the Sponsor Group or Texas Holdings of (1) the common stock of EFH Corp.; or (2) a sale of 50% or more of the outstanding partnership interests of Texas Holdings. Subject to certain conditions, the participant will also receive these rights if Oncor Holdings proposes to sell any of its Oncor equity interests. Additionally, the participant will be subject to certain drag-along rights in the event (a) Texas Holdings or a member of the Sponsor Group proposes to sell a number of shares of common stock of EFH Corp. or limited partnership interests of Texas Holdings equal to 50% or more of the outstanding shares of common stock of EFH Corp. or limited partnership interests of Texas Holdings, as applicable; or (b) Oncor Holdings proposes to sell 50% or more of the outstanding Oncor equity interests. Generally, these rights will terminate on the earlier of (a) a change in control of Oncor or (b) the later of (i) October 10, 2012, or (ii) a public offering of Oncor or Investment LLC equity.

The management stockholder’s agreement also contains certain non-compete provisions, including a restriction on the participant from engaging in a competing business during the term of the participant’s employment with us and for 12 months following his or her termination of employment with us.

139

Director Stockholder’s Agreement

The director stockholder’s agreement contains restrictions on the participant’s ability to transfer any Class B Interests. Until the earlier of a “qualified public offering” (as defined in the director stockholder’s agreement), five years from the date of the agreement or the occurrence of a “change of control” (as defined in the director stockholder’s agreement) in the event a director proposes to transfer any Oncor equity interests or Class B Interests, except in certain limited circumstances, such director must first offer such equity interests or Class B Interests to us or Investment LLC, as applicable.

Furthermore, the director stockholder’s agreement provides that, subject to certain conditions, the participant will receive certain piggy-back rights to sell its Oncor equity interests and Class B Interests to Oncor if there is a proposed sale by the Sponsor Group or Texas Holdings of (1) the common stock of EFH Corp.; or (2) 50% or more of the outstanding partnership interests of Texas Holdings. Subject to certain conditions, the participant will also receive these rights if Oncor Holdings proposes to sell any of its Oncor equity interests. Additionally, the participant will be subject to certain drag-along rights in the event (a) Texas Holdings or a member of the Sponsor Group proposes to sell a number of shares of common stock of EFH Corp. or limited partnership interests of Texas Holdings equal to 50% or more of the outstanding shares of common stock of EFH Corp. or limited partnership interests of Texas Holdings, as applicable; or (b) Oncor Holdings proposes to sell 50% or more of the outstanding Oncor equity interests. Generally, the rights described in this paragraph will terminate on the earlier of a change in control of Oncor or the later of (i) five years from the date of the agreement, or (ii) a public offering of Oncor or Investment LLC equity.

Sale Participation Agreements

The sale participation agreements entered into by members of our management and board of directors in connection with their investments in Investment LLC give us, Oncor Holdings and certain of Oncor Holdings’ investors drag-along rights in the event Oncor, Oncor Holdings or certain of Oncor Holdings’ investors engage in corporate transactions in which they sell a direct or indirect equity interest in Oncor. In addition, the sale participation agreement gives the participant tag-along rights in the event Oncor, Oncor Holdings or certain of Oncor Holdings’ investors engage in corporate transactions in which they sell a direct or indirect equity interest in Oncor. The form of sale participation agreement entered into by management is identical to the form of sale participation agreement entered into by directors, except with respect to termination of the agreement. In the case of management, the rights described in this paragraph will terminate on the earlier of (1) a change in control of Oncor or (2) the later of (a) October 10, 2012 or (b) certain public offerings of Oncor’s equity interests. In the case of directors, the rights described in this paragraph will terminate on the earlier of (i) a change in control of Oncor or (ii) the later of (x) five years from the date of the agreement or (y) certain public offerings of Oncor’s equity interests.

140

Director Independence

Our Limited Liability Company Agreement provides that six members of our board of directors must be deemed independent. For a director to be deemed independent, our board of directors must affirmatively determine that such director does not have a material relationship with Oncor or EFH Corp. or their respective successors and subsidiaries, any entity that controls or owns directly or indirectly more than 49% of the equity interests in Oncor, and certain other specified entities that directly or indirectly own securities of Oncor (collectively, the Non-Ring Fenced Entities). In addition, under our Limited Liability Company Agreement, to be deemed independent, a director must also meet the independence standards in Section 303A of the New York Stock Exchange Manual in all material respects. Our Limited Liability Company Agreement further provides that a director that otherwise meets these requirements will not be precluded from qualifying as independent if such director otherwise meets such criteria but (i) served as a director or shareholder of EFH Corp. prior to the October 2007 merger of Texas Energy Future Merger Sub Corp. with and into EFH Corp., (ii) indirectly or beneficially owns equity interests through a mutual fund or similar investment vehicle with respect to which the director does not have discretion or control over the investments held by such investment vehicle, (iii) directly or indirectly holds an amount of legal or beneficial stock in any of the Non-Ring Fenced Entities that is de minimis and which the other independent directors determine would not reasonably be expected to influence the judgment of such director in determining the interests of Oncor or its members, or (iv) is a ratepayer, supplier, creditor or independent contractor of, or a person who received any benefit from or provided any services to, Oncor, Oncor Holdings or any of the Non-Ring Fenced Entities, if the other independent directors determine that such relationship would not reasonably be expected to influence the judgment of the director in determining the interests of Oncor or its members.

In addition, our Limited Liability Company Agreement requires that two of the six independent members of our board of directors also meet additional independence qualifications. These directors, known as special independent directors, may not, during their service as a director or at any time in the five years preceding their appointment, be (i) a direct or indirect legal or beneficial owner in Oncor, Oncor Holdings or any of the Non-Ring Fenced Entities, (ii) a creditor; supplier; employee; officer; director; family member of any officer, employee or director; manager or contractor of Oncor, Oncor Holdings or any of the Non-Ring Fenced Entities, or (iii) a person who controls (directly, indirectly or otherwise) Oncor, Oncor Holdings or any of the Non-Ring Fenced Entities or any creditor, supplier, employee, officer, director, manager or contractor of Oncor, Oncor Holdings or any of the Non-Ring Fenced Entities. However, a director will not be precluded from being deemed a special independent director if such director otherwise meets the requirements but (i) indirectly or beneficially owns stock through a mutual fund or similar diversified investment vehicle (other than investment vehicles affiliated with KKR, TPG or Goldman Sachs & Co.), or (ii) directly or indirectly legally or beneficially owns interests in a Non-Ring Fenced Entity, if such ownership does not exceed one percent of the net worth of such director. A special independent director may also serve as an independent director of Oncor Holdings or any of Oncor’s subsidiaries.

Our board of directors has determined that Ms. Brownell and Messrs. Estrada, Dunning, Ford, Hill and Wortham are independent directors under the standards in Section 303A of the New York Stock Exchange Manual and the other standards in our Limited Liability Company Agreement. Further, our board of directors has determined that each of Ms. Brownell and Mr. Hill qualifies as a special independent director under the standards set forth in our Limited Liability Company Agreement.

In July 2010, our board of directors created the position of Lead Independent Director and appointed Mr. Dunning to serve in that role. The Lead Independent Director presides at meetings of the independent directors, serves as a liaison to the EFH Corp. board of directors, and performs such duties and responsibilities as may be specified by the board.

Our board of directors has designated an Audit Committee, Nominating and Governance Committee and Organization and Compensation Committee to exercise certain powers and authorities of the board of the directors. Members of these committees are not required by our Limited Liability Company Agreement or board of directors to meet any independence standards. Mr. Liaw has served on the Organization and Compensation Committee since the committee’s inception, and Mr. Zucchet was appointed to such committee effective May 5, 2010. Mr. Byers was appointed to the Audit Committee effective December 19, 2008 and served in such capacity until his departure from our board of directors in October 2012. Mr. Ranger, who was appointed by Texas Transmission to replace Mr. Byers on our board of director, joined our board of directors in October 2012 and was appointed to the audit committee effective January 9, 2013. Mr. Ferguson and Mr. Zucchet were appointed to the Nominating and Governance Committee effective February 15, 2011. None of Mr. Liaw, Mr. Zucchet, Mr. Byers, Mr. Rheal or Mr. Ferguson qualifies as an independent director for purposes of our Limited Liability Company Agreement.

141

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Deloitte & Touche LLP is our independent auditor.

In 2008, our Audit Committee adopted a policy governing the engagement of our independent auditor. The policy provides that in addition to the audit of the financial statements, related quarterly reviews and other audit services, and providing services necessary to complete SEC filings, our independent auditor may be engaged to provide non-audit services as described herein. Prior to engagement, all services to be rendered by the independent auditor must be authorized by our Audit Committee in accordance with pre-approval procedures which are defined in the policy. The pre-approval procedures require:

1. the annual review and pre-approval by our Audit Committee of all anticipated audit and non-audit services, and

2. the quarterly pre-approval by our Audit Committee of services, if any, not previously approved and the review of the status of previously approved services.

Our Audit Committee may also approve certain ongoing non-audit services not previously approved in the limited circumstances provided for in the SEC rules. All services performed in 2012 by Deloitte & Touche LLP, the member firms of Deloitte & Touche Tohmatsu and their respective affiliates (Deloitte & Touche) were pre-approved by our Audit Committee.

The policy defines those non-audit services which our independent auditor may also be engaged to provide as follows:

1. Audit-related services, including:

a. due diligence, accounting consultations and audits related to mergers, acquisitions and divestitures;

b. employee benefit plan and political action plan audits;

c. accounting and financial reporting standards consultation;

d. internal control reviews, and

e. attest services, including agreed-upon procedures reports that are not required by statute or regulation.

2. Tax-related services, including:

a. tax compliance;

b. general tax consultation and planning;

c. tax advice related to mergers, acquisitions and divestitures, and

d. communications with and request for rulings from tax authorities.

3. Other services, including:

a. process improvement, review and assurance;

b. litigation and rate review assistance;

c. forensic and investigative services, and

d. training services.

The policy prohibits us from engaging our independent auditor to provide:

1. bookkeeping or other services related to our accounting records or financial statements;

2. financial information systems design and implementation services;

3. appraisal or valuation services, fairness opinions or contribution-in-kind reports;

4. actuarial services;

5. internal audit outsourcing services;

6. management or human resources functions;

7. broker-dealer, investment advisor or investment banking services;

8. legal and expert services unrelated to the audit, and

9. any other service that the Public Company Accounting Oversight Board determines, by regulation, to be impermissible.

In addition, the policy prohibits our independent auditor from providing tax or financial planning advice to any of our officers.

142

The policy also contains the following standard of conduct for our independent auditor related to staffing and conducting its annual audit:

1. no member performing the audit of our financial statements will be under the direction of the lead member of such firm conducting the financial statement audit work for EFH Corp.;

2. the audit team will reach its own conclusions as to the sufficiency and adequacy of the audit procedures necessary to conduct the audit;

3. the audit team accepts the sole responsibility for the opinion on our financial statements;

4. the audit team may use other EFH Corp. auditors as a service provider;

5. the audit team may consider the EFH Corp. Sarbanes-Oxley Act compliance audit team as a service provider;

6. the audit team may consider the EFH Corp. tax compliance audit team as a service provider;

7. the audit team is not prohibited from sharing the results of its audit procedures or conclusions with the EFH Corp. audit team so that an opinion on EFH Corp.’s consolidated financial statements can be rendered;

8. our independent auditor shall be bound by the professional standards and theRules for the Accounting Profession of the Texas State Board of Public Accountancy regarding confidentiality of client information;

9. the audit team will have a separate engagement letter with the Audit Committee and will render separate billings for audit work pursuant to such contract directly to our designated employee, and

10. the audit team will address its reports to our Audit Committee, board of directors and/or management team as appropriate.

Compliance with our Audit Committee’s policy relating to the engagement of Deloitte & Touche is monitored on behalf of our Audit Committee by our chief internal audit executive. Reports from Deloitte & Touche and the chief internal audit executive describing the services provided by Deloitte & Touche and fees for such services are provided to our Audit Committee no less often than quarterly.

For the years ended December 31, 2012 and 2011, fees billed (in US dollars) to us by Deloitte & Touche were as follows:

	2012		2011
Audit Fees. Fees for services necessary to perform the annual audit, review SEC filings, fulfill statutory and other attest service requirements and provide comfort letters and consents.	$	1,772,000	$	1,454,000
Audit-Related Fees.Fees for services including employee benefit plan audits, due diligence related to mergers, acquisitions and divestitures, accounting consultations and audits in connection with acquisitions, internal control reviews, attest services that are not required by statute or regulation, and consultation concerning financial accounting and reporting standards		175,000		71,000
Tax Fees.Fees for tax compliance, tax planning, and tax advice related to mergers and acquisitions, divestitures, and communications with and requests for rulings from taxing authorities.		—		—
All Other Fees. Fees for services including process improvement reviews, forensic accounting reviews and litigation and rate review assistance		—		—
Total	$	1,947,000	$	1,525,000

143

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The consolidated financial statement schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the consolidated financial statements or notes thereto.

(b) Exhibits:

Exhibits	Previously Filed* With File Number	As Exhibit
3(i)	Articles of Incorporation
3(a)	333-100240 Form 10-Q (filed November 14, 2007)	3(a)	—	Certificate of Formation of Oncor Electric Delivery Company LLC.
3(ii)	By-laws
3(b)	333-100240 Form 10-Q (filed November 6, 2008)	3(a)	—	Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Company LLC, dated as of November 5, 2008, by and among Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Oncor Management Investment LLC.
3(c)	333-100240 2008 Form 10-K (filed March 3, 2009)	3(c)	—	First Amendment to Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Company LLC, entered into as of February 18, 2009, by and among Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Oncor Management Investment LLC
(4)	Instruments Defining the Rights of Security Holders, Including Indentures.
4(a)	333-100240 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York, as Trustee.
4(b)	001-12833 Form 8-K (filed October 31, 2005)	10.1	—	Supplemental Indenture No. 1, dated October 25, 2005, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York.
4(c)	333-100240 Form S-4 (filed October 2, 2002)	4(b)	—	Officer’s Certificate, dated May 6, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes due 2012 and 7.000% Senior Notes due 2032.
4(d)	333-106894 Form S-4 (filed July 9, 2003)	4(c)	—	Officer’s Certificate, dated December 20, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes due 2015 and 7.250% Senior Notes due 2033.
4(e)	333-100240 Form 10-Q (filed May 15, 2008)	4(b)	—	Supplemental Indenture No. 2, dated May 15, 2008, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York.
4(f)	333-100242 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture (for Unsecured Debt Securities), dated as of August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York, as Trustee.

144

Exhibits	Previously Filed* With File Number	As Exhibit
4(g)	333-100240 Form 10-Q (filed May 15, 2008)	4(c)	—	Supplemental Indenture No. 1, dated May 15, 2008, to Indenture and Deed of Trust, dated as of August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York.
4(h)	333-100242 Form S-4 (filed October 2, 2002)	4(b)	—	Officer’s Certificate, dated August 30, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 5% Debentures due 2007 and 7% Debentures due 2022.
4(i)	333-100240 Form 8-K (filed September 9, 2008)	4.1	—	Officer’s Certificate, dated September 8, 2008, establishing the terms of Oncor Electric Delivery Company LLC’s 5.95% Senior Secured Notes due 2013, 6.80% Senior Secured Notes due 2018 and 7.50% Senior Secured Notes due 2038.
4(j)	333-100240 Form 10-Q (filed November 6, 2008)	4(c)	—	Investor Rights Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
4(k)	333-100240 Form 10-Q (filed November 6, 2008)	4(d)	—	Registration Rights Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Energy Future Holdings Corp. and Texas Transmission Investment LLC.
4(l)	333-100240 Form 10-Q (filed May 15, 2008)	4(a)	—	Deed of Trust, Security Agreement and Fixture Filing, dated as of May 15, 2008, by Oncor Electric Delivery Company LLC, as Grantor, to and for the benefit of The Bank of New York, as Collateral Agent.
4(m)	333-100240 2008 Form 10-K (filed March 3, 2009)	4(n)	—	First Amendment to Deed of Trust, dated as of March 2, 2009, by and between Oncor Electric Delivery Company LLC and The Bank of New York Mellon (formerly The Bank of New York) as Collateral Agent.
4(n)	333-100240 Form 8-K (filed September 3, 2010)	10.1	—	Second Amendment to Deed of Trust, Security Agreement and Fixture Filing dated as of September 3, 2010 by and between Oncor Electric Delivery Company LLC, as Grantor, to and for the benefit of The Bank of New York Mellon, as Collateral Agent.
4(o)	333-100240 Form 8-K (filed November 15, 2011)	10.1	—	Third Amendment to Deed of Trust, Security Agreement and Fixture Filing dated November 10, 2011 by and between Oncor Electric Delivery Company LLC, as Grantor, 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.
4(p)	333-100240 Form 8-K (filed September 16, 2010)	4.1	—	Officer’s Certificate, dated September 13, 2010, establishing the terms of Oncor’s 5.25% Senior Secured Notes due 2040.
4(q)	333-100240 Form 8-K (filed October 12, 2010)	4.1	—	Officer’s Certificate, dated October 8, 2010, establishing the terms of Oncor’s 5.00% Senior Secured Notes due 2017 and 5.75% Senior Secured Notes due 2020.

145

Exhibits	Previously Filed* With File Number	As Exhibit
4(r)	333-100240 Form 8-K (filed November 23, 2011)	4.1	—	Officer’s Certificate, dated November 23, 2011, establishing the terms of Oncor’s 4.55% Senior Secured Notes due 2041.
4(s)	333-100240 Form 8-K (filed May 18, 2012)	4.1	—	Officer’s Certificate, dated May 18, 2012, establishing the terms of Oncor’s 4.10% Senior Secured Notes due 2022 and Oncor’s 5.30% Senior Secured Notes due 2042.
4(t)	333-100240 Form 8-K (filed May 18, 2012)	4.2	—	Registration Rights Agreement, dated May 18, 2012, among Oncor and the representatives of the initial purchasers of Oncor’s 4.10% Senior Secured Notes due 2022 and Oncor’s 5.30% Senior Secured Notes due 2042.
(10)	Material Contracts.
	Management Contracts; Compensatory Plans, Contracts and Arrangements
10(a)	333-100240 2007 Form 10-K (filed March 31, 2008)	10(i)	—	Oncor Electric Delivery Company LLC Non-employee Director Compensation Arrangement.
10(b)	333-100240 Form 8-K (filed February 23, 2009)	10.1	—	Form of Management Stockholder Agreement (Senior Management Form).
10(c)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(l)	—	Form of Director Stockholder’s Agreement.
10(d)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(m)	—	Form of Director Sale Participation Agreement.
10(e)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(n)	—	Oncor Electric Delivery Company LLC Director Stock Appreciation Rights Plan.
10(f)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(o)	—	Form of Stock Appreciation Rights Award Letter pursuant to the Director Stock Appreciation Rights Plan.
10(g)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(p)	—	2008 Equity Interests Plan for Key Employees of Oncor Electric Delivery Company LLC and its affiliates.
10(h)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(q)	—	Form of Sale Participation Agreement (Management Form).
10(i)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(r)	—	Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan.
10(j)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(s)	—	Form of Stock Appreciation Rights Award Letter pursuant to the Stock Appreciation Rights Plan.

146

Exhibits	Previously Filed* With File Number	As Exhibit
10(k)	333-100240 2009 Form 10-K (filed February 19, 2010)	10(p)	—	Oncor Salary Deferral Program.
10(l)	333-100240 2009 Form 10-K (filed February 19, 2010)	10(q)	—	Oncor Supplemental Retirement Plan.
10(m)	001-12833 2005 Form 10-K (filed March 6, 2006)	10(gg)	—	EFH Split Dollar Life insurance Program, as amended and restated, executed March 2, 2006, effective as of May 20, 2005.
10(n)	001-12833 2007 Form 10-K (filed March 31, 2008)	10(n)	—	Amendment to the EFH Split Dollar Life Insurance Program, effective as of October 10, 2007.
10(o)	333-100240 2010 Form 10-K (filed February 18, 2011)	10(w)	—	Oncor Electric Delivery Company LLC Executive Change in Control Policy.
10(p)	333-100240 2010 Form 10-K (filed February 18, 2011)	10(x)	—	Oncor Electric Delivery Company LLC Executive Severance Plan and Summary Plan Description.
10(q)	333-100240 2010 Form 10-K (filed February 18, 2011)	10(y)	—	Oncor Electric Delivery Company LLC Second Amended and Restated Executive Annual Incentive Plan.
10(r)	333-100240 Form 10-Q (filed July 29, 2011)	10(a)	—	Oncor Electric Delivery Company LLC Third Amended and Restated Executive Annual Incentive Plan.
10(s)			—	Retention Agreement, effective as of February 12, 2013, between Oncor Electric Delivery Company LLC and E. Allen Nye, Jr.
10(t)			—	Oncor Electric Delivery Company LLC Long-Term Incentive Plan.
10(u)			—	Form of Oncor Electric Delivery Company LLC Long-Term Incentive Plan Award Agreement.
	Credit Agreements
10(v)	333-100240 Form 8-K (filed October 11, 2011)	10.1	—	Amended and Restated Revolving Credit Agreement, dated as of October 11, 2011, among Oncor Electric Delivery Company LLC, as borrower, the lenders listed therein, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., as swingline lender, and JPMorgan Chase Bank, N.A., Barclays Bank PLC, The Royal Bank of Scotland plc, Bank of America, N.A. and Citibank, N.A., as fronting banks for letters of credit issued thereunder.

147

Exhibits	Previously Filed* With File Number	As Exhibit
10(w)	333-100240 Form 8-K (filed May 15, 2012)	10.1	—	Joinder Agreement, dated as of May 15, 2012, by and among Oncor, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent under the Credit Agreement, swingline lender and fronting bank, Barclays Bank PLC, Bank of America, N.A., Citibank, N.A. and The Royal Bank of Scotland PLC, as fronting banks, and each party identified as an “Incremental Lender” on the signature pages thereto.
	Other Material Contracts
10(x)	333-100240 2004 Form 10-K (filed March 23, 2005)	10(i)	—	Agreement, dated as of March 10, 2005, by and between Oncor Electric Delivery Company LLC and certain TXU Energy Company LLC affiliates allocating to Oncor Electric Delivery Company LLC the pension and post-retirement benefit costs for all Oncor Electric Delivery Company LLC employees who had retired or had terminated employment as vested employees prior to January 1, 2002.
10(y)	333-100240 Form 10-Q (filed November 6, 2008)	10(b)	—	Amended and Restated Tax Sharing Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Oncor Management Investment LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
10(z)	001-12833 2007 Form 10-K (filed March 31, 2008)	10(eee)	—	Stipulation as approved by the PUCT in Docket No. 34077.
10(aa)	001-12833 2007 Form 10-K (filed March 31, 2008)	10(fff)	—	Amendment to Stipulation Regarding Section 1, Paragraph 35 and Exhibit B in Docket No. 34077.
10(ab)	333-100240 2010 Form 10-K (filed February 18, 2011)	10(ae)	—	PUCT Order on Rehearing in Docket No. 34077.
(12)	Statement Regarding Computation of Ratios.
12(a)			—	Computation of Ratio of Earnings to Fixed Charges, and Ratio of Earnings to Combined Fixed Charges and Preference Dividends.
(21)	Subsidiaries of the Registrant.
21(a)			—	Subsidiaries of Oncor Electric Delivery Company LLC.
(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.

148

Exhibits	Previously Filed* With File Number	As Exhibit
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(a)	333-91935 Form S-3 (filed July 1, 2003)	99(a)	—	Financing Order.
99(b)	333-91935 Form S-3 (filed July 1, 2003)	99(b)	—	Internal Revenue Service Private Letter Ruling pertaining to the transition bonds, dated May 21, 2002.
99(c)	333-91935 Form S-3 (filed July 1, 2003)	99(c)	—	Internal Revenue Service Private Letter Ruling pertaining to the transition bonds, dated February 18, 2000.
	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.

** Furnished herewith

149

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Oncor Electric Delivery Company LLC has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ONCOR ELECTRIC DELIVERY COMPANY LLC
Date: February 19, 2013
	By	/s/ ROBERT S. SHAPARD
		(Robert S. Shapard, Chairman of the Board and Chief Executive)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Oncor Electric Delivery Company LLC and in the capacities and on the date indicated.

Signature	Title	Date
/s/ ROBERT S. SHAPARD	Principal Executive	February 19, 2013
(Robert S. Shapard, Chairman of the Board and Chief Executive)	Officer and Director
/s/ DAVID M. DAVIS	Principal Financial Officer	February 19, 2013
(David M. Davis, Senior Vice President and Chief Financial Officer)
/s/ RICHARD C. HAYS	Principal Accounting Officer	February 19, 2013
(Richard C. Hays, Controller)
/s/ NORA MEAD BROWNELL	Director	February 19, 2013
(Nora Mead Brownell)
/s/ THOMAS M. DUNNING	Director	February 19, 2013
(Thomas M. Dunning)
/s/ ROBERT A. ESTRADA	Director	February 19, 2013
(Robert A. Estrada)
/s/ THOMAS D. FERGUSON	Director	February 19, 2013
(Thomas D. Ferguson)
/s/ MONTE E. FORD	Director	February 19, 2013
(Monte E. Ford)
/s/ WILLIAM T. HILL, JR.	Director	February 19, 2013
(William T. Hill, Jr.)
/s/ JEFFREY LIAW	Director	February 19, 2013
(Jeffrey Liaw)
/s/ RHEAL R. RANGER	Director	February 19, 2013
(Rheal R, Ranger)
/s/ RICHARD W. WORTHAM III	Director	February 19, 2013
(Richard W. Wortham III)
/s/ STEVEN J. ZUCCHET	Director	February 19, 2013
(Steven J. Zucchet)

150

EXHIBIT INDEX

Exhibits	Previously Filed* With File Number	As Exhibit
3(i)	Articles of Incorporation
3(a)	333-100240 Form 10-Q (filed November 14, 2007)	3(a)	—	Certificate of Formation of Oncor Electric Delivery Company LLC.
3(ii)	By-laws
3(b)	333-100240 Form 10-Q (filed November 6, 2008)	3(a)	—	Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Company LLC, dated as of November 5, 2008, by and among Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Oncor Management Investment LLC.
3(c)	333-100240 2008 Form 10-K (filed March 3, 2009)	3(c)	—	First Amendment to Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Company LLC, entered into as of February 18, 2009, by and among Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Oncor Management Investment LLC.
(4)	Instruments Defining the Rights of Security Holders, Including Indentures.
4(a)	333-100240 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York, as Trustee.
4(b)	001-12833 Form 8-K (filed October 31, 2005)	10.1	—	Supplemental Indenture No. 1, dated October 25, 2005, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York.
4(c)	333-100240 Form S-4 (filed October 2, 2002)	4(b)	—	Officer’s Certificate, dated May 6, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes due 2012 and 7.000% Senior Notes due 2032.
4(d)	333-106894 Form S-4 (filed July 9, 2003)	4(c)	—	Officer’s Certificate, dated December 20, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes due 2015 and 7.250% Senior Notes due 2033.
4(e)	333-100240 Form 10-Q (filed May 15, 2008)	4(b)	—	Supplemental Indenture No. 2, dated May 15, 2008, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York.
4(f)	333-100242 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture (for Unsecured Debt Securities), dated as of August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York, as Trustee.
4(g)	333-100240 Form 10-Q (filed May 15, 2008)	4(c)	—	Supplemental Indenture No. 1, dated May 15, 2008, to Indenture and Deed of Trust, dated as of August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York.

151

Exhibits	Previously Filed* With File Number	As Exhibit
4(h)	333-100242 Form S-4 (filed October 2, 2002)	4(b)	—	Officer’s Certificate, dated August 30, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 5% Debentures due 2007 and 7% Debentures due 2022.
4(i)	333-100240 Form 8-K (filed September 9, 2008)	4.1	—	Officer’s Certificate, dated September 8, 2008, establishing the terms of Oncor Electric Delivery Company LLC’s 5.95% Senior Secured Notes due 2013, 6.80% Senior Secured Notes due 2018 and 7.50% Senior Secured Notes due 2038.
4(j)	333-100240 Form 10-Q (filed November 6, 2008)	4(c)	—	Investor Rights Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
4(k)	333-100240 Form 10-Q (filed November 6, 2008)	4(d)	—	Registration Rights Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Energy Future Holdings Corp. and Texas Transmission Investment LLC.
4(l)	333-100240 Form 10-Q (filed May 15, 2008)	4(a)	—	Deed of Trust, Security Agreement and Fixture Filing, dated as of May 15, 2008, by Oncor Electric Delivery Company LLC, as Grantor, to and for the benefit of The Bank of New York, as Collateral Agent.
4(m)	333-100240 2008 Form 10-K (filed March 3, 2009)	4(n)	—	First Amendment to Deed of Trust, dated as of March 2, 2009, by and between Oncor Electric Delivery Company LLC and The Bank of New York Mellon (formerly The Bank of New York) as Collateral Agent.
4(n)	333-100240 Form 8-K (filed September 3, 2010)	10.1	—	Second Amendment to Deed of Trust, Security Agreement and Fixture Filing dated as of September 3, 2010 by and between Oncor Electric Delivery Company LLC, as Grantor, to and for the benefit of The Bank of New York Mellon, as Collateral Agent.
4(o)	333-100240 Form 8-K (filed November 15, 2011)	10.1	—	Third Amendment to Deed of Trust, Security Agreement and Fixture Filing dated November 10, 2011 by and between Oncor Electric Delivery Company LLC, as Grantor, 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.
4(p)	333-100240 Form 8-K (filed September 16, 2010)	4.1	—	Officer’s Certificate, dated September 13, 2010, establishing the terms of Oncor’s 5.25% Senior Secured Notes due 2040.
4(q)	333-100240 Form 8-K (filed October 12, 2010)	4.1	—	Officer’s Certificate, dated October 8, 2010, establishing the terms of Oncor’s 5.00% Senior Secured Notes due 2017 and 5.75% Senior Secured Notes due 2020.
4(r)	333-100240 Form 8-K (filed November 23, 2011)	4.1	—	Officer’s Certificate, dated November 23, 2011, establishing the terms of Oncor’s 4.55% Senior Secured Notes due 2041.

152

Exhibits	Previously Filed* With File Number	As Exhibit
4(s)	333-100240 Form 8-K (filed May 18, 2012)	4.1	—	Officer’s Certificate, dated May 18, 2012, establishing the terms of Oncor’s 4.10% Senior Secured Notes due 2022 and Oncor’s 5.30% Senior Secured Notes due 2042.
4(t)	333-100240 Form 8-K (filed May 18, 2012)	4.2	—	Registration Rights Agreement, dated May 18, 2012, among Oncor and the representatives of the initial purchasers of Oncor’s 4.10% Senior Secured Notes due 2022 and Oncor’s 5.30% Senior Secured Notes due 2042.
(10)	Material Contracts.
	Management Contracts; Compensatory Plans, Contracts and Arrangements
10(a)	333-100240 2007 Form 10-K (filed March 31, 2008)	10(i)	—	Oncor Electric Delivery Company LLC Non-employee Director Compensation Arrangement.
10(b)	333-100240 Form 8-K (filed February 23, 2009)	10.1	—	Form of Management Stockholder Agreement (Senior Management Form).
10(c)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(l)	—	Form of Director Stockholder’s Agreement.
10(d)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(m)	—	Form of Director Sale Participation Agreement.
10(e)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(n)	—	Oncor Electric Delivery Company LLC Director Stock Appreciation Rights Plan.
10(f)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(o)	—	Form of Stock Appreciation Rights Award Letter pursuant to the Director Stock Appreciation Rights Plan.
10(g)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(p)	—	2008 Equity Interests Plan for Key Employees of Oncor Electric Delivery Company LLC and its affiliates.
10(h)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(q)	—	Form of Sale Participation Agreement (Management Form).
10(i)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(r)	—	Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan.
10(j)	333-100240 2008 Form 10-K (filed March 3, 2009)	10(s)	—	Form of Stock Appreciation Rights Award Letter pursuant to the Stock Appreciation Rights Plan.
10(k)	333-100240 2009 Form 10-K (filed February 19, 2010)	10(p)	—	Oncor Salary Deferral Program.

153

Exhibits	Previously Filed* With File Number	As Exhibit
10(l)	333-100240 2009 Form 10-K (filed February 19, 2010)	10(q)	—	Oncor Supplemental Retirement Plan.
10(m)	001-12833 2005 Form 10-K (filed March 6, 2006)	10(gg)	—	EFH Split Dollar Life insurance Program, as amended and restated, executed March 2, 2006, effective as of May 20, 2005.
10(n)	001-12833 2007 Form 10-K (filed March 31, 2008)	10(n)	—	Amendment to the EFH Split Dollar Life Insurance Program, effective as of October 10, 2007.
10(o)	333-100240 2010 Form 10-K (filed February 18, 2011)	10(w)	—	Oncor Electric Delivery Company LLC Executive Change in Control Policy.
10(p)	333-100240 2010 Form 10-K (filed February 18, 2011)	10(x)	—	Oncor Electric Delivery Company LLC Executive Severance Plan and Summary Plan Description.
10(q)	333-100240 2010 Form 10-K (filed February 18, 2011)	10(y)	—	Oncor Electric Delivery Company LLC Second Amended and Restated Executive Annual Incentive Plan.
10(r)	333-100240 Form 10-Q (filed July 29, 2011)	10(a)	—	Oncor Electric Delivery Company LLC Third Amended and Restated Executive Annual Incentive Plan.
10(s)			—	Retention Agreement, effective as of February 12, 2013, between Oncor Electric Delivery Company LLC and E. Allen Nye, Jr.
10(t)			—	Oncor Electric Delivery Company LLC Long-Term Incentive Plan.
10(u)			—	Form of Oncor Electric Delivery Company LLC Long-Term Incentive Plan Award Agreement.
	Credit Agreements
10(v)	333-100240 Form 8-K (filed October 11, 2011)	10.1	—	Amended and Restated Revolving Credit Agreement, dated as of October 11, 2011, among Oncor Electric Delivery Company LLC, as borrower, the lenders listed therein, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., as swingline lender, and JPMorgan Chase Bank, N.A., Barclays Bank PLC, The Royal Bank of Scotland plc, Bank of America, N.A. and Citibank, N.A., as fronting banks for letters of credit issued thereunder.
10(w)	333-100240 Form 8-K (filed May 15, 2012)	10.1	—	Joinder Agreement, dated as of May 15, 2012, by and among Oncor, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent under the Credit Agreement, swingline lender and fronting bank, Barclays Bank PLC, Bank of America, N.A., Citibank, N.A. and The Royal Bank of Scotland PLC, as fronting banks, and each party identified as an “Incremental Lender” on the signature pages thereto.

154

Exhibits	Previously Filed* With File Number	As Exhibit
	Other Material Contracts
10(x)	333-100240 2004 Form 10-K (filed March 23, 2005)	10(i)	—	Agreement, dated as of March 10, 2005, by and between Oncor Electric Delivery Company LLC and certain TXU Energy Company LLC affiliates allocating to Oncor Electric Delivery Company LLC the pension and post-retirement benefit costs for all Oncor Electric Delivery Company LLC employees who had retired or had terminated employment as vested employees prior to January 1, 2002.
10(y)	333-100240 Form 10-Q (filed November 6, 2008)	10(b)	—	Amended and Restated Tax Sharing Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Oncor Management Investment LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
10(z)	001-12833 2007 Form 10-K (filed March 31, 2008)	10(eee)	—	Stipulation as approved by the PUCT in Docket No. 34077.
10(aa)	001-12833 2007 Form 10-K (filed March 31, 2008)	10(fff)	—	Amendment to Stipulation Regarding Section 1, Paragraph 35 and Exhibit B in Docket No. 34077.
10(ab)	333-100240 2010 Form 10-K (filed February 18, 2011)	10(ae)	—	PUCT Order on Rehearing in Docket No. 34077.
(12)	Statement Regarding Computation of Ratios.
12(a)			—	Computation of Ratio of Earnings to Fixed Charges, and Ratio of Earnings to Combined Fixed Charges and Preference Dividends.
(21)	Subsidiaries of the Registrant.
21(a)			—	Subsidiaries of Oncor Electric Delivery Company LLC.
(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.

155

Exhibits	Previously Filed* With File Number	As Exhibit
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(a)	333-91935 Form S-3 (filed July 1, 2003)	99(a)	—	Financing Order.
99(b)	333-91935 Form S-3 (filed July 1, 2003)	99(b)	—	Internal Revenue Service Private Letter Ruling pertaining to the transition bonds, dated May 21, 2002.
99(c)	333-91935 Form S-3 (filed July 1, 2003)	99(c)	—	Internal Revenue Service Private Letter Ruling pertaining to the transition bonds, dated February 18, 2000.
	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.

** Furnished herewith.

156

Supplemental Information to be Furnished with Reports Filed

Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered

Securities Pursuant to Section 12 of the Act

No annual report, proxy statement, form of proxy or other proxy soliciting material has been sent to security holders of Oncor Electric Delivery Company LLC during the period covered by this Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

157