ONCOR ELECTRIC DELIVERY CO LLC filed this 10-K on 02/28/2014
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________

 

FORM 10-K

 

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

 

For the Fiscal Year Ended December 31, 2013

 

— OR

 

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

 

Commission File Number 333-100240

 

Oncor Electric Delivery Company LLC

(Exact name of registrant as specified in its charter)

 

 

 

Delaware

75-2967830

(State of Organization)

(I.R.S. Employer Identification No.)

 

 

1616 Woodall Rodgers Fwy., Dallas, TX  75202

(214) 486-2000

(Address of principal executive offices)(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  √  

 

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   √     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      

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes   √     No___

 

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.  √  

 

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   √  (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  √  

 

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

 

As of February 27, 2014, 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 

3

PART I 

Items 1 and 2.

BUSINESS AND PROPERTIES

6

Item 1A.

RISK FACTORS

11

Item 1B.

UNRESOLVED STAFF COMMENTS

17

Item 3.

LEGAL PROCEEDINGS

17

Item 4.

MINE SAFETY DISCLOSURES

17

PART II 

Item 5.

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

18

Item 6.

SELECTED FINANCIAL DATA

18

Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

19

 

RESULTS OF OPERATIONS

 

Item 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

36

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

38

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

75

Item 9A.

CONTROLS AND PROCEDURES

75

Item 9B.

OTHER INFORMATION

77

PART III 

Item 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

78

Item 11.

EXECUTIVE COMPENSATION

87

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED EQUITY HOLDER MATTERS

126

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

131

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

 

This annual report on 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.

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GLOSSARY

 

 

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

AMS

advanced metering system

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

EECRF

energy efficiency cost recovery factor

EFH Corp.

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

EFH Retirement Plan

Refers to a defined benefit pension plan sponsored by EFH Corp., in which Oncor participatesIn 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

 

 

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Limited Liability Company Agreement

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

Luminant

Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.

Moody’s

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

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

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.

4


 

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

TCOS

transmission cost of service

TCRF

transmission cost recovery factor

Texas Holdings

Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.

Texas Holdings Group

Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.

Texas margin tax

A privilege tax imposed on taxable entities chartered/organized or doing business in the State of Texas that, for accounting purposes, is reported as an income tax.  Also referred to as “Texas franchise tax” and/or “Texas gross margin tax.”

Texas Transmission

Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor.  Texas Transmission is an entity indirectly owned by a private investment group led by OMERS Administration Corporation, acting through its infrastructure investment entity, Borealis Infrastructure Management Inc., and the Government of Singapore Investment Corporation, acting through its private equity and infrastructure arm, GIC Special Investments Pte Ltd.  Texas Transmission is not affiliated with EFH Corp., any of EFH Corp.’s subsidiaries or any member of the Sponsor Group.

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

 

 

 

 

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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 electrical systems, as well as providing transmission grid connections to merchant generation facilities 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 the remaining 0.22% of our 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.

 

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 120,000 miles of transmission and distribution lines.  We provide:

 

·

transmission services to electricity distribution companies, cooperatives, municipalities, and

 

·

distribution services to REPs, including subsidiaries of TCEH, which sell electricity to retail customers.

 

Our transmission and distribution rates are regulated by the PUCT, and in certain instances, by the FERC.  We are not a seller of electricity, nor do we purchase electricity for resale.  The company is managed as an integrated business; consequently, there are no reportable segments.

 

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.  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, 2013, we had approximately 3,420 full-time employees, including approximately 690 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.

 

As noted in SEC filings made by members of the Texas Holdings Group, EFH Corp. and other members of the Texas Holdings Group have engaged in discussions with certain unaffiliated creditors regarding certain of those entities’ capital structures and long-term liquidity, as well as possible restructuring transactions involving those entities.  We believe the “ring-fencing” measures discussed above mitigate our exposure to a bankruptcy or other restructuring transaction involving members of the Texas Holdings Group.

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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 more than 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 2013, ERCOT’s hourly demand peaked at 67,245 MW as compared to the peak demand of 66,548 MW in 2012.  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 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 2013.  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 2013, we invested approximately $1.1 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 projectsThe projects involve the construction of transmission lines and stations to support the transmission of electricity from

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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.  At December 31, 2013, our cumulative CREZ-related capital expenditures totaled $1.871 billion, including $411 million in 2013.  All CREZ-related line and station construction projects were energized by the end of 2013.  Additional voltage support projects were completed in January 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 advanced digital communication, data management, real-time monitoring and outage detection capabilities to take advantage of our recent deployment of advanced digital metering equipment.  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 from the new meters makes it possible for REPs to support new programs and pricing options.

 

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 system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.

 

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, 2013, our transmission facilities included 6,522 circuit miles of 345kV transmission lines and 9,658 circuit miles of 138kV and 69kV transmission lines.  Sixty-seven generation facilities totaling 36,410 MW were directly connected to our transmission system at December 31, 2013, and 292 transmission stations and 709 distribution substations were served from our transmission system.

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At December 31, 2013, our transmission facilities had the following connections to other transmission grids in Texas:

 

 

 

 

 

 

 

 

 

 

Number of Interconnected Lines

Grid Connections

 

345kV

 

138kV

 

69kV

Brazos Electric Power Cooperative, Inc.

 

 

112 

 

23 

Rayburn Country Electric Cooperative, Inc. 

 

 -

 

39 

 

Lower Colorado River Authority

 

10 

 

23 

 

Texas New Mexico Power

 

 

 

12 

Tex-La Electric Cooperative of Texas, Inc.

 

 -

 

12 

 

American Electric Power Company, Inc. (a)

 

 

 

11 

Texas Municipal Power Agency

 

 

 

 -

Lone Star Transmission

 

12 

 

 -

 

 -

Centerpoint Energy Inc.

 

 

 -

 

 -

Electric Transmission Texas, LLC

 

 

 

 -

Sharyland Utilities, L.P.

 

 -

 

 

 -

Other small systems operating wholly within Texas

 

 

 

_____________

(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 3,177 distribution feeders.

 

Our distribution system included over 3.2 million points of delivery at December 31, 2013.  Over the past five years, the number of distribution system points of delivery we serve, excluding lighting sites, grew an average of 1.13% per year, adding approximately 43,700 points of delivery in 2013.

 

Our distribution system consists of 56,683 miles of overhead primary conductors, 21,621 miles of overhead secondary and street light conductors, 16,169 miles of underground primary conductors and 9,966 miles of underground secondary and street light conductors.  The majority of the distribution system operates at 25kV and 12.5kV.

 

Distribution revenues from residential and small business users are based on actual monthly consumption (kWh), and, depending on size and annual load factor, revenues from large commercial and industrial users are based either on actual monthly demand (kilowatts) or the greater of actual monthly demand (kilowatts) or 80% of peak monthly demand during the prior eleven months.

 

The PUCT has approved a periodic rate adjustment, 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.

 

CustomersOur 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 27% of our total operating revenues in 2013.  Revenues from REP subsidiaries of a nonaffiliated entity, NRG Energy, Inc., collectively represented 15% of our total operating revenues in 2013.  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.

 

Regulation and RatesAs 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.”

 

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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 (i.e., the PUCT or the municipality with original jurisdiction).

 

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 all utilities that are subject to the PUCT’s jurisdiction over transmission services, including us.

 

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, 2013, $311 million principal amount of transition bonds (maturing between 2014 and 2016) was outstanding.

 

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 $14 million in 2013 and are expected to total approximately $13 million in 2014.

10


 

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 last regular session ended in May 2013.  The next regular session is scheduled to commence in January 2015.  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 or physical 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.  Recently there have been numerous attacks on government and industry information technology systems that have resulted in material operational, reputation and/or financial costs.  While we

11


 

have controls in place designed to protect our information technology 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 and regulatory claims, impair our ability to execute on business strategies and/or materially affect our results of operations, liquidity and financial condition.

A physical attack on our transmission and distribution infrastructure could also interfere with normal business operations and affect our ability to control our transmission and distribution assets. While we have security measures in place designed to protect our transmission and distribution system and have not had any significant security breaches, a physical security breach could adversely affect our reputation, expose us to material regulatory claims 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, security measures and services to detect, mitigate and protect our assets, both physical and cyber.  These investments include upgrades to network architecture and physical security measures, 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.”

 

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.  Considering our construction plans to service our growing customer base and ERCOT needs, 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 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 EFH Corp., our majority

12


 

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 taken, and could in the future take, an adverse action with respect to our credit ratings in response to financing and liability management activities by, or restructuring transactions involving EFH Corp. and other members of the Texas Holdings Group.  Further, it is unclear how any bankruptcy filing including EFH Corp. and other members of the Texas Holdings Group and related proceedings may effect our credit ratings.  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 large suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions with us. If our credit ratings decline, the costs to operate our business could increase because counterparties could require the posting of collateral in the form of cash-related instruments, or counterparties could decline to do business with us.

 

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.  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 27% of our total operating revenues for the year ended December 31, 2013.  Revenues from REP subsidiaries of a non-affiliated entity, NRG Energy, Inc., collectively represented 15% of our total operating revenues for the year ended December 31, 2013.  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 are not allowed to 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:

 

13


 

·

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 or bankruptcy 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, 2013, we were in compliance with such covenant.  See Note 5 to Financial Statements for further information regarding this 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, 2013, the available bond credits were approximately $2.176 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 $1.173 billion.  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, 2013, our regulatory capitalization ratio was 58.7% debt and 41.3% 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 $31 million at December 31, 2013.  Funding for the EFH Retirement Plan is expected to total approximately $103 million in 2014 and $119 million in the 2014 to 2018 period.  We are expected to fund approximately $83 million in 2014 and $83 million in the 2014 to 2018 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

14


 

recovery of those costs and, as a result, in 2005 we entered into an agreement with EFH Corp.’s predecessor to assume those costs.

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 connection with a bankruptcy case involving one or more members of the Texas Holdings Group.  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.

 

Our rights under certain agreements with EFH Corp. and other members of the Texas Holdings Group could be adversely affected in connection with a bankruptcy proceeding involving those entities.

We are party to various contracts and unexpired leases with EFH Corp. and other members of the Texas Holdings Group, as described in Note 11 to Financial Statements.  The US Bankruptcy Code permits a debtor in bankruptcy to assume (accept) or reject executory contracts and unexpired leases.  If members of the Texas Holdings Group were to become debtors in a bankruptcy case and determined to reject some or all of their executory contracts and unexpired leases with us in connection with that bankruptcy case, our results of operations and financial condition could be adversely affected.

 

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.

15


 

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 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 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.

16


 

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.

 

Item 1B.  UNRESOLVED STAFF COMMENTS

 

None.

 

Item 3.      LEGAL PROCEEDINGS

 

We are involved in various legal and administrative proceedings in the normal course of business the ultimate resolution of which, in the opinion of management, should not have a material effect 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.

17


 

PART II

 

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

 

At December 31, 2013, 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 2013.

 

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,

 

2013

 

2012

 

2011

 

2010

 

2009

 

(millions of dollars, except ratios)

Total assets

$

18,234 

 

$

17,990 

 

$

17,371 

 

$

16,846 

 

$

16,232 

Property, plant & equipment ─ net

 

11,902 

 

 

11,318 

 

 

10,569 

 

 

9,676 

 

 

9,174 

Goodwill

 

4,064 

 

 

4,064 

 

 

4,064 

 

 

4,064 

 

 

4,064 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capitalization

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt, less amounts due currently

$

5,381 

 

$

5,400 

 

$

5,144 

 

$

5,333 

 

$

4,996 

Membership interests

 

7,409 

 

 

7,304 

 

 

7,181 

 

 

6,988 

 

 

6,847 

Total

$

12,790 

 

$

12,704 

 

$

12,325 

 

$

12,321 

 

$

11,843 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capitalization ratios (a)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt, less amounts due currently

 

42.0% 

 

 

42.5% 

 

 

41.7% 

 

 

43.3% 

 

 

42.2% 

Membership interests

 

58.0% 

 

 

57.5% 

 

 

58.3% 

 

 

56.7% 

 

 

57.8% 

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, 2013 was 58.7% debt and 41.3% 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,

 

2013

 

2012

 

2011

 

2010

 

2009

 

(millions of dollars, except ratios)

Operating revenues

$

3,552 

 

$

3,328 

 

$

3,118 

 

$

2,914 

 

$

2,690 

Net income

$

432 

 

$

349 

 

$

367 

 

$

352 

 

$

320 

Capital expenditures

$

1,079 

 

$

1,389 

 

$

1,362 

 

$

1,020 

 

$

998 

Ratio of earnings to fixed charges

 

2.76 

 

 

2.49 

 

 

2.62 

 

 

2.60 

 

 

2.40 

Embedded interest cost on long-term debt ─ end of period (a)

 

6.4% 

 

 

7.0% 

 

 

6.6% 

 

 

6.5% 

 

 

6.6% 

_______________

(a)

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.

 

 

 

 

 

18


 

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, 2013, 2012 and 2011 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 27%, 29% and 33% of our total operating revenues for the years ended December 31, 2013, 2012 and 2011, respectively.  We are a majority-owned subsidiary of Oncor Holdings, which is a direct, wholly-owned subsidiary of EFIH, a direct, wholly-owned subsidiary of EFH Corp.  Oncor Holdings owns 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 0.22% of the outstanding membership interests through Investment LLC.  We are managed as an integrated business; consequently, there are no separate reportable business segments.

 

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

 

As noted in SEC filings made by members of the Texas Holdings Group, EFH Corp. and other members of the Texas Holdings Group have engaged in discussions with certain unaffiliated creditors regarding certain of those entities’ capital structures and long-term liquidity, as well as possible restructuring transactions involving those entities.  We believe the “ring-fencing” measures discussed above mitigate our exposure to a bankruptcy or other restructuring transaction involving members of the Texas Holdings Group.

 

Significant Activities and Events

 

Debt-Related Activities — See Note 6 to Financial Statements for information regarding the issuance of $100 million principal amount of senior secured notes in May 2013.

 

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.  For additional information concerning risk factors related to our business, see “Item1A. Risk Factors” in this report.

19


 

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.  Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital.  However, 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.

 

EFH Corp. Potential Restructuring Activities

 

As noted in SEC filings made by members of the Texas Holdings Group, EFH Corp. and other members of the Texas Holdings Group have engaged in discussions with certain unaffiliated creditors regarding certain of those entities’ capital structures and long-term liquidity, as well as possible restructuring transactions involving those entities.  See “Item 1A. Risk Factors” and Notes 7 and 11 to Financial Statements for a discussion of risks relating to, and potential impacts of, these restructuring activities.

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 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.

 

Cyber Security and Infrastructure Protection Risk

 

A breach of cyber/data or physical security measures that impairs our information technology infrastructure or transmission and distribution infrastructure could disrupt normal business operations, affect our ability to control our transmission and distribution system, expose us to material regulatory claims and limit communication with third parties.  Any loss of confidential or proprietary data through a cyber/data breach could also materially affect our reputation, expose the company to legal claims or impair our ability to execute on business strategies.  We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques.  While we have not experienced any security breach with a significant operational, reputational or financial impact, we recognize the growing threat within our industry and are proactively taking steps to continuously improve our technology, security measures, processes and services to detect, mitigate and protect our assets, both physical and cyber.

 

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.

20


 

Contingencies

As noted in Note 1 to Financial Statements, EFH Corp. and other members of the Texas Holdings Group have indicated that they have been involved in discussions regarding possible restructuring transactions.  Due to the uncertainty of the outcome of these restructuring activities, we have applied our contingency policy to the accounts receivable from affiliates arising from the various related party transactions described in Note 11 to Financial Statements.  We have determined that no loss contingency is probable as of December 31, 2013.  We do not have enough information about the plans of the Texas Holdings Group to determine that the likelihood of a loss contingency is remote.  At February 27, 2014, we had collected all but $6 million of the accounts receivable from affiliates outstanding at December 31, 2013.  In addition, with respect to the various contracts and unexpired leases with EFH Corp. and certain of its subsidiaries, the US Bankruptcy Code permits a debtor in bankruptcy to assume (accept) or reject executory contracts and unexpired leases.  We have determined that as of December 31, 2013 a loss contingency of approximately $20 million related to these agreements is reasonably possible if members of the Texas Holdings Group were to become debtors in a bankruptcy case and determined to reject their executory contracts and unexpired leases with us.

 

Revenue Recognition

 

Revenue includes an estimate for electricity delivery services provided from the billed meter reading date to the end of the period (unbilled revenue).  For electricity delivery services billed on the basis of kWh volumes, unbilled revenue is based on data collected through our AMS.    For other electricity delivery services, unbilled revenue is based on average daily revenues for the most recent period applied to the number of unmetered days through the end of the period. Accrued unbilled revenues totaled $180 million, $147 million and $127 million at December 31, 2013, 2012 and 2011, 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).

 

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.

21


 

Regulatory Assets

 

Our financial statements at December 31, 2013 and 2012 reflect total regulatory assets of $1.771 billion and $2.093 billion, respectively.  These amounts include $281 million and $409 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 $422 million and $315 million at December 31, 2013 and 2012, 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.

 

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.

 

Testing performed in December 2013 and 2012 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, 2013, 2012 or 2011.

 

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.

22


 

 

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:

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

2013

 

2012

 

2011

 

 

 

 

 

 

 

 

 

Pension costs

$

95 

 

$

179 

 

$

95 

OPEB costs

 

37 

 

 

27 

 

 

74 

Total benefit costs

 

132 

 

 

206 

 

 

169 

Less amounts deferred principally as property or a regulatory asset

 

(95)

 

 

(169)

 

 

(132)

Net amounts recognized as expense

$

37 

 

$

37 

 

$

37 

Discount rate (percentage) (a)(b)

 

4.10% 

 

 

5.00% 

 

 

5.50% 

Funding of the pension plans and the OPEB Plan (c)

$

20 

 

$

104 

 

$

193 

_____________

(a)

As a result of the amendments to the EFH Retirement Plan in 2012, 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 4.10%, 4.95% and 5.55% in 2013, 2012 and 2011, 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 2014 Pension and OPEB Costs

Discount rate – 1% increase

 

$

(32)

Discount rate – 1% decrease

 

$

34 

Expected return on assets – 1% increase

 

$

(23)

Expected return on assets – 1% decrease

 

$

23 

 

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

23


 

RESULTS OF OPERATIONS

 

Operating Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 

2013

 

 

2012

 

 

2011

Operating statistics:

 

 

 

 

 

 

 

 

 

Electric energy billed volumes (gigawatt-hours):

 

 

 

 

 

 

 

 

 

Residential

 

 

41,486 

 

 

40,377 

 

 

43,888 

Other (a)

 

 

70,826 

 

 

69,994 

 

 

69,949 

Total electric energy billed volumes

 

 

112,312 

 

 

110,371 

 

 

113,837 

 

 

 

 

 

 

 

 

 

 

Reliability statistics (b):

 

 

 

 

 

 

 

 

 

System Average Interruption Duration Index (SAIDI) (nonstorm)

 

 

106.1 

 

 

89.9 

 

 

106.2 

System Average Interruption Frequency Index (SAIFI) (nonstorm)

 

 

1.4 

 

 

1.2 

 

 

1.3 

Customer Average Interruption Duration Index (CAIDI) (nonstorm)

 

 

75.6 

 

 

77.6 

 

 

83.1 

 

 

 

 

 

 

 

 

 

 

Electricity points of delivery (end of period and in thousands):

 

 

 

 

 

 

 

 

 

Electricity distribution points of delivery (based on number of active meters)

 

 

3,284 

 

 

3,242 

 

 

3,203 

 

 

 

 

 

 

 

 

 

 

Operating revenues:

 

 

 

 

 

 

 

 

 

Distribution base revenues

 

$

1,826 

 

$

1,789 

 

$

1,993 

Transmission base revenues (TCOS) (c)

 

 

703 

 

 

629 

 

 

555 

Reconcilable rates:

 

 

 

 

 

 

 

 

 

TCRF (c)

 

 

846 

 

 

733 

 

 

401 

Transition charges

 

 

149 

 

 

144 

 

 

150 

AMS surcharges

 

 

148 

 

 

142 

 

 

103 

EECRF and rate case expense surcharges

 

 

66 

 

 

49 

 

 

43 

Other miscellaneous revenues

 

 

73 

 

 

73 

 

 

77 

Intercompany eliminations (c)

 

 

(259)

 

 

(231)

 

 

(204)

Total operating revenues

 

$

3,552 

 

$

3,328 

 

$

3,118 

 

________________

(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)A portion of transmission base revenues (TCOS) is recovered from Oncor’s distribution customers through the TCRF rate.

24


 

Financial Results ─ Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

 

Total operating revenues increased $224 million, or 7%, to $3.552 billion in 2013.  All revenue is billed under tariffs approved by the PUCT.  The increase reflected:

 

·

Distribution base revenues — Base rates are set periodically in a rate review docket initiated by either us or the PUCT.  The present distribution base rates became effective on January 1, 2012.  The $37 million increase in distribution base rate revenues consisted of a $21 million impact of higher average consumption, largely driven by the effects of colder fall/winter weather in 2013 as compared to 2012 and an estimated $16 million effect of growth in points of delivery.

 

·

Transmission base revenues — TCOS revenues are collected from load serving entities benefitting from our transmission system.  REPs serving customers in our service territory are billed though the TCRF mechanism discussed below while other load serving entities are billed directly.  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 $74 million increase in transmission base revenues primarily reflects interim rate increases to recover ongoing investment, including a return component, in the transmission system.  See TCOS Filings Table below for a listing of Transmission Interim Rate Update Applications impacting revenues for the years ended December 31, 2013 and 2012 as well as filings that will impact revenues for the year ended December 31, 2014.

 

TCOS Filings Table

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Docket No.

 

Filed

 

Effective

 

Annual Revenue Impact

 

Third-Party Wholesale Transmission

 

Included in TCRF

42267

 

February 2014*

 

April 2014

 

$

74 

 

$

47 

 

$

27 

41706

 

July 2013

 

September 2013

 

$

71 

 

$

45 

 

$

26 

41166

 

January 2013

 

March 2013

 

$

27 

 

$

17 

 

$

10 

40603

 

July 2012

 

August 2012

 

$

30 

 

$

19 

 

$

11 

40142

 

January 2012

 

March 2012

 

$

 

$

 

$

39644

 

August 2011

 

October 2011

 

$

35 

 

$

22 

 

$

13 

__________

*    Application pending.

 

·

Reconcilable Rates — The PUCT has designated certain tariffs (TCRF, EECRF surcharge, AMS surcharge and charges related to transition bonds) as reconcilable, which means the differences between amounts billed under these tariffs and the related incurred costs, including a return component where allowed, are deferred as either regulatory assets or regulatory liabilities.  Accordingly, at prescribed intervals, future applicable tariffs are adjusted to either repay regulatory liabilities or collect regulatory assets.  Changes in these tariffs do not impact operating income, except for the AMS return component, but do impact the timing of cash flows.  See Note 1 to Financial Statements for accounting treatment of reconcilable tariffs.

-

TCRF is a distribution rate charged to REPs to recover fees we pay 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 on March 1 and September 1 each year.  The $113 million increase in TCRF revenue reflects the pass through of an $86 million increase in third-party wholesale transmission expense described below and a $27 million increase in our own TCOS rate to recover ongoing investment in our transmission system including a return component.  At December 31, 2013, approximately $37 million was deferred as under-recovered wholesale transmission service expense (see Note 4 to Financial Statements).  See TCRF Filings Table below for a listing of TCRF filings impacting cash flow for the years ended December 31, 2013 and 2012 as well as filings that will impact cash flow for the year ended December 31, 2014.

25


 

TCRF Filings Table

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Semi-Annual

 

 

 

 

 

 

Billing Impact

Docket No.

 

Filed

 

Effective

 

Increase (Decrease)

42059

 

December 2013

 

March 2014 – August 2014

 

$

44 

41543

 

June 2013

 

September 2013 – February 2014

 

$

88 

41002

 

November 2012

 

   March 2013 – August 2013

 

$

(47)

40451

 

June 2012

 

September 2012 – February 2013

 

$

129 

39940

 

November 2011

 

   March 2012 – August 2012

 

$

(41)

39456

 

June 2011

 

September 2011 – February 2012

 

$

24 

 

-

Transition charges — Transition charge revenue is dedicated to paying the principal and interest of transition bonds.  We account for the difference between transition charge revenue recognized and cost related to the transition bonds as a regulatory liability.  Annual true-up adjustments are filed to increase or decrease the transition charges such that sufficient funds will be collected during the following period to meet scheduled debt service payments.  The final transition bonds mature in 2016.  The $5 million increase in charges related to transition bonds corresponds with an offsetting increase in amortization expense and primarily reflects higher electricity volumes delivered by us due to the effects of colder fall/winter weather in 2013 as compared to 2012.

-

AMS surcharges — The PUCT has authorized monthly per customer advanced meter cost recovery factors designed to recover the cost of our initial AMS deployment over an eleven-year period ending in 2019.  We recognize revenues equal to reconcilable expenses incurred including depreciation net of calculated savings plus a return component on our investment.  The $6 million increase in recognized AMS revenues is due to increased costs driven by meter installation and systems development.  See “Regulation and Rates” below.

-

EECRF surcharges — 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 recover or refund any over/under recovery of our costs in prior years.  We recognize the performance bonuses in other miscellaneous revenues upon approval by the PUCT.  PUCT rules require us to file an annual EECRF tariff update by the first business day in June of each year for implementation on March 1 of the next calendar year.  For the year ended 2013, we recognized a $17 million increase in EECRF surcharges, which is offset in operation and maintenance expense.  See EECRF Filings Table below for a listing of EECRF filings impacting revenues for the years ended December 31, 2013 and 2012 as well as filings that will impact revenues for the year ended 2014.

 

EECRF Filings Table

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Docket No.

 

Filed

 

Effective

 

Monthly Charge per Residential Customer

 

Program Costs

 

Performance Bonus

 

Under-/  (Over)- Recovery

41544

 

May 2013

 

March 2014

 

$

1.01 

*

$

62 

 

$

12 

 

$

(1)

40361

 

May 2012

 

January 2013

 

$

1.23 

 

$

62 

 

$

 

$

39375

 

May 2011

 

January 2012

 

$

0.99 

 

$

49 

 

$

 

$

(3)

__________

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

 

·

Other miscellaneous revenues — Miscellaneous revenues includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs, services provided on a time and materials basis, rents, energy efficiency performance bonuses approved by the PUCT and other miscellaneous revenues.

 

26


 

Wholesale transmission service expense increased $86 million, or 17%, to $588 million in 2013.  Third-party wholesale transmission service expense increased $95 million in 2013 due to higher fees paid to other transmission entities and a 2% increase in volumes, partially offset by a $9 million charge associated with a wholesale transmission cost settlement in 2012.

 

Operation and maintenance expense increased $12 million, or 2%, to $681 million in 2013.  The change included $16 million in higher labor and employee benefits costs and $8 million in higher other costs, offset by $12 million in lower vegetation management expenses, $6 million in lower outside services costs, $5 million in lower professional services costs and $2 million in lower amortization of regulatory assets.  Operation and maintenance expense also reflects fluctuations in expenses that are offset by corresponding revenues, including a $17 million increase in costs related to programs designed to improve customer electricity efficiency and a $4 million decrease related to advanced meters.  Amortization of regulatory assets reported in operation and maintenance expense totaled $52 million and $54 million in 2013 and 2012, respectively.

 

Depreciation and amortization increased $43 million, or 6%, to $814 million in 2013.  The increase reflected $38 million attributed to ongoing investments in property, plant and equipment (including $12 million attributed to investments related to the deployment of advanced meters) and $5 million in higher amortization of regulatory assets associated with transition bonds (with an offsetting increase in revenues).

 

Other income totaled $18 million in 2013 and $26 million in 2012.  The 2013 and 2012 amounts included accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting totaling $18 million and $23 million, respectively.  See Note 12 to Financial Statements.

 

Other deductions totaled $15 million and $64 million in 2013 and 2012, respectively.  The decrease was primarily attributable to the SARs settlement in 2012.  See Note 12 to Financial Statements.

 

Provision in lieu of income taxes totaled $249 million in 2013 (including $247 million related to operating income and $2 million related to nonoperating income) compared to a net $234 million (including $240 million related to operating income and a benefit of $6 million related to nonoperating income) in 2012.  The effective income tax rate on pretax income was 36.6% in 2013 and 40.1% in 2012.  The 2013 effective income tax rate on pretax income differs from the US federal statutory rate of 35% primarily due to the effect of $14 million of non-deductible amortization of the regulatory asset attributed to a change in deductibility of the Medicare Part D subsidy as a result of the Patient Protection and Affordable Care Act of 2010 and the effect of the 2013 Texas margin tax,  partially offset by the reversal of accrued interest and taxes totaling $16 million attributed to the resolution of certain uncertain tax positions.  See Note 3 to Financial Statements.

 

Interest income decreased $20 million, or 83%, to $4 million in 2013.  The change reflected a $16 million decrease as a result of our sale of the TCEH transition bond interest reimbursement agreement to EFIH in August 2012 (see Note 11 to Financial Statements for discussion of the sale) and a $6 million decrease attributable to a prior year sales tax refund, partially offset by a $2 million increase in assets related to an employee benefit plan. 

 

Interest expense and related charges decreased $3 million, or 1%, to $371 million in 2013.  The change was driven by a $9 million decrease attributable to lower average interest rates, partially offset by a $3 million increase attributable to higher average borrowings reflecting ongoing capital investments and $3 million in higher amortization of net debt-related costs.

 

Net income increased $83 million, or 24%, to $432 million in 2013.  The change reflected increased revenue from higher transmission rates, growth in points of delivery and lower other deductions, partially offset by higher depreciation, lower interest income, higher income taxes and higher operation and maintenance expenses.

 

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.  All revenue is billed under tariffs approved by the PUCT.  The increase reflected:

 

·

Distribution base revenues — A $204 million decrease in distribution base rate revenues consisted of a $223 million impact from reclassifying all TCRF revenues as reconcilable revenues resulting from a rate structure

27


 

change in 2011 (with a corresponding amount recognized in TCRF revenues below) and a $78 million impact of lower average consumption, primarily due to the effects of milder weather in 2012 as compared to 2011.  These decreases were partially offset by $77 million in higher distribution tariffs and an estimated $20 million effect of growth in points of delivery.

 

-

Transmission base revenues — The $74 million increase in transmission base revenues primarily reflects interim rate increases to recover ongoing investment, including a return component, in the transmission system.  See TCOS Filings Table above for a listing of TCOS filings impacting revenues for the years ended December 31, 2012 and 2011.

 

·

Reconcilable Rates:

 

-

TCRF —  The $332 million increase in TCRF consisted of a $223 million impact from reclassifying all TCRF revenues as reconcilable revenues resulting from a rate structure change in 2011 (with a corresponding amount recognized in distribution base revenues above) and a $109 million increase in TCRF revenues, which primarily reflects the pass through of a $63 million increase in third-party wholesale transmission expense described below.  At December 31, 2012, approximately $40 million was deferred as under-recovered wholesale transmission service expense (see Note 4 to Financial Statements).  See TCRF Filings Table above for a listing of TCRF filings impacting cash flow for the years ended December 31, 2012 and 2011.

-

Transition charges — The $6 million decrease in charges related to transition bonds corresponds with an offsetting increase in amortization expense and primarily reflects lower electricity volumes delivered due to the effects of milder weather in 2012 as compared to 2011.

-

AMS surcharges — The $39 million increase in recognized AMS revenues is due to increased costs driven by meter installation and systems development completed in 2012.

-

EECRF surcharges— For the year ended 2012, we recognized a $6 million increase in EECRF surcharges, which is offset in operation and maintenance expense.  See EECRF Filings Table above for a listing of EECRF filings impacting revenues for the years ended December 31, 2012 and 2011.

 

·

Other miscellaneous revenues — The $4 million decrease in other miscellaneous revenues is primarily due to lower REP discretionary services as a result of the continuing deployment of advanced meters.

 

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 change 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.

 

28


 

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.

 

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 an $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.

 

OTHER COMPREHENSIVE INCOME

 

We reported $19 million and $3 million (both after tax) in other comprehensive income for the years ended December 31, 2013 and 2012, respectively.  These amounts represent 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).

 

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.  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.

 

FINANCIAL CONDITION

 

Liquidity and Capital Resources

 

Cash Flows —  Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 

 

Cash provided by operating activities totaled $1.370 billion and $1.269 billion in 2013 and 2012, respectively.  The $101 million change was driven by an $84 million decrease in pension and OPEB contributions, a $57 million effect of a SARs payout in 2012 (see Note 10 to Financial Statements), a $35 million increase in transmission and distribution receipts due to higher rates, a $30 million increase in accounts payable levels, a $17 million decrease in cash interest payments due to the early redemption of debt in June 2012 (see Note 6 to Financial Statements) and a $15 million decrease in energy efficiency program payments.  These increases in cash were partially offset by a $103 million increase in estimated federal and state income tax payments and a $29 million decrease in cash as a result of the sale of our tax reimbursement agreement to EFIH in August 2012 (see Note 11 to Financial Statements).

 

29


 

Cash used in financing activities totaled $324 million in 2013 and cash provided by financing activities totaled $132 million in 2012.  The 2013 activity reflected $310 million of cash used in distributions to our members (an $85 million increase compared to 2012 (see Note 8 to Financial Statements)) and $125 million in cash principal payments on transition bonds (a $7 million increase compared to 2012 (see Note 6 to Financial Statements)), partially offset by a $100 million increase from the issuance of long-term debt in May 2013 and a $10 million increase in short-term borrowings.

 

Cash used in investing activities, which consists primarily of capital expenditures, totaled $1.064 billion in 2013 and $1.368 billion in 2012.  The $304 million, or 22%, decrease was driven by lower capital expenditures for CREZ and advanced metering deployment initiatives, partially offset by higher capital expenditures for distribution facilities to serve new customers, information technology initiatives, and infrastructure maintenance.

 

Depreciation and amortization expense reported in the statements of consolidated cash flows was $34 million and $31 million more than the amounts reported in the statements of consolidated income for the years ended December 31, 2013 and 2012, respectively.  The differences result from amortization reported in the following different lines items in the statements of consolidated income: regulatory asset amortization (reported in operation and maintenance expense), the accretion of the adjustment (discount) to regulatory assets (reported in other income) and the amortization of debt fair value discount (reported in interest expense and related charges).

 

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 change 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 (see Note 6 to Financial Statements), 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.

 

Long-Term Debt Activity — Repayments of long-term debt in 2013 totaled $125 million and represent transition bond principal payments at scheduled maturity dates.

 

30


 

Issuances of long-term debt in 2013 totaled $100 million, consisting of the May 2013 sale of $100 million aggregate principal amount of 4.550% senior secured notes maturing in December 2041 (Additional 2041 Notes).  The Additional 2041 Notes were an additional issuance of our 4.550% senior secured notes maturing in December 2041, $300 million aggregate principal amount of which were previously issued in November 2011 (2041 Notes).  The Additional 2041 Notes were issued as part of the same series as the 2041 Notes.  We used the net proceeds of approximately $107 million from the sale of the Additional 2041 Notes to repay borrowings under our revolving credit facility and for general corporate purposes.  The Additional 2041 Notes and 2041 Notes are secured by the first priority lien (see Note 6 to Financial Statements), and are secured equally and ratably with all of our other secured indebtedness.

 

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, 2013 and 2012, we had a $2.4 billion secured revolving credit facility (see Note 5 to Financial Statements).  The revolving credit facility expires in October 2016Subject to the limitations described below, available borrowing capacity under our revolving credit facility totaled $1.649 billion and $1.659 billion at December 31, 2013 and 2012, respectively.  We may request an increase in our borrowing capacity of $100 million in the aggregate and up to two one-year extensions, provided certain conditions are met, including lender approval.

 

The revolving credit facility contains a senior debt-to-capitalization ratio covenant that effectively limits our ability to incur indebtedness in the future.  At December 31, 2013, we were in compliance with the covenant.  See “Financial Covenants, Credit Rating Provisions and Cross Default Provisions” below for additional information on this covenant and the calculation of this ratio.  The revolving credit facility and the senior notes and debentures issued by us are secured by the Deed of Trust, which permits us to secure other indebtedness with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the lower of the fair value or cost of certain property additions that have been certified to the Deed of Trust collateral agent.  Accordingly, the availability under our revolving credit facility is limited by the amount of available bond credits and any property additions certified to the Deed of Trust collateral agent in connection with the revolving credit facility borrowings.  In addition, our outstanding senior notes and debentures are secured by the Deed of Trust.  To the extent we continue to issue debt securities secured by the Deed of Trust, those debt securities would also be limited by the amount of available bond credits and any property additions that have been certified to the Deed of Trust collateral agent.  At December 31, 2013, the available bond credits totaled $2.176 billion, and the amount of additional potential indebtedness that could be secured by property additions, subject to the completion of a certification process, totaled $1.173 billion.  At December 31, 2013, the available borrowing capacity of the revolving credit facility could be fully drawn.

 

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

 

Cash and cash equivalents totaled $27 million and $45 million at December 31, 2013 and 2012, respectively.  Available liquidity (cash and available credit facility capacity) at December 31, 2013 totaled $1.676 billion reflecting a decrease of $28 million from December 31, 2012.  The change reflects our ongoing capital investment in transmission and distribution infrastructure.

 

We also committed to the PUCT that we would maintain a regulatory capital structure at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.  At December 31, 2013 and 2012, our regulatory capitalization ratios were 58.7% debt and 41.3% equity and 58.8% debt and 41.2% equity, respectively.  See Note 8 to Financial Statements for discussion of the regulatory capitalization ratio.

 

Liquidity Needs, Including Capital Expenditures — We expect our capital expenditures to total approximately $1.1 billion in 2014 and approximately $1.0 billion in 2015, including amounts related to CREZ voltage support projects, and approximately $1.1 billion in each of the years 2016 through 2018.  These capital expenditures are expected to be used for investment in transmission and distribution infrastructure.

 

31


 

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.  As noted in Note 1 to Financial Statements, EFH Corp. and other members of the Texas Holdings Group have indicated that they have been involved in discussions regarding possible restructuring transactions.  We do not expect that any such restructuring transactions would have a material impact on our liquidity.  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 19, 2014, our board of directors declared a cash distribution of $53 million, which was paid to our members on February 20, 2014.  See Note 8 to Financial Statements for discussion of distribution restrictions.

 

During 2013, our board of directors declared, and we paid, the following cash distributions to our members:

 

 

 

 

 

 

 

 

Declaration Date

 

Payment Date

 

Amount

October 29, 2013

 

October 31, 2013

 

$

95 

July 31, 2013

 

August 1, 2013

 

$

95 

May 1, 2013

 

May 2, 2013

 

$

70 

February 13, 2013

 

February 15, 2013

 

$

50 

 

Pension and OPEB Plan Funding — Our funding for the pension plans and the OPEB Plan for the calendar year 2014 is expected to total $87 million and $15 million, respectively.  Based on the funded status of the pension plans at December 31, 2013, our aggregate pension plans and OPEB Plan funding is expected to total approximately $547 million for 2014 to 2018.  In 2013, we made cash contributions to the pension plans and the OPEB Plan of $9 million and $11 million, respectively.  See Note 9 to Financial Statements for additional information regarding the pension plans and the OPEB Plan.

 

Capitalization — Our capitalization ratios were 42.0% and 42.5% long-term debt, less amounts due currently, to 58.0% and 57.5% membership interests at December 31, 2013 and 2012, 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, 2013, we were in compliance with this covenant with a debt-to-capitalization ratio of 0.45 to 1.00.

 

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

 

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

 

32


 

Presented below are the credit ratings assigned for our debt securities at February 27, 2014.  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 and  Moody’s changed our senior secured credit rating to Baa3 from Baa2, which was primarily driven by its view of the risks to which we are exposed by EFH Corp. (our majority equity investor) and TCEH, and increased debt at EFIH.  Oncor is on “stable” outlook with S&P, Fitch and Moody’s. 

 

 

 

 

 

 

 

Senior Secured

S&P

 

A

Fitch

 

BBB+

Moody’s

 

Baa3

 

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 1.50%.  A decline in credit ratings would increase the cost of our revolving credit facility and likely increase the cost of any debt issuances and additional credit facilities.

 

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

 

Under our revolving credit facility, a default by us or our subsidiary in respect of indebtedness in a principal amount in excess of $100 million or any judgments for the payment of money in excess of $50 million that are not discharged within 60 days may cause the maturity of outstanding balances ($745 million in short-term borrowings and $6 million in letters of credit at December 31, 2013) under that 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, 2013 (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

 

$

131 

 

$

680 

 

$

874 

 

$

3,851 

 

$

5,536 

Long-term debt – interest

 

 

339 

 

 

595 

 

 

540 

 

 

3,119 

 

 

4,593 

Operating leases (a)

 

 

 

 

 

 

 

 

 -

 

 

14 

Obligations under outsourcing agreements

 

 

88 

 

 

 

 

 -

 

 

 -

 

 

95 

Total contractual cash obligations

 

$

564 

 

$

1,289 

 

$

1,415 

 

$

6,970 

 

$

10,238 

____________

(a)   Includes short-term noncancelable leases.

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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 $54 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 $102 million in 2014 and approximately $547 million for the 2014 to 2018 period as discussed above under “Pension and OPEB Plan Funding,” and

·

capital expenditures under PUCT orders and other commitments made.

 

Guarantees — At December 31, 2013, we did not have any material guarantees.

 

OFF-BALANCE SHEET ARRANGEMENTS

 

At December 31, 2013, 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, 2013 that are expected to materially impact us.

 

REGULATION AND RATES

 

Sunset Review and Other State Legislation

 

Sunset review is the regular assessment by the Texas Legislature of the continuing need for a state agency to exist, and is grounded in the premise that an agency will be abolished unless legislation is passed to continue functions.  On a specified time schedule, 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.  The PUCT was subject to review by the Sunset Commission and a limited sunset review by the Texas Legislature in 2013.  During the 2013 regular legislative session, which ended in May 2013, the Texas Legislature extended the life of the PUCT until 2023.  No other legislation passed during the 2013 regular legislative session is expected to have a substantial impact on our financial position, results of operations or cash flows.

 

Matters with the PUCT

 

Application for Reconciliation of AMS Surcharge (PUCT Docket No. 41814)  In September 2013, we filed an application with the PUCT for reconciliation of all costs incurred and investments made from January 1, 2011 through December 31, 2012, in the deployment of our AMS pursuant to the AMS Deployment Plan approved in Docket No. 35718.  During the 2011 to 2012 period, we incurred approximately $300 million of capital expenditures and $34 million of operating and maintenance expense, and billed customers approximately $174 million through the AMS surcharge.  We were not seeking a change in the AMS surcharge in this proceeding. In November 2013, we filed an amended request and the PUCT Staff filed its recommendation concluding that all costs presented in the amended application, with the exception of less than $1,000 of expenses, are appropriate for recovery.  In December 2013, the PUCT issued its final order in the proceeding agreeing with the PUCT Staff’s recommendation, finding that costs expended and investments made in the deployment of our AMS through December 31, 2012 were properly allocated, reasonable and necessary.

34


 

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

 

Competitive Renewable Energy Zones (CREZs) (PUCT Docket Nos. 35665 and 37902) —  In 2009, the PUCT awarded us CREZ construction projects.   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.  At December 31, 2013, our cumulative CREZ-related capital expenditures totaled $1.871 billion, including $411 million during 2013.  All CREZ-related line and station construction projects were energized by the end of 2013.  Additional voltage support projects were completed in January 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.

 

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.

35


 

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, 2013 and 2012 carried fixed interest rates.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expected Maturity Date

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2015

 

2016

 

2017

 

2018

 

There-after

 

2013

Total Carrying Amount

 

2013 Total Fair Value

 

2012

Total Carrying Amount

 

2012 Total Fair Value

Long-term debt (including current maturities):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed rate debt amount (a)

 

$

131 

 

$

639 

 

$

41 

 

$

324 

 

$

550 

 

$

3,851 

 

$

5,536 

 

$

6,188 

 

$

5,561 

 

$

6,568 

Average interest rate

 

 

5.34% 

 

 

6.15% 

 

 

5.29% 

 

 

5.00% 

 

 

6.80% 

 

 

6.03% 

 

 

6.04% 

 

 

 

 

6.12% 

 

 

 

_________________

(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 net exposure to credit risk associated with trade accounts receivable from affiliates totaled $132 million at December 31, 2013, consisting of $83 million of billed receivables and $56 million of unbilled receivables, of which $7 million is secured by letters of credit posted by TCEH for our benefit. Under PUCT rules, unbilled amounts are billed within the following month and amounts are due in 35 days of billing.  Due to commitments made to the PUCT, this concentration of accounts receivable from affiliates increases the risk that a default could have a material effect on earnings and cash flows.  In the event of an affiliated REP default, we would not be able to recover in rates the amount in default.  At February 27, 2014, we had collected all but $6 million of the accounts receivable from affiliates outstanding at December 31, 2013.  Our net exposure with respect to accounts receivable from affiliates totaled $145 million at February 27, 2014.  See Note 11 to Financial Statements for additional information regarding our transactions with affiliates.

 

Our exposure to credit risk associated with accounts receivable from nonaffiliates totaled $388 million at December 31, 2013.  The nonaffiliated receivable amount is before the allowance for uncollectible accounts, which totaled $3 million at December 31, 2013.  The nonaffiliated exposure includes trade accounts receivable from REPs totaling $294 million, which are almost entirely noninvestment grade.  At December 31, 2013, 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 trade accounts receivable amount.  We view our exposure to this customer to be within an acceptable level of risk tolerance considering PUCT rules and regulations; however, this concentration increases the risk that a default could have a material effect on cash flows.

36


 

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;

·

adverse impacts on us as a result of restructuring transactions involving EFH Corp. and other members of the Texas Holdings Group;

·

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 

37


 

·

our ability to effectively execute our operational strategy.

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

 

Item 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, 2013 and 2012, 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, 2013.  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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

 

As discussed in Note 1 to the consolidated financial statements, the Company has implemented certain ring-fencing measures, which management believes mitigate the Company’s exposure to a bankruptcy or other restructuring transaction involving members of the Texas Holdings Group.

 

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, 2013, based on the criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2014 expressed an unqualified opinion on the Company’s internal control over financial reporting.

 

/s/ Deloitte & Touche LLP

 

Dallas, Texas

February 27, 2014

 

38


 

ONCOR ELECTRIC DELIVERY COMPANY LLC

STATEMENTS OF CONSOLIDATED INCOME

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

2013

 

2012

 

2011

 

(millions of dollars)

Operating revenues:

 

 

 

 

 

 

 

 

Nonaffiliates

$

2,585 

 

$

2,366 

 

$

2,092 

Affiliates

 

967 

 

 

962 

 

 

1,026 

Total operating revenues

 

3,552 

 

 

3,328 

 

 

3,118 

Operating expenses:

 

 

 

 

 

 

 

 

Wholesale transmission service

 

588 

 

 

502 

 

 

439 

Operation and maintenance

 

681 

 

 

669 

 

 

658 

Depreciation and amortization

 

814 

 

 

771 

 

 

719 

Provision in lieu of income taxes (Notes 3 and 11)

 

247 

 

 

240 

 

 

209 

Taxes other than amounts related to income taxes

 

424 

 

 

415 

 

 

400 

Total operating expenses

 

2,754 

 

 

2,597 

 

 

2,425 

Operating income

 

798 

 

 

731 

 

 

693 

Other income and deductions:

 

 

 

 

 

 

 

 

Other income (Note 12)

 

18 

 

 

26 

 

 

30 

Other deductions (Note 12)

 

15 

 

 

64 

 

 

Nonoperating provision in lieu of income taxes (Note 3)

 

 

 

(6)

 

 

20 

Interest income

 

 

 

24 

 

 

32 

Interest expense and related charges (Note 12)

 

371 

 

 

374 

 

 

359 

Net income

$

432 

 

$

349 

 

$

367 

 

 

See Notes to Financial Statements.

 

39


 

 

ONCOR ELECTRIC DELIVERY COMPANY LLC

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

2013

 

2012

 

2011

 

 

(millions of dollars)

Net income

 

$

432 

 

$

349 

 

$

367 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

Cash flow hedges (Notes 1 and 6):

 

 

 

 

 

 

 

 

 

Net decrease in fair value of derivatives (net of tax benefit of $—, $— and $17)

 

 

 -

 

 

 -

 

 

(29)

Derivative value net loss recognized in net income (net of tax benefit of $1, $1 and $—)

 

 

 

 

 

 

 -

Total cash flow hedges

 

 

 

 

 

 

(29)

Defined benefit pension plans (net of tax benefit of $11, $1 and $—) (Note 9)

 

 

(19)

 

 

(3)

 

 

 -

       Total other comprehensive income (loss)

 

 

(17)

 

 

 -

 

 

(29)

Comprehensive income

 

$

415 

 

$

349 

 

$

338 

 

 

See Notes to Financial Statements.

40


 

ONCOR ELECTRIC DELIVERY COMPANY LLC

STATEMENTS OF CONSOLIDATED CASH FLOWS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

2013

 

2012

 

2011

 

(millions of dollars)

Cash flows — operating activities:

 

 

 

 

 

 

 

 

Net income

$

432 

 

$

349 

 

$

367 

Adjustments to reconcile net income to cash provided by operating activities:

 

 

 

 

 

 

 

 

Depreciation and amortization

 

848 

 

 

802 

 

 

732 

Provision in lieu of deferred income taxes – net

 

194 

 

 

208 

 

 

258 

Other – net 

 

(4)

 

 

(4)

 

 

(3)

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

Accounts receivable — trade (including affiliates)

 

(129)

 

 

52 

 

 

(36)

Inventories

 

 

 

(3)

 

 

25 

Accounts payable — trade (including affiliates)

 

38 

 

 

(9)

 

 

17 

Deferred revenues (Note 4)

 

(53)

 

 

(101)

 

 

(7)

Other — assets

 

172 

 

 

(17)

 

 

111 

Other — liabilities

 

(137)

 

 

(8)

 

 

(169)

Cash provided by operating activities

 

1,370