UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015

— OR —

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

Commission File Number 1-12833

Energy Future Holdings Corp.

(Exact name of registrant as specified in its charter)

Texas	46-2488810
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1601 Bryan Street, Dallas, TX 75201-3411	(214) 812-4600
(Address of principal executive offices) (Zip Code)	(Registrant's telephone number, including area code)

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

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

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

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 x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes x    No o

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.    x

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 o  Accelerated filer o  Non-Accelerated filer x (Do not check if a smaller reporting company)

Smaller reporting company o

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

At February 29, 2016, there were 1,669,861,379 shares of common stock, without par value, outstanding of Energy Future Holdings Corp. (substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.’s parent holding company, and none of which is publicly traded).

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DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

		PAGE
Glossary		ii
	PART I
Items 1. and 2.	BUSINESS AND PROPERTIES	1
Item 1A.	RISK FACTORS	17
Item 1B.	UNRESOLVED STAFF COMMENTS	32
Item 3.	LEGAL PROCEEDINGS	32
Item 4.	MINE SAFETY DISCLOSURES	32
	PART II
Item 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	33
Item 6.	SELECTED FINANCIAL DATA	34
Item 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	36
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	68
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	74
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	150
Item 9A.	CONTROLS AND PROCEDURES	150
Item 9B.	OTHER INFORMATION	152
	PART III
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	153
Item 11.	EXECUTIVE COMPENSATION	159
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	181
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	184
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	187
	PART IV
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	189

Energy Future Holdings Corp.'s (EFH Corp.) 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 EFH Corp. website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on EFH Corp.'s 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 at 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 EFH Corp. and its subsidiaries occasionally make references to EFH Corp. (or "we," "our," "us" or "the Company"), EFCH, EFIH, TCEH, TXU Energy, Luminant, Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent company's financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.

i

GLOSSARY

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

ancillary services	Refers to services necessary to support the transmission of energy and maintain reliable operations for the entire transmission system. These services include monitoring and providing for various types of reserve generation to ensure adequate electricity supply and system reliability.
Chapter 11 Cases	Cases being heard in the US Bankruptcy Court for the District of Delaware (Bankruptcy Court) concerning voluntary petitions for relief under Chapter 11 of the US Bankruptcy Code (Bankruptcy Code) filed on April 29, 2014 by the Debtors
CAIR	Clean Air Interstate Rule
CFTC	US Commodity Futures Trading Commission
CO2	carbon dioxide
CPNPC	Refers to Comanche Peak Nuclear Power Company LLC, which was formed for the purpose of developing two new nuclear generation units and obtaining a combined operating license from the NRC for the units.
Competitive Electric segment	the EFH Corp. business segment that consists principally of TCEH
Consolidated EBITDA	Consolidated EBITDA means TCEH EBITDA adjusted to exclude noncash items, unusual items and other adjustments allowable under the agreement governing the TCEH DIP Facility. See the definition of EBITDA below. Consolidated EBITDA and EBITDA are not recognized terms under US GAAP and, thus, are non-GAAP financial measures. We are providing Consolidated EBITDA in this Form 10-K (see reconciliation in Exhibit 99(b)) solely because of the important role that Consolidated EBITDA plays in respect of covenants contained in the agreement governing the TCEH DIP Facility. We do not intend for Consolidated EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with US GAAP. Additionally, we do not intend for Consolidated EBITDA (or EBITDA) to be used as a measure of free cash flow available for management's discretionary use, as the measure excludes certain cash requirements such as adequate assurance payments, interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Consolidated EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
Confirmation Order	The Bankruptcy Court's December 2015 order confirming the Plan of Reorganization
CREZ	Competitive Renewable Energy Zone
CSAPR	the final Cross-State Air Pollution Rule issued by the EPA in July 2011
DIP Facilities	Refers, collectively, to TCEH's debtor-in-possession financing and EFIH's debtor-in-possession financing. See Note 12 to the Financial Statements.
Debtors	EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities
Disclosure Statement	Fifth Amended Disclosure Statement for the Debtors' Fifth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code approved by the Bankruptcy Court in September 2015
D.C. Circuit Court	US Court of Appeals for the District of Columbia Circuit
DOE	US Department of Energy
EBITDA	earnings (net income) before interest expense, income taxes, depreciation and amortization
EFCH	Energy Future Competitive Holdings Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context
EFH Acquisition	The acquisition of reorganized EFH Corp. financed by existing TCEH creditors and third-party investors as proposed in the Plan of Reorganization

ii

EFH Corp.	Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context, whose major subsidiaries include TCEH and Oncor
EFIH	Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings
EFIH Debtors	EFIH and EFIH Finance
EFIH Finance	EFIH Finance Inc., a direct, wholly owned subsidiary of EFIH, formed for the sole purpose of serving as co-issuer with EFIH of certain debt securities
EFIH First Lien Notes	EFIH's and EFIH Finance's $503 million principal amount of 6.875% Senior Secured First Lien Notes and $3.482 billion principal amount of 10.000% Senior Secured First Lien Notes, collectively
EFIH PIK Notes	EFIH's and EFIH Finance's $1.566 billion principal amount of 11.25%/12.25% Senior Toggle Notes
EFIH Second Lien Notes	EFIH's and EFIH Finance's $322 million principal amount of 11% Senior Secured Second Lien Notes and $1.389 billion principal amount of 11.75% Senior Secured Second Lien Notes, collectively
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
Federal and State Income Tax Allocation Agreements	EFH Corp. and certain of its subsidiaries (including EFCH, EFIH and TCEH, but not including Oncor Holdings and Oncor) are parties to a Federal and State Income Tax Allocation Agreement, executed on May 15, 2012 but effective as of January 1, 2010. EFH Corp., Oncor Holdings, Oncor, Texas Transmission, and Oncor Management Investment LLC are parties to a separate Federal and State Income Tax Allocation Agreement dated November 5, 2008. See Note 7 to the Financial Statements and Management's Discussion and Analysis, under Financial Condition.
FERC	US Federal Energy Regulatory Commission
Fifth Circuit Court	US Court of Appeals for the Fifth Circuit
GAAP	generally accepted accounting principles
GHG	greenhouse gas
GWh	gigawatt-hours
ICE	the IntercontinentalExchange, an electronic commodity derivative exchange
IRS	US Internal Revenue Service
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
Luminant	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
market heat rate	Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.
MATS	the Mercury and Air Toxics Standard established by the EPA

iii

Merger	the transaction referred to in the Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp., which was completed on October 10, 2007
MMBtu	million British thermal units
Moody's	Moody's Investors Services, Inc.
MSHA	US Mine Safety and Health Administration
MW	megawatts
MWh	megawatt-hours
NERC	North American Electric Reliability Corporation
NOX	nitrogen oxide
NRC	US Nuclear Regulatory Commission
NYMEX	the New York Mercantile Exchange, a commodity derivatives exchange
Oncor	Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities
Oncor Holdings	Oncor Electric Delivery Holdings Company LLC, a direct, wholly owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context
Oncor Ring-Fenced Entities	Oncor Holdings and its direct and indirect subsidiaries, including Oncor
OPEB	postretirement employee benefits other than pensions
Petition Date	April 29, 2014, the date the Debtors made the Bankruptcy Filing
Plan of Reorganization	Sixth Amended Joint Plan of Reorganization, as amended, Pursuant to Chapter 11 of the Bankruptcy Code confirmed by the Bankruptcy Court in December 2015, including the Plan Supplement
Plan Support Agreement	Third Amendment to the Amended and Restated Plan Support Agreement, entered into in December 2015, amending and restating the Plan Support Agreement approved by the Bankruptcy Court in September 2015
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.
Regulated Delivery segment	the EFH Corp. business segment that consists primarily of our investment in Oncor
REP	retail electric provider
RCT	Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
S&P	Standard & Poor's Ratings (a credit rating agency)
SEC	US Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
SG&A	selling, general and administrative

iv

Settlement Agreement	Amended and Restated Settlement Agreement among the Debtors, the Sponsor Group, settling TCEH first lien creditors, settling TCEH second lien creditors, settling TCEH unsecured creditors and the official committee of unsecured creditors of TCEH (collectively, the Settling Parties), filed by the Debtors with the Bankruptcy Court in December 2015. See Note 2 to the Financial Statements.
Settlement Agreement Order	The Bankruptcy Court's December 2015 order approving the Settlement Agreement
SO2	sulfur dioxide
Sponsor Group	Refers, collectively, to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Global, LLC (together with its affiliates, TPG) and GS Capital Partners, an affiliate of Goldman, Sachs & Co., that have an ownership interest in Texas Holdings.
TCEH	Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy market activities, and whose major subsidiaries include Luminant and TXU Energy
TCEH Debtors	EFCH, TCEH and the subsidiaries of TCEH that are Debtors in the Chapter 11 Cases
TCEH Demand Notes	Refers to certain loans from TCEH to EFH Corp. in the form of demand notes to finance EFH Corp. debt principal and interest payments and, until April 2011, other general corporate purposes of EFH Corp. that were guaranteed on a senior unsecured basis by EFCH and EFIH and were settled by EFH Corp. in January 2013.
TCEH DIP Facility	TCEH's $3.375 billion debtor-in-possession financing facility approved by the Bankruptcy Court in June 2014. See Note 12 to the Financial Statements.
TCEH Finance	TCEH Finance, Inc., a direct, wholly owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities
TCEH Senior Notes	Refers, collectively, to TCEH's and TCEH Finance's 10.25% Senior Notes and 10.25% Senior Notes, Series B (collectively, TCEH 10.25% Notes) and TCEH's and TCEH Finance's 10.50%/11.25% Senior Toggle Notes (TCEH Toggle Notes) with a total principal amount of $4.874 billion.
TCEH Senior Secured Facilities	Refers, collectively, to the TCEH First Lien Term Loan Facilities, TCEH First Lien Revolving Credit Facility and TCEH First Lien Letter of Credit Facility with a total principal amount of $22.616 billion.
TCEH Senior Secured Notes	TCEH's and TCEH Finance's $1.750 billion principal amount of 11.5% First Lien Senior Secured Notes
TCEH Senior Secured Second Lien Notes	Refers, collectively, to TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes and TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes, Series B with a total principal amount of $1.571 billion.
TCEQ	Texas Commission on Environmental Quality
Texas Holdings	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	Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities
Texas Transmission	Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor and is not affiliated with EFH Corp., any of EFH Corp.'s subsidiaries or any member of the Sponsor Group
TRE	Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and monitors compliance with ERCOT protocols
TXU Energy	TXU Energy Retail Company LLC, a direct, wholly owned subsidiary of TCEH that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
US	United States of America
VIE	variable interest entity

v

PART I.

Items 1. and 2. BUSINESS AND PROPERTIES

References in this report to "we," "our," "us" and "the Company" are to EFH Corp. and/or its subsidiaries, as apparent in the context. See Glossary for descriptions of major subsidiaries and other defined terms.

EFH Corp. Business

We are a Dallas, Texas-based energy company with a portfolio of competitive and regulated energy businesses. EFH Corp. is a holding company conducting its operations principally through its TCEH and Oncor subsidiaries. Collectively with its operating subsidiaries, EFH Corp. is the largest generator, retailer and distributor of electricity in Texas. Immediately below is an organization chart of the key subsidiaries discussed in this report.

Texas Holdings, which is controlled by the Sponsor Group, owns substantially all of the common stock of EFH Corp.

EFCH and EFIH are wholly owned by EFH Corp. TCEH is wholly owned by EFCH. EFIH indirectly holds an approximate 80% equity interest in Oncor.

EFCH's principal asset is its investment in TCEH. EFCH is a guarantor of a significant portion of TCEH's debt and $60 million principal amount of EFH Corp.'s debt.

TCEH, through its subsidiaries, is engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management activities and retail electricity operations. Collectively, with its operating subsidiaries, TCEH is the largest generator and retailer of electricity in Texas.

TCEH owns 13,772 MW of electricity generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas fueled generation facilities and accounts for approximately 16% of the generation capacity in ERCOT. TCEH provides competitive electricity and related services to approximately 1.7 million retail electricity customers in Texas.

EFIH's principal asset consists of its investment in Oncor Holdings, which owns 80% of the equity in Oncor. EFIH is also a guarantor of $60 million principal amount of EFH Corp.'s debt.

1

Oncor is engaged in regulated electricity transmission and distribution operations in Texas that are primarily regulated by the PUCT and, in certain instances, the FERC. Oncor provides transmission and distribution services to REPs, which sell electricity to residential and business consumers, as well as transmission services to electricity distribution companies, cooperatives and municipalities. Oncor operates the largest transmission and distribution system in Texas, delivering electricity to more than 3.3 million homes and businesses and operating more than 121,000 miles of transmission and distribution lines. A significant portion of Oncor's revenues represent fees for services provided to TCEH's retail electricity operations. Revenues from services provided to TCEH represented approximately 25% of Oncor's total reported consolidated revenues for each of the years ended December 31, 2015 and 2014.

EFH Corp. and Oncor have implemented certain structural and operational ring-fencing measures based on commitments made by Texas Holdings and Oncor to the PUCT as part of the Merger in 2007 to further enhance the credit quality of Oncor Holdings and Oncor. These measures serve to mitigate Oncor's and Oncor Holdings' credit exposure to the Texas Holdings Group with the intent to minimize the risk that a court would order any of the assets and liabilities of the Oncor Ring-Fenced Entities to be substantively consolidated with the assets and liabilities of any member of the Texas Holdings Group in the event any such member were to become a debtor in a bankruptcy case. As a result of these measures, EFH Corp. and EFIH do not control and do not consolidate Oncor Holdings and Oncor for financial reporting purposes. See Notes 1 and 4 to the Financial Statements for a description of the material features of these ring-fencing measures.

At December 31, 2015, we had approximately 8,860 full-time employees (including approximately 3,520 at Oncor). Approximately 2,510 employees are under collective bargaining agreements (including approximately 670 at Oncor).

Chapter 11 Cases

On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities (the Debtors), filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). During the pendency of the Bankruptcy Filing (the Chapter 11 Cases), the Debtors have operated, and continue to operate, their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. We intend to conduct our business operations in the normal course and maintain our focus on achieving excellence in customer service and meeting the needs of electricity consumers in Texas. In December 2015, the Bankruptcy Court entered the Confirmation Order approving the Debtors' Plan of Reorganization. The effectiveness of the Plan of Reorganization and our emergence from the Chapter 11 Cases is subject to several events and conditions that are not within our control. As a result, we cannot predict whether the Plan of Reorganization will become effective and/or when we will ultimately emerge from the Chapter 11 Cases.

Consistent with the ring-fencing measures discussed above, the assets and liabilities of the Oncor Ring-Fenced Entities have not been, and are not expected to be, substantively consolidated with the assets and liabilities of the Debtors in the Chapter 11 Cases.

For additional discussion of the Chapter 11 Cases and the effects on us, see Note 2 to the Financial Statements and Item 1A, Risk Factors – Risks Related to Chapter 11 Cases. See Note 12 to the Financial Statements for discussion of the DIP Facilities.

EFH Corp.'s Market

We operate primarily within the ERCOT electricity market. This market represents approximately 90% of the electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the Independent System Operator of the interconnected transmission grid for those systems. ERCOT's membership consists of approximately 300 corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, investor-owned utilities, REPs and consumers.

The ERCOT market operates under reliability standards set by the NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure adequacy and reliability of power supply across Texas' main interconnected transmission grid. ERCOT is responsible for scheduling power on the grid and maintaining reliable operations of the electricity supply system. Its responsibilities include centralized dispatch of the power pool and ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. ERCOT also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.

2

Oncor, along with other owners of transmission and distribution facilities in Texas, assists ERCOT in its operations. Oncor has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated distribution service area. Oncor participates with ERCOT and other ERCOT utilities in obtaining regulatory approvals and planning, designing, constructing and upgrading transmission lines in order to remove existing constraints and interconnect generation on the ERCOT transmission grid. The transmission line projects are necessary to meet reliability needs, support energy production and increase bulk power transfer capability.

Installed generation capacity in the ERCOT market for the year 2015 totaled approximately 87,400 MW, including approximately 750 MW of mothballed (idled) capacity and approximately 16,900 MW of wind and other resources that may not be available coincident with system need. Texas has more installed wind generation capacity than any other state in the US. In 2015, ERCOT's hourly demand peaked at 69,877 MW as compared to peak hourly demand of 66,454 MW in 2014. Of ERCOT's total installed capacity, approximately 53% is natural gas fueled generation, approximately 22% is lignite/coal fueled generation, approximately 6% is nuclear fueled generation and approximately 19% is generated by wind and other renewable resources.

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 1,120 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.

Natural gas fueled generation is the predominant electricity capacity resource (approximately 53%) in the ERCOT market and accounted for approximately 48% of the electricity produced in the ERCOT market in 2015. Because of the significant amount of natural gas fueled capacity and the ability of such facilities to more readily increase or decrease production when compared to nuclear and lignite/coal fueled generation, marginal demand for electricity in ERCOT is usually met by natural gas fueled facilities. As a result, wholesale electricity prices in ERCOT have generally moved with natural gas prices.

EFH Corp.'s Business Focus

Each of our businesses focuses its operations on key safety, reliability, economic and environmental drivers for that business, as described below:

• TCEH focuses on optimizing and developing its generation fleet to safely provide reliable electricity supply in a cost-effective manner and in consideration of environmental impacts, hedging its commodity price and volume exposure and providing high quality service and innovative energy products to retail and wholesale customers.

• Oncor focuses on delivering electricity in a safe and reliable manner, minimizing service interruptions and investing in its transmission and distribution infrastructure to maintain its system, serving its growing customer base with a modernized grid and supporting energy production.

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.

3

Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment, consisting largely of TCEH and its subsidiaries, and the Regulated Delivery segment, consisting largely of our investment in Oncor. See Note 20 to the Financial Statements for additional financial information for the segments.

Competitive Electric Segment

Key activities, including risk management related to commodity price and availability, as well as electricity sourcing for our retail and wholesale customers, are performed on an integrated basis. This integration strategy, the execution of which is discussed below in describing the activities of our wholesale operations, is a key consideration in our operating segment determination. Our ability to balance the electricity demand requirements of our retail and wholesale customers along with the supply from our generation sources is a critical activity that has significant impacts on our profitability. For purposes of market identity and operational accountability, our operations are grouped and identified as Luminant, which is engaged in electricity generation and wholesale market activities, and TXU Energy, which is engaged in retail electricity activities. These activities are conducted through separate legal entities.

Luminant — Luminant's existing fleet consists of 36 electricity generation units in Texas, all of which are owned, with total installed nameplate generating capacity as shown in the table below:

Fuel Type	Installed Nameplate Capacity (MW)	Number of Plant Sites	Number of Units
Nuclear	2,300	1	2
Lignite/coal	8,017	5	12
Natural gas (a)	3,455	7	22
Total	13,772	13	36

___________

(a) See La Frontera CCGTs below for discussion of an agreement to purchase 2,988 MW of natural gas fueled generation capacity not included above.

Our generation units are located primarily on owned land. Nuclear and lignite/coal fueled units are generally scheduled to run at capacity except for periods of scheduled maintenance activities; however, we reduce production from certain lignite/coal fueled generation units, referred to as economic backdown, during periods when wholesale electricity prices are less than the unit's variable production costs. In addition, we have implemented seasonal suspensions of operations of certain lignite/coal fueled generation units because of the low wholesale electricity price environment. The natural gas fueled generation units supplement the nuclear and lignite/coal fueled generation capacity in meeting consumption in peak demand periods as production from certain of these units, particularly combustion-turbine units, can be more readily ramped up or down as demand warrants.

Nuclear Generation Operations — Luminant operates two nuclear generation units at the Comanche Peak plant site, each of which is designed for a capacity of 1,150 MW. Comanche Peak Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the refueling cycle results in the refueling of both units during the same year, the latest of which occurred in 2014. While one unit is undergoing a refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance, modification and testing activities are completed that cannot be accomplished when the unit is in operation. Over the last three years the refueling outage period per unit has ranged from 22 to 54 days. The Comanche Peak facility operated at a capacity factor of 99%, 92.5% and 101.7% in 2015, 2014 and 2013, respectively.

Luminant has contracts in place for the majority of its nuclear fuel requirements for 2016. Luminant has contracts in place for substantially all of its nuclear fuel fabrication and enrichment services through 2018. As part of the Chapter 11 Cases, Luminant has terminated or renegotiated certain nuclear fuel contracts to provide for better economic or operational terms and conditions. Luminant does not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion, enrichment and fabrication services in the foreseeable future.

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The nuclear industry has developed ways to store used nuclear fuel on site at nuclear generation facilities, primarily through the use of dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the US. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear fuel storage capability is sufficient for the foreseeable future.

Luminant expects decommissioning activities to begin in 2050 for Comanche Peak Unit 1 and 2053 for Unit 2 and common facilities. Decommissioning costs will be paid from a decommissioning trust that, pursuant to Texas law, is intended to be fully funded from Oncor's customers through an ongoing delivery surcharge. (See Note 21 to the Financial Statements for discussion of the decommissioning trust fund.) Under applicable law, the Chapter 11 Cases are not expected to have any effect on the collection of such surcharge or the ongoing viability of the decommissioning trust.

Nuclear insurance provisions are discussed in Note 14 to the Financial Statements.

Nuclear Generation Development — In 2008, we filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at our existing Comanche Peak nuclear plant site. In connection with the filing of the application, in 2009, subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company LLC (CPNPC), to further the development of the two new nuclear generation units using MHI's US-Advanced Pressurized Water Reactor (US-APWR) technology. In the fourth quarter 2014, MHI withdrew from the joint venture, and the TCEH subsidiary now owns 100% of CPNPC.

As a result of MHI's withdrawal, Luminant suspended all reviews by the NRC associated with the combined operating license application. MHI expressed to the NRC its continuing commitment to obtaining an NRC design certification for its technology. See Note 9 to the Financial Statements for discussion of impairment of the joint venture's assets in 2013.

Lignite/Coal Fueled Generation Operations — Luminant's lignite/coal fueled generation fleet capacity totals 8,017 MW and consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units), Oak Grove (2 units) and Sandow (2 units) plant sites. Maintenance outages at these units are scheduled during the spring or fall off-peak demand periods. Over the last three years, the total annual scheduled and unscheduled outages per unit averaged 33 days in duration. Luminant's lignite/coal fueled generation fleet operated at a capacity factor of 59.5% in 2015, 69.6% in 2014 and 74.1% in 2013. This performance reflects increased economic backdown of the units and the seasonal suspension of certain units due to the persistent low wholesale power price environment in ERCOT.

Luminant meets all of its fuel requirements at its Oak Grove and Sandow generation facilities with lignite that it mines. Luminant meets its fuel requirements for its Big Brown, Monticello and Martin Lake generation units by blending lignite it mines with coal purchased from multiple suppliers under contracts of various lengths and transported from the Powder River Basin to Luminant's generation plants by railcar. In 2015, approximately 48% of the fuel used at the Big Brown, Monticello and Martin Lake generation facilities and 69% of the fuel used at all of Luminant's lignite/coal fueled generation facilities was supplied from surface minable lignite reserves dedicated to our generation plants, which are located adjacent to the reserves.

As a result of projected mining development costs, current economic forecasts and regulatory uncertainty, in 2014, Luminant decided to transition the fuel plans at its Big Brown and Monticello generation facilities to be fully fueled with coal from the Powder River Basin. As a result, it plans to discontinue lignite mining operations at these sites once mining and reclamation of current mine sites is complete. Lignite mining and the majority of reclamation activities at these facilities is expected to be completed by the end of 2020 unless economic forecasts and increased regulatory certainty justify additional mine development. See Note 9 to the Financial Statements for discussion of the impairment of certain generation facilities and related mining facilities and the write off of certain mine development costs.

See Environmental Regulations and Related Considerations – Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions for discussion of potential effects of recent EPA rules on future operations of our generation units.

Natural Gas Fueled Generation Operations — Luminant owns a fleet of 22 natural gas fueled generation units, of which 7 are steam generation units totaling 2,480 MW of capacity and 15 are combustion turbine generation units totaling 975 MW of capacity. The natural gas fueled units predominantly serve as peaking units that can be ramped up or down to balance electricity supply and demand.

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La Frontera CCGTs — In November 2015, Luminant entered into a purchase and sale agreement with La Frontera Ventures, LLC, a subsidiary of NextEra Energy, Inc., to purchase all of the membership interests in La Frontera Holdings, LLC, the indirect owner of two combined cycle gas turbine (CCGT) natural gas fueled generation facilities totaling 2,988 MW of capacity located in ERCOT. The closing of this transaction is subject to several customary closing conditions. For additional discussion, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events and Items Influencing Future Performance – La Frontera CCGTs.

Natural Gas Fueled Generation Development —In recent years, the TCEQ granted air permits to Luminant to build natural gas fueled generation units at certain of our existing plant sites. We believe current market conditions do not provide adequate economic returns for the development or construction of these facilities; however, we believe additional generation resources will be needed in the future to support electricity demand growth and reliability in the ERCOT market. The following table summarizes the potential facilities that form the basis of such air permits.

Plant Site	Type of Generation Technology	Number of Units	Total Capacity	Status of Air and Greenhouse Gas Permits Filed with TCEQ
DeCordova	Combustion Turbine	2	420 MW to 460 MW	Granted
DeCordova (a)	Combined Cycle	1	730 MW to 810 MW	Pending
Eagle Mountain	Combined Cycle	1	730 MW to 810 MW	Pending
Lake Creek	Combustion Turbine	2	420 MW to 460 MW	Granted
Permian Basin	Combustion Turbine	2	420 MW to 460 MW	Granted
Tradinghouse	Combustion Turbine	2	420 MW to 460 MW	Granted
Tradinghouse (a)	Combined Cycle	2	1460 MW to 1620 MW	Pending
Valley	Combustion Turbine	2	420 MW to 460 MW	Granted

___________

(a) These potential units would be an alternative to the potential combustion turbine units at such sites, respectively.

Wholesale Operations — Luminant's wholesale operations play a pivotal role in our Competitive Electric segment by optimally dispatching the generation fleet, procuring fuels for the generation fleet, sourcing all of TXU Energy's electricity requirements and managing commodity risk for the retail and wholesale electricity sales operations.

Our electricity price exposure is managed across the complementary generation, wholesale and retail operations on an integrated basis. Under this approach, Luminant's wholesale operations manage the risks of imbalances between generation supply and sales demand of both wholesale and retail customers, as well as exposures to natural gas price movements and market heat rate changes (variations in the relationships between natural gas prices and wholesale electricity prices), through wholesale market activities that include physical purchases and sales and transacting in financial instruments.

Luminant's wholesale operations provide TXU Energy and other retail and wholesale customers with electricity-related services to meet their demands and the operating requirements of ERCOT. In consideration of electricity generation resource availability and consumer demand levels that can be highly variable, as well as opportunities to meet longer-term objectives of larger wholesale market participants, Luminant buys and sells electricity in short-term transactions and executes longer-term forward electricity purchase and sales agreements. Luminant is also a significant purchaser of wind-generated electricity in Texas and the US with approximately 390 MW of existing wind power under contract.

Fuel price exposure, primarily relating to Powder River Basin coal, natural gas, uranium and fuel oil, as well as fuel transportation costs, is managed primarily through short- and long-term contracts for physical delivery of fuel as well as financial contracts utilized to hedge price risk.

In its hedging activities, Luminant enters into contracts for the physical delivery of electricity and fuel commodities, exchange traded and over-the-counter financial contracts and bilateral contracts with other wholesale market participants, including generators and end-use customers. A significant element of these activities involves natural gas hedging, designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, principally utilizing natural gas-related financial instruments.

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The wholesale operations also dispatch Luminant's available generation capacity. These dispatching activities include economic backdown of lignite/coal fueled units and ramping up and down of natural gas fueled units as market conditions warrant. Luminant's dispatching activities are performed on a centrally managed real-time basis optimizing operational activities across the fleet and interfacing with various wholesale market channels. In addition, the wholesale operations manage the fuel procurement requirements for Luminant's fossil fuel and nuclear generation facilities.

Luminant's wholesale operations manage exposure to wholesale commodity and credit-related risk within established transactional risk management policies, limits and controls. These policies, limits and controls have been structured so that they are practical in application and consistent with stated business objectives. Risk management processes include capturing transaction data, monitoring transaction types and notional limits, reviewing and managing credit risk, performing and validating valuations and reporting exposures on a daily basis using risk management information systems designed to support a large transactional portfolio. Risk management also includes a disciplinary program to address any violations of the policies and periodic reviews of these policies to ensure they are responsive to changing market and business conditions.

TXU Energy — TXU Energy serves approximately 1.7 million residential and commercial retail electricity customers in Texas. Approximately 65% of our reported retail revenues in 2015 represented sales to residential customers. Texas is one of the fastest growing states in the nation with a diverse economy and, as a result, has attracted a number of competitors into the retail electricity market; consequently, competition is robust. TXU Energy, as an active participant in this competitive market, provides retail electric service to all areas of the ERCOT market now open to competition, including the Dallas/Fort Worth area, Houston, Corpus Christi, and certain other parts of south Texas, and holds an approximately 25% and 17% share of the residential and business customers in ERCOT, respectively. TXU Energy competitively markets its services to add new customers and retain its existing customer base, as well as opportunistically acquire customers from other REPs. There are more than 100 REPs certified to compete within the ERCOT region.

TXU Energy's strategy focuses on providing its customers with high quality customer service and creating new products and services to meet customer needs; accordingly, customer care enhancements are implemented on an ongoing basis to continually improve customer satisfaction. TXU Energy offers a wide range of innovative residential products to meet varying customer needs.

Regulation — Luminant is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to the jurisdiction of the NRC with respect to its nuclear generation plant. NRC regulations govern the granting of licenses for the construction and operation of nuclear fueled generation facilities and subject such facilities to continuing review and regulation. In addition, Luminant is subject to the jurisdiction of the RCT's oversight of its lignite mining and reclamation operations.

Luminant is also subject to the jurisdiction of the PUCT's oversight of the competitive ERCOT wholesale electricity market. PUCT rules establish a framework for and robust oversight of wholesale electricity pricing and market behavior. Luminant is also subject to the requirements of the ERCOT Nodal Protocols as well as reliability standards adopted and enforced by the TRE and the NERC, including NERC critical infrastructure protection (CIP) standards. Luminant is also subject to the authority of the CFTC as it continues to implement rules and provide oversight vested in the agency by the Wall Street Reform and Consumer Protection Act of 2010, particularly Title VII, which deals with over-the-counter derivative markets.

TXU Energy is a licensed REP under the Texas Electric Choice Act and is subject to the jurisdiction of the PUCT with respect to provision of electricity service in ERCOT. PUCT rules govern the granting of licenses for REPs, including oversight but not setting of retail prices. TXU Energy is also subject to the requirements of the ERCOT Nodal Protocols.

Regulated Delivery Segment

The Regulated Delivery segment consists largely of our investment in Oncor. Oncor is a regulated electricity transmission and distribution company that provides the service of delivering electricity safely, reliably and economically to end-use consumers through its electrical systems, as well as providing transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas. Oncor's service territory comprises 91 counties and more than 400 incorporated municipalities, including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler and Killeen. Oncor's transmission and distribution assets are located principally in the north-central, eastern and western parts of Texas. Most of Oncor's 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. Oncor's transmission and distribution rates are regulated by the PUCT.

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Oncor is not a seller of electricity, nor does it purchase electricity for resale. It provides transmission services to electricity distribution companies, cooperatives and municipalities. It provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Oncor is also subject to the requirements of the ERCOT Nodal Protocols as well as reliability standards adopted and enforced by the TRE and the NERC, including NERC CIP standards.

Performance — Oncor achieved or exceeded market performance protocols in 12 out of 14 PUCT market metrics in 2015. 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 2015, Oncor invested approximately $1.2 billion in its network to upgrade the transmission system and associated facilities, to extend the distribution infrastructure and to pursue certain initiatives in infrastructure maintenance and information technology.

Electricity Transmission — Oncor's electricity transmission business is responsible for the safe and reliable operations of its 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 Oncor's transmission facilities in coordination with ERCOT.

Oncor is a member of ERCOT, and its transmission business actively assists the operations of ERCOT and market participants. Through its transmission business, Oncor participates 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. Other services offered by Oncor through its 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 Oncor to update its 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, 2015, Oncor's transmission facilities included 6,410 circuit miles of 345kV transmission lines and 9,536 circuit miles of 138kV and 69kV transmission lines. Sixty-nine generation facilities totaling 36,991 MW were directly connected to Oncor's transmission system at December 31, 2015, and 298 transmission stations and 717 distribution substations were served from Oncor's transmission system.

At December 31, 2015, Oncor's 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.	8	112	25
Rayburn Country Electric Cooperative, Inc.	—	40	6
Lower Colorado River Authority	9	27	2
Texas New Mexico Power	4	10	12
Tex-La Electric Cooperative of Texas, Inc.	—	12	1
American Electric Power Company, Inc. (a)	5	5	8
Texas Municipal Power Agency	7	6	—
Lone Star Transmission	12	—	—
Centerpoint Energy Inc.	8	—	—
Sharyland Utilities, L.P.	1	4	—
Electric Transmission Texas, LLC	8	1	—
Other small systems operating wholly within Texas	6	6	3

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

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Electricity Distribution — Oncor's 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 Oncor's certificated service area. Oncor's distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through 3,237 distribution feeders.

The Oncor distribution system included over 3.3 million points of delivery at December 31, 2015. Over the past five years, the number of distribution system points of delivery served by Oncor, excluding lighting sites, grew an average of 1.39% per year. Oncor added approximately 49,200 points of delivery in 2015.

The Oncor distribution system consists of 56,956 miles of overhead primary conductors, 21,323 miles of overhead secondary and street light conductors, 16,834 miles of underground primary conductors and 10,415 miles of underground secondary and street light conductors. The majority of the distribution system operates at 25kV and 12.5kV.

Oncor's 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 allows Oncor to file, under certain circumstances, up to four rate adjustments between rate reviews to recover distribution-related investments on an interim basis. Oncor has not filed any such distribution-related rate adjustments to date.

Customers — Oncor's transmission customers consist of municipalities, electric cooperatives and other distribution companies. Oncor's distribution customers consist of approximately 80 REPs, including TCEH's retail sales operations and certain electric cooperatives in Oncor's certificated service area. Revenues from services provided to TCEH represented approximately 25% of Oncor's total reported consolidated revenues for 2015. Revenues from REP subsidiaries of one nonaffiliated entity collectively represented approximately 17% of Oncor's total reported consolidated revenues for 2015. No other customer represented more than 10% of Oncor's total operating revenues. The consumers of the electricity delivered by Oncor are free to choose their electricity supplier from REPs who compete for their business.

Regulation and Rates — As its operations are wholly within Texas, Oncor is not a public utility as defined in the Federal Power Act and, as a result, it is not subject to general regulation under that Act. However, Oncor is subject to reliability standards adopted and enforced by the TRE and the NERC, including NERC CIP standards, under the Federal Power Act.

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 Oncor.

Securitization Bonds — Oncor's operations include its wholly owned, bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC. This financing subsidiary was organized for the limited purpose of issuing certain securitization (transition) bonds in 2003 and 2004. Oncor Electric Delivery Transition Bond Company LLC 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, 2015, aggregate principal amounts of transition bonds outstanding, which mature in May 2016, totaled $41 million.

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Environmental Regulations and Related Considerations

Global Climate Change

Background — There is a debate nationally and internationally about global climate change and how greenhouse gas (GHG) emissions, such as CO₂, might contribute to global climate change. GHG emissions from the combustion of fossil fuels, primarily by our lignite/coal fueled generation plants, represent the substantial majority of our total GHG emissions. CO₂, methane and nitrous oxide are emitted in this combustion process, with CO₂ representing the largest portion of these GHG emissions. We estimate that our generation facilities produced 50 million short tons of CO₂ in 2015. Our financial condition, liquidity or results of operations could be materially affected by the enactment of statutes or regulations that mandate a reduction in GHG emissions or that impose financial penalties, costs or taxes on those that produce GHG emissions. See Item 1A, Risk Factors for additional discussion of risks posed to us regarding global climate change regulation.

Greenhouse Gas Emissions Regulation — Federal Level — Over the past several years, the EPA has taken a number of actions regarding GHG emissions. In December 2009, the EPA issued a finding that GHG emissions endanger human health and the environment and that emissions from motor vehicles contribute to that endangerment. The EPA's finding required it to begin regulating GHG emissions from motor vehicles, and the EPA ultimately extended regulation of GHG emissions to stationary sources under existing provisions of the federal Clean Air Act (CAA). In March 2010, the EPA determined that the CAA's Prevention of Significant Deterioration (PSD) program permit requirements would apply to newly identified pollutants such as GHGs when a nation-wide rule requiring the control of a pollutant takes effect. Under this determination, PSD permitting requirements became applicable to GHG emissions from planned stationary sources or planned modifications to stationary sources that had not been issued a PSD permit by January 2011. In June 2010, the EPA finalized its so-called "tailoring rule" that established new thresholds of GHG emissions for the applicability of permits under the CAA for stationary sources, including our electricity generation facilities. The EPA's tailoring rule defined a threshold of GHG emissions for determining applicability of the CAA's PSD and Title V permitting programs at levels greater than the emission thresholds contained in the CAA. In June 2014, the US Supreme Court ruled that the EPA's regulation of GHG emissions from motor vehicles did not mandate that the EPA implement permit requirements for stationary source GHGs, but upheld the EPA's permitting program in situations where the source is already required to permit emissions that have historically been covered under the CAA. The case was remanded to the D.C. Circuit Court for further proceedings consistent with the US Supreme Court's decision. In an April 2014 order, the D.C. Circuit ordered that the EPA's regulations be vacated to the extent that they require a "GHG-only" stationary source to obtain a PSD or Title V permit. It further ordered the EPA to rescind or revise its regulations as soon as practical and to consider whether any further regulatory changes are needed to implement the US Supreme Court's ruling. In May 2014, the EPA issued a direct final rule to provide a mechanism for rescinding permits issued that were issued because of "GHG-only" emission triggers. The EPA has projected that it will propose a rule in early 2016 establishing modification thresholds for GHG emissions increases that are concurrent with emissions increases of historically covered pollutants. Current EPA guidance prescribes the use of tailoring rule thresholds.

The EPA has finalized two rules to address greenhouse gas (GHG) emissions from new, modified and reconstructed units, and existing electricity generation plants. The final rules for new and modified or reconstructed units were released in August 2015. The final rule for existing plants, also released in August 2015, would establish state-specific emission rate goals to reduce nationwide CO₂ emissions related to affected electricity generation units by over 30% from 2012 emission levels by 2030. In October 2015, the final rules, including the rule for existing plants, were published in the Federal Register. In August 2015, the EPA proposed model rules and federal plan requirements for states to consider as they develop state plans to comply with the rules for GHG emissions. A federal plan would then be deemed final for a state if a state fails to submit a state plan by the deadlines established in the CAA for existing plants or if the EPA disapproves a submitted state plan. We filed comments on the federal plan proposal in January 2016. The EPA is expected to finalize the model rule by the summer of 2016. While we cannot predict the outcome of this rulemaking and legal proceedings on our results of operations, liquidity or financial condition, the impacts could be material. See the discussion of existing litigation related to GHG emissions rulemaking in Note 14 to the Financial Statements.

A number of members of the US Congress from both parties have introduced legislation to either block or delay EPA regulation of GHGs under the CAA, and legislative activity in this area in the future is possible.

State and Regional Level — There are currently no Texas state regulations in effect concerning GHGs, except for permitting in situations where the source is already required to permit emissions that have been traditionally covered by the CAA, and there are no regional initiatives concerning GHGs in which the State of Texas is a participant.

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EFH Corp.'s Voluntary Energy Efficiency, Renewable Energy, and Global Climate Change Efforts — We are actively engaged in, considering, or expect to be actively engaged in, business activities that could result in reduced GHG emissions including:

• Investing in Energy Efficiency and Related Initiatives by Our Competitive Businesses — Since the Merger, our competitive businesses have invested more than $100 million in energy efficiency and related initiatives, including software- and hardware-based services deployed behind the meter. These programs leverage advanced meter interval data and in-home devices to provide usage and other information to customers. Examples of these initiatives include: the TXU Energy MyEnergy Dashboard^SM, a set of online tools that show residential customers how and when they use electricity;the Online Energy Store providing customers cost-effective energy-saving products; the iThermostat, a web-enabled programmable thermostat; TXU Energy Right Time Pricing Products^SM, including time-based electricity rates; the provision of GreenBack rebates to business customers for purchasing new energy efficient equipment for their facilities; the TXU Energy Electricity Usage Report, a weekly email that contains charts and graphs that give customers insight to better control their electricity usage and bills; and home warranty service plans that cover repair or replacement for various appliances such as heating and cooling systems in homes.

• Purchasing Electricity from Renewable Sources — We provide electricity from renewable sources by purchasing wind and solar power. Our total wind power portfolio is currently approximately 390 MW. In addition, we have agreed to purchase up to 116 MW of solar power beginning in late 2016. We also purchase additional renewable energy credits (RECs) to support sales of renewable power to our customers.

• Promoting the Use of Solar Power — TXU Energy provides qualified customers, through its TXU Solar program, the ability to purchase or finance the addition of solar panels to their homes. TXU Energy also purchases surplus renewable distributed generation from qualified customers with on-site renewable generation. In addition, customers ineligible for solar panels can enroll in rate plans such as TXU Energy Solar Advantage^SM,, backed by 100% solar energy through RECs purchased from Texas solar plants.

• New Energy Technologies — We continue to evaluate the development and commercialization of cleaner power facility technologies, including technologies that support capture and/or reduction of CO₂; incremental renewable sources of electricity, including wind and solar power; energy storage, including advanced battery and compressed air storage, as well as related technologies that seek to lower emissions intensity. Additionally, we continue to explore and participate in opportunities to accelerate the adoption of electric cars and plug-in hybrid electric vehicles that have the potential to reduce overall GHG emissions and are furthering the advance of such vehicles by supporting, and helping develop infrastructure for, networks of charging stations for electric vehicles.

• Offsetting GHG Emissions by Planting Trees — We are engaged in a number of tree planting programs that offset GHG emissions, resulting in the planting of over 1.2 million trees in 2015. The majority of these trees were planted as part of our mining reclamation efforts but also include TXU Energy's Urban Tree Farm program, which has planted more than 218,000 trees since its inception in 2002.

• Investing in Energy Efficiency Initiatives by Oncor — Oncor's 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 Oncor's deployment of advanced digital metering equipment. 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.

• Participating in the CREZ Program — Oncor has largely completed construction of CREZ transmission facilities (at a cost of approximately $2.0 billion) that are designed to connect existing and future renewable energy facilities to the electricity transmission system in ERCOT.

Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions

Air Transport Regulations: Cross-State Air Pollution Rule(CSAPR)— The CSAPR implements the provisions of the Clean Air Act requiring states to reduce emissions of sulfur dioxide (SO₂) and nitrogen oxide (NO_X) that significantly contribute to other states failing to attain or maintain compliance with the EPA's National Ambient Air Quality Standards (NAAQS) for fine particulate matter and/or ozone.

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The CSAPR became effective January 1, 2015. In July 2015, following a remand of the case from the US Supreme Court to consider further legal challenges, the D.C. Circuit Court unanimously ruled in favor of us and other petitioners, holding that the CSAPR emissions budgets over-controlled Texas and other states. The D.C. Circuit Court remanded those states' budgets to the EPA for reconsideration. While we planned to participate in the EPA's reconsideration process to develop increased budgets that do not over-control Texas, the EPA instead responded to the remand by updating the budget for the 2008 ozone standard with a new rulemaking without explicitly addressing the issues of over-control of the 1997 standard. Comments on the EPA's proposal were submitted by Luminant in February 2016. While we cannot predict the outcome of future proceedings related to the CSAPR, including the EPA's reconsideration of the CSAPR emissions budgets for affected states, based upon our current operating plans, we do not believe that the CSAPR will cause any material impacts on our operations, liquidity or financial condition.

In November 2015, the EPA proposed an update to the CSAPR to address interstate emission transport to areas projected to be in nonattainment with the 2008 eight-hour ozone standard in 2017. Texas is modeled to contribute significantly to several metropolitan areas in northern and northeastern states. The proposed rule would reduce our ozone season CSAPR NO_X allowances by approximately 10% in 2017. Luminant submitted comments on the proposal in February 2016.

Mercury and Air Toxics Standard (MATS) — The MATS rule regulates the emissions of mercury, nonmercury metals, hazardous organic compounds and acid gases. Any additional control equipment retrofits on our lignite/coal fueled generation units required to comply with the MATS rule were required to be installed by April 2015 unless a one-year extension was granted. The TCEQ granted one-year MATS compliance extensions for our Big Brown, Martin Lake, Monticello and Sandow 4 generation facilities, which require those facilities to begin compliance in April 2016.

In June 2015, the US Supreme Court reversed and remanded the MATS rule back to the D.C. Circuit Court for further action after considering the question of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. The US Supreme Court held that the EPA must consider cost, including cost of compliance, before deciding whether regulation is appropriate and necessary. In September 2015, certain states and industry petitioners, including a subsidiary of TCEH, filed a motion in the D.C. Circuit Court requesting that the court vacate the MATS rule. In December 2015, the D.C. Circuit Court issued an order remanding the MATS rule without vacatur to the EPA for further consideration based on the EPA's representation that it will finalize the necessary and appropriate finding by April 2016. The MATS rule remains in effect, and generation units must continue to comply pending further action from the EPA. While we cannot predict the outcome of future proceedings related to the MATS rule, we do not expect the MATS rule will have any material impact on our results of operations, liquidity or financial condition.

Regional Haze — The Regional Haze Program of the CAA establishes "as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I federal areas, like national parks, which impairment results from man-made pollution." There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. Second, electricity generation units built between 1962 and 1977 are subject to best available retrofit technology (BART) standards designed to improve visibility. BART reductions of SO₂ and NO_X are required either on a unit-by-unit basis or are deemed satisfied by state participation in an EPA-approved regional trading program such as the CSAPR. In February 2009, the TCEQ submitted a State Implementation Plan (SIP) concerning regional haze (Regional Haze SIP) to the EPA. In December 2011, the EPA proposed a limited disapproval of the Regional Haze SIP due to its reliance on the Clean Air Interstate Rule (CAIR) instead of the EPA's replacement CSAPR program. In August 2012, we filed a petition for review in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the EPA's limited disapproval of the Regional Haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court's decision in the CSAPR litigation. In September 2012, we filed a petition to intervene in a case filed by industry groups and other states and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance of a Federal Implementation Plan (FIP) regarding the regional haze BART program. The Fifth Circuit Court case has since been transferred to the D.C. Circuit Court and consolidated with other pending BART program regional haze appeals. No schedule has been set in the consolidated cases now in the D.C. Circuit Court.

In response to a lawsuit by environmental groups, the D.C. Circuit Court issued a consent decree in March 2012 that required the EPA to propose a decision on the Regional Haze SIP by May 2012 and finalize that decision by November 2012. The consent decree requires a FIP for any provisions that the EPA disapproves. The D.C. Circuit Court has amended the consent decree several times to extend the dates for the EPA to propose and finalize a decision on the Regional Haze SIP. The consent decree was modified in December 2015 to extend the deadline for the EPA to finalize action on the determination and adoption of requirements for BART for electricity generation. Under the amended consent decree the EPA has until December 2016 to finalize a FIP for BART for Texas electricity generation sources, if the EPA determines that BART requirements have not been met.

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In June 2014, the EPA issued requests for information under Section 114 of the CAA to Luminant and other generators in Texas. After releasing a proposed rule in November 2014 and receiving comments from a number of parties, including Luminant and the State of Texas in April 2015, the EPA released a final rule in January 2016 approving in part and disapproving in part Texas' SIP for Regional Haze and issuing a FIP for Regional Haze. In the rule, the EPA asserts that the Texas SIP does not show reasonable progress in improving visibility for two areas in Texas and that its long-term strategy fails to make emission reductions needed to achieve reasonable progress in improving visibility in the Wichita Mountains of Oklahoma. Unlike the proposed rule and inconsistent with how the EPA has applied Regional Haze rules to other states, the EPA's final rule does not treat Texas's compliance with the CSAPR as satisfying its obligations under the BART portion of the Regional Haze Program. The EPA concluded that it would not be appropriate to finalize that determination at this time given the remand of the CSAPR budgets. In our view, the EPA's proposed FIP for Texas goes beyond the requirements of the CSAPR and sets emission limits on a unit-by-unit basis for 15 electricity generation units in Texas. The EPA's proposed emission limits assume additional control equipment for specific coal fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven generation units and upgrades to existing scrubbers at seven generation units. Specifically for Luminant, the EPA's emission limitations are based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4. Luminant is continuing to evaluate the requirements and potential financial and operational impacts of the rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the FIP (if those limits are even possible to attain), along with the existence of low wholesale power prices in ERCOT, would likely challenge the long-term economic viability of those units. The scrubber upgrades will be required by February 2019, and the new scrubbers will be required by February 2021. While we cannot predict the outcome of the rulemaking and any possible legal proceedings, the result may have a material impact on our results of operations, liquidity or financial condition.

State Implementation Plan (SIP) Emissions Rules — The CAA requires each state to monitor air quality for compliance with federal health standards. The EPA is required to periodically review, and if appropriate, revise all national ambient air quality standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted SIP rules in May 2007 to deal with eight-hour ozone standards, which required NO_X emission reductions from certain of our peaking natural gas fueled units in the Dallas-Fort Worth area. In May 2012, the EPA designated nonattainment areas and, as required, the TCEQ submitted a SIP attainment demonstration to the EPA that required no additional emission reductions from our facilities. In 2010 the EPA added a new one-hour nitrogen dioxide (NO₂) and one-hour SO₂ National Ambient Air Quality Standard (NAAQS) that may require actions within Texas to reduce emissions. Based on current monitoring, Texas has recommended to the EPA that no area in Texas is in nonattainment with a 2010 one-hour SO₂ standard. The EPA designated 29 areas in 16 states as nonattainment but did not finalize designations for other areas of the country, including Texas. In April 2014, the EPA issued a proposed rule establishing data requirements and deadlines associated with a timeline to expand existing monitoring networks and require modeling to determine attainment status for the other areas. Areas where modeling will be used will be designated in 2017 with attainment demonstrations due in 2019, while areas with expanded or new monitors will be designated in 2020 with SIP revisions due in 2022. The EPA finalized this rule in August 2015 with an evaluation threshold for sources that emit 2,000 tons or more per year. Separately, the Sierra Club filed suit to compel the EPA to make SO₂ designations. The Sierra Club and the Natural Resources Defense Council also filed a lawsuit seeking to force the EPA to issue designations using air modeling. The Sierra Club provided the EPA with modeling that implicates Luminant's Big Brown, Monticello and Martin Lake coal plants as causing NAAQS exceedances. Notwithstanding the timelines in the data requirements rule, in March 2015, the US District Court of Northern California granted the EPA and the Sierra Club's motion to enter into a proposed consent decree with the Sierra Club that would require designations in July 2016 for areas with sources that emit 16,000 tons or more of SO₂. The ruling is being appealed to the U.S. Court of Appeals Ninth Circuit by Texas and other states who are parties to the case. We are not a party to this litigation, but we are continuing to monitor the case. In September 2015, Texas updated its recommendation of area designations for the one-hour SO₂ NAAQS, recommending that counties in Texas be designated either attainment based on monitoring data or unclassifiable/attainment where there are no monitors. In February 2016, the EPA notified Texas of EPA's preliminary intention to designate as nonattainment areas around our Big Brown, Monticello and Martin Lake plants based on modeling data submitted to the EPA by the Sierra Club. We continue to believe that these models do not accurately predict actual SO₂ emissions measurements and that these designations should be determined by emissions data from air quality monitors. Should the EPA finalize these designations as intended in July 2016, Texas will begin the multi-year process to evaluate what potential emission controls or operational changes, if any, may be necessary to demonstrate attainment. The EPA has also initiated efforts to expand near-road monitoring for fine particulates and NO_X, which will increase the risk that an area could be labeled as nonattainment as a result of the proximity of the monitors to mobile sources. We cannot predict the impact of the new standards on our business, results of operations or financial condition until the TCEQ adopts (if required) an implementation plan with respect to the standards.

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In February 2013, in response to a petition for rulemaking filed by the Sierra Club, the EPA proposed a rule requiring certain states to replace SIP exemptions for excess emissions during malfunctions with an affirmative defense. Texas was not included in that original proposal since it already had an EPA-approved affirmative defense provision in its SIP. In 2014, as a result of a D.C. Circuit Court decision striking down an affirmative defense in another EPA rule, the EPA revised its 2013 proposal to extend the EPA's proposed findings of inadequacy to states that have affirmative defense provisions, including Texas. The EPA's revised proposal would require Texas to remove or replace its EPA-approved affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. We filed comments on the EPA proposal in November 2014, and in May 2015 the EPA finalized the proposal which requires states to revise their SIPs to eliminate affirmative defense provisions by November 2016. In June 2015, we filed a petition for review in the Fifth Circuit Court challenging certain aspects of the EPA's final rule as they apply to the Texas SIP. The State of Texas and other parties also filed similar petitions in the Fifth Circuit Court. In August 2015, the Fifth Circuit Court transferred the petitions that Luminant and other parties filed to the D.C. Circuit Court, and in October 2015 the petitions were consolidated with the pending petitions challenging the EPA's action in the D.C. Circuit Court. Briefing in the D.C. Circuit Court on the challenges is scheduled to be completed by October 2016.

In June 2014, the Sierra Club filed a petition in the D.C. Circuit Court seeking review of several EPA regulations containing affirmative defenses for malfunctions, including the MATS rule for power plants. In the petition, the Sierra Club contends this affirmative defense is no longer permissible in light of a D.C. Circuit Court decision regarding similar defenses applicable to the cement industry. Luminant filed a motion to intervene in this case. In July 2014, the D.C. Circuit Court ordered the case stayed pending the EPA's consideration of a petition for administrative reconsideration of the regulations at issue. In December 2014, the EPA signed a proposal to make technical corrections to the MATS rule. We filed comments on this proposal in April 2015. Except as set forth above, we cannot predict the timing or outcome of future proceedings related to this petition, the petition for administrative reconsideration that is pending before the EPA or the financial effects of these proceedings, if any.

National Ambient Air Quality Standard for Ozone — In October 2015, the EPA finalized a new eight-hour standard for ozone of 70 parts per billion (ppb), lowering it from the existing 75 ppb. In October 2017, the EPA will designate nonattainment areas for the standard, and states will then have three years to develop an implementation plan for meeting the standard. Based on current levels, the Dallas/Fort Worth area does not meet the standard; however, monitors in East (Tyler-Longview-Marshall) and Central (Waco) Texas, which are closer to our generation units, measure levels below the standard. If our generation units are implicated in ozone exceedances, Texas may pursue additional nitrogen oxide controls to reduce ozone concentrations. While we are not a party to the lawsuit, the EPA ozone standard is being challenged in a proceeding in the D.C. Circuit Court. We cannot predict the outcome of the state ozone attainment implementation planning process or the impact that the standard may have on our results of operations, liquidity or financial condition.

Acid Rain Program— The EPA has promulgated Acid Rain Program rules that require fossil fueled generation plants to have sufficient SO₂ emission allowances and meet certain NO_X emission standards. We believe our generation plants meet these SO₂ allowance requirements and NO_X emission rates.

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Installation of Substantial Emissions Control Equipment — Each of our lignite/coal fueled generation facilities is currently equipped with substantial emissions control equipment as detailed in the table below.

Emissions Control Equipment	Big Brown	Martin Lake	Monticello	Oak Grove	Sandow
Activated carbon injection systems to reduce mercury emissions	Units 1 and 2	Units 1, 2 and 3	Units 1, 2 and 3	Units 1 and 2	Units 4 and 5
Flue gas desulfurization systems designed primarily to reduce SO2 emissions (a)		Units 1, 2 and 3	Unit 3	Units 1 and 2	Units 4 and 5
Selective catalytic reduction systems designed to reduce NOX emissions				Units 1 and 2	Unit 4
Selective non-catalytic reduction systems designed to reduce NOX emissions	Units 1 and 2		Units 1, 2 and 3		Unit 5
Fabric filter systems designed primarily to reduce particulate matter emissions (a)	Units 1 and 2		Units 1 and 2	Units 1 and 2	Unit 5
Electrostatic precipitator systems designed primarily to reduce particulate matter emissions (a)	Units 1 and 2	Units 1, 2 and 3	Units 1, 2 and 3		Unit 4
Fluidized bed combustion process that facilitates control of NOX and SO2					Unit 5

___________

(a) Flue gas desulfurization systems, fabric filter systems and electrostatic precipitator systems also assist in reducing mercury and other emissions.

We believe that we hold all required emissions permits for facilities in operation. If the TCEQ adopts implementation plans that require us to install additional emissions controls, or if the EPA adopts more stringent requirements through any of the number of potential rulemaking activities in which it is or may be engaged, we could incur material capital expenditures, higher operating costs and potential production curtailments, resulting in material effects on our results of operations, liquidity and financial condition.

Water

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 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.

Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. We believe we possess all necessary permits from the TCEQ for these activities at our current facilities. Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities were published by the EPA in 2004. As prescribed in the regulations, we began implementing a monitoring program to determine the future actions that might need to be taken to comply with these regulations. In May 2014, the EPA finalized the Section 316(b) regulations. Although the rule does not mandate a certain control technology, it does require site-specific assessments of technology feasibility on a case-by-case basis at the state level. Compliance with this rule requires assessments and reports six months following implementation of the rule, but allows up to eight full years following promulgation for full compliance. Luminant has received determinations that most of our cooling water lakes are closed-cycle recirculating systems and an approval of a Fisheries Management Program for our non-public lakes. Compliance with the rule is not anticipated to have a material effect on our results of operations, liquidity or financial condition.

Stream Protection Rule — In July 2015, the Office of Surface Mining (OSM) proposed a Stream Protection Rule that represents significant changes to surface mining regulations under the Surface Mining Control and Reclamation Act (SMCRA) program. The rule proposes to prevent or minimize impacts to surface water and groundwater from coal mining. In October 2015, we filed comments on the proposed rule. While we cannot predict the outcome of this rulemaking on our results of operations, liquidity or financial condition, the impacts could be material.

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Radioactive Waste

Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the State of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The State of Texas has agreed to a compact for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by the President in 1998, and the State of Texas has enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal. The first disposal facility in Texas for such purposes began operations in 2012, and we began shipping some forms of waste material to the facility in 2013. We also ship other low-level waste material to a disposal facility outside of Texas. Should existing off-site disposal become unavailable, the low-level waste material can be stored on-site. (See discussion of this and storage of used nuclear fuel under Luminant – Nuclear Generation Operations above.)

Solid Waste, Including Coal Combustion Residuals from Lignite/Coal Fueled Generation

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 believe we are in material compliance with all applicable solid waste rules and regulations. In addition, we have registered solid waste disposal sites and have obtained or applied for permits where required by such regulations.

In October 2015, the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule) became effective. As of December 31, 2015, we have established an estimated $69 million asset retirement obligation related to the CCR Rule for our existing facilities (see Note 21).

In September 2015, the EPA finalized the Effluent Limitation Guideline and Standards for the Steam Electric Power Generating Point Source Category rule targeted at coal-fueled generation units, specifically to the coal combustion residual related wastestreams and practices. It was developed with consideration of the final CCR rule discussed above. The guidelines establish new, stringent numeric limits for arsenic, mercury, selenium and nitrate-nitrites in flue gas desulfurization wastestreams. The rule also establishes "zero discharge" restrictions on some wastestreams, with very few exceptions. Based on our existing practices related to wastewater discharges, we do not believe that these guidelines will cause any material operational, financial or compliance issues.

Environmental Commitment and Capital Expenditures

We are committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce our impact on the environment.

Capital expenditures for our environmental projects totaled $82 million in 2015 and are expected to total approximately $50 million in 2016 for environmental control equipment to comply with regulatory requirements. The total future expenditure for environmental capital will ultimately depend on the evolution of pending or future regulatory requirements, along with the economic viability of our lignite/coal fueled generation facilities in context of those regulations.

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Item 1A.    RISK FACTORS

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 impact on our operations, liquidity, 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, are described below. There may be further risks and uncertainties that are not currently known or that are not currently believed to be material that may adversely affect our business, results of operations, liquidity and/or financial condition in the future.

Our major risks fall primarily into the following categories:

• Risks Related to the Chapter 11 Cases. The Chapter 11 Cases subject us to material expense and a variety of material and adverse impacts on our business, including: a decrease in the number of counterparties that are willing to engage in commodity related hedging transactions with us and a significant increase in the amount of collateral required to engage in any such transactions; a loss of, or a disruption in, the materials and services received from suppliers, contractors and service providers; a loss of wholesale and retail electric customers; difficulties in the retention of employees; management distraction; limitations on our ability to operate our business and to adjust to changing market and industry conditions during the pendency of the Chapter 11 Cases; and litigation and/or claims asserted by creditors and other stakeholders in the Chapter 11 Cases. Since the inception of the Chapter 11 Cases we have incurred fees associated with legal representation, financial advisory and other professional services, along with financing fees in excess of $880 million. Although the Bankruptcy Court has confirmed our Plan of Reorganization, the consummation of the transactions contemplated by the plan are subject to a number of conditions (some of which are out of our control). Accordingly, there is no assurance that such transactions will be consummated or that the Plan of Reorganization will become effective. If those transactions are not consummated and the Plan of Reorganization does not become effective, we will be subject to a more lengthy and costly bankruptcy proceeding.

Risks Related to Our Structure. The distributions that may be paid to us by Oncor are limited due to certain structural and operational ring-fencing measures. Further, distributions declared by Oncor are made by Oncor's independent board of directors subject to the terms of its organizational documents and applicable law.

• Market, Financial and Economic Risks. Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas. Accordingly, our earnings, cash flows and the value of our lignite/coal and nuclear fueled generation assets are dependent in significant part upon the price of natural gas. In recent years natural gas supply has outpaced demand, thereby depressing natural gas prices. In addition, wholesale electricity prices move with ERCOT market heat rates, which could fall if demand for electricity were to decrease or if more efficient generation facilities are built in ERCOT. Accordingly, our earnings, cash flows and the value of our lignite/coal and nuclear fueled generation assets are also dependent in significant part upon market heat rates. Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations. In addition, changes in technology or increased electricity conservation efforts may reduce the value of our assets.

• Regulatory and Legislative Risks. Our regulatory and legislative risks include changes in laws and regulations that govern our operations. In particular, new requirements for control of certain emissions from sources including electricity generation facilities may result in our incurrence of significant additional costs or significant changes to our existing operating practices. In addition, the rates of Oncor's electricity delivery business are subject to regulatory review, and may be reduced below current levels, which could adversely impact Oncor's results of operations, liquidity and financial condition.

• Operational Risks. Our operational risks include the risks inherent in running electricity generation facilities, retail electricity operations and electricity transmission and distribution systems. Failure of our equipment and facilities, information technology failure, fuel or water supply interruptions and adverse weather conditions, among other things, can adversely affect our business. In addition, our retail business is subject to intense competition.

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Risks Related to Chapter 11 Cases

We have filed voluntary petitions for relief under the Bankruptcy Code and are subject to the risks and uncertainties associated with bankruptcy cases.

We have filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. For the duration of the Chapter 11 Cases, our business and operations will be subject to various risks, including but not limited to the following:

• Whether the conditions (including the receipt of required regulatory approvals) to consummate the transactions contemplated by the Plan of Reorganization will be satisfied or waived;

• Increased costs related to the Chapter 11 Cases and related litigation;

• Negative effects and increased costs of a prolonged duration of the Chapter 11 Cases;

• Our ability to maintain or obtain sufficient financing sources for our operations during the pendency of the Chapter 11 Cases or to obtain sufficient exit financing to fund a Chapter 11 plan of reorganization;

• Risks related to our mining reclamation bonding obligations;

• Potential incremental increase in risks related to distributions from Oncor to EFH Corp. or EFIH;

• Potential increased difficulty in retaining and motivating our key employees through the process of reorganization, and potential increased difficulty in attracting new employees, and

• Significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations.

We are also subject to risks and uncertainties with respect to the actions and decisions of creditors, regulators and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and may significantly increase the duration of the Chapter 11 Cases. Because of the risks and uncertainties associated with Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations.

The Plan of Reorganization may not become effective.

While the Plan of Reorganization has been confirmed by the Bankruptcy Court, it may not become effective because it is subject to the satisfaction of certain conditions precedent (some of which are beyond our control). There can be no assurance that such conditions will be satisfied, and therefore, that the Plan of Reorganization will become effective and that the Debtors will emerge from the Chapter 11 Cases as contemplated by such Plan of Reorganization. If the transactions contemplated by the Plan of Reorganization are not completed, it may become necessary to amend the Plan of Reorganization. The terms of any such amendment are uncertain and could result in material additional expense and result in material delays in the Chapter 11 Cases. We no longer have the exclusive right to propose a plan of reorganization in the Chapter 11 Cases. Accordingly, any creditor of the Debtors could propose a plan of reorganization with respect to any one or more of the Debtors. Any new plan of reorganization would require the approval of the Bankruptcy Court and the approval of the required creditors, which could subject us to more lengthy and costly Chapter 11 Cases. In addition, any resulting delay could require us to extend or refinance our DIP Facilities and could adversely impact our liquidity.

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The consummation of the EFH Acquisition contemplated by the Plan of Reorganization is subject to various conditions precedent. If the Merger and Purchase Agreement is terminated, the Purchasers and the Investor Group will effectively have no liability to the Debtors thereunder except for certain expense reimbursement obligations. As a result, there is no certainty that the EFH Acquisition will be completed.

The Merger and Purchase Agreement includes various conditions precedent to consummation of the transactions contemplated thereby. The Purchasers' conditions precedent include, among other things, a condition that certain approvals and rulings be obtained, including from, among others, the PUCT and the IRS, that are necessary to consummate the acquisition and convert a successor to Reorganized EFH into a REIT. In addition, the Merger and Purchase Agreement may be terminated upon certain events, including, among other things, by either party, if certain termination events occur under the Plan Support Agreement, including if the EFH Acquisition is not completed by April 30, 2016, subject to extension to June 30, 2016 or August 31, 2016 under certain conditions. If the Merger and Purchase Agreement is terminated for any reason (including, among other things, due to failure to complete the EFH Acquisition within the timeframes described therein), the Purchasers and the Investor Group will effectively have no liability to the Debtors thereunder. EFH Corp. and EFIH have effectively waived their respective rights under the Merger and Purchase Agreement to seek any legal or equitable remedies (including money damages and specific performance) against the Purchasers or the Investor Group. As a result, even if the applicable regulatory approvals are obtained, there is no certainty that the EFH Acquisition will be completed. If it is not completed for any reason, the Debtors will have no recourse against the Purchasers and the Investor Group except for certain expense reimbursement obligations.

Operating under Chapter 11 may restrict our ability to pursue our strategic and operational initiatives. Moreover, we are subject to various covenants and events of default under our DIP Facilities.

Under Chapter 11, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities or to adapt to changing market or industry conditions. The TCEH Debtors and the EFIH Debtors are subject to various covenants and events of default under their respective DIP Facilities. In general, certain of these covenants limit the Debtors' ability, subject to certain exceptions, to take certain actions, including:

• selling assets outside the normal course of business;

• consolidating, merging, selling or otherwise disposing of all or substantially all of our assets;

• granting liens, and

• financing our operations, investments or other capital needs or engaging in other business activities that may be in our best interest.

If the TCEH Debtors and EFIH Debtors fail to comply with these covenants or an event of default occurs under the DIP Facilities, our liquidity, financial condition or operations may be materially impacted.

We may experience increased levels of employee attrition as a result of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, we may experience increased levels of employee attrition, and our employees likely will face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incent key employees to remain with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material and adverse impact on our financial condition, liquidity and results of operations.

As a result of the Chapter 11 Cases, our historical financial information will not be indicative of our future financial performance.

On the effective date of the Plan of Reorganization, we will cease to hold a direct or indirect interest in assets or liabilities of TCEH or any of TCEH's direct or indirect subsidiaries, and our capital structure will be significantly altered. Under fresh-start accounting rules that will apply to us upon the effective date of the Plan of Reorganization, our assets and liabilities will be adjusted to fair value, which could have a significant impact on our financial statements. Accordingly, our financial condition and results of operations following our emergence from Chapter 11 will not be comparable to the financial condition and results of operations reflected in our historical financial statements. In connection with the Chapter 11 Cases and the development of a Chapter 11 plan, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such charges could be material to our consolidated financial position, liquidity and results of operations.

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There is no assurance regarding the outcome of various appeals related to whether note holders are entitled to certain make-whole or redemption premiums and/or post-petition interest in connection with the treatment of their claims in bankruptcy.

The EFIH Debtors are engaged in litigation regarding whether holders of its outstanding notes are entitled to receive a make-whole or redemption premium in connection with the repayment of such notes, including pursuant to a Chapter 11 plan of reorganization. As of December 31, 2015, the total aggregate amount of make-whole or redemption premiums that would be owed if such alleged claims were allowed claims would be approximately $946 million (of which $432 million relates to the EFIH First Lien Notes, $401 million relates to the EFIH Second Lien Notes and $113 million relates to the EFIH PIK Notes). The EFIH Debtors have received orders from the Bankruptcy Court disallowing such claims, but these orders are subject to, and are in the process of, being appealed by holders of such claims. See Note 14 to the Financial Statements for a more detailed discussion regarding these claims.

EFH Corp. may become engaged in litigation or similar adversarial proceedings regarding whether holders of its outstanding notes are entitled to receive a make-whole or redemption premium in connection with the repayment of such notes if the Plan of Reorganization does not become effective. As of December 31, 2015, the total aggregate amount of make-whole or redemption premiums that would be owed if such alleged claims were allowed would be approximately $208 million.

Moreover, creditors have made and may continue to make additional claims in the Chapter 11 Cases in connection with the repayments or settlements of their pre-petition debt such as indemnification claims or for the payment of fees and expenses incurred in connection with litigating such claims.

In addition, creditors have asserted and may continue to assert claims for post-petition interest, including default interest, on their outstanding notes in connection with the repayment of such notes, including pursuant to a Chapter 11 plan of reorganization. Such amounts would be material, particularly if such post-petition interest were required to be paid at the contract rate as opposed to the federal judgment rate.

We cannot predict the ultimate outcome of any of these matters.

The DIP Facilities may be insufficient to fund our cash requirements through our emergence from bankruptcy. In addition, our independent auditor's report on our financial statements raises substantial doubt about our ability to continue as a going concern given the Chapter 11 Cases.

For the duration of the Chapter 11 Cases, we will be subject to various risks, including but not limited to (i) the inability to maintain or obtain sufficient financing sources for operations or to fund the Plan of Reorganization and meet future obligations, and (ii) increased legal and other professional costs associated with the Chapter 11 Cases and our reorganization.

If the transactions contemplated by the Plan of Reorganization are not completed and the effective date of the Plan of Reorganization does not occur prior to the maturity of the DIP Facilities, we will likely need to refinance our existing DIP Facilities. We may not be able to obtain some or all of any such financing on acceptable terms or at all.

In its report on our financial statements included in this Annual Report on Form 10-K, our independent public accounting firm states that the uncertainties inherent in the bankruptcy process raise substantial doubt about our ability to continue as a going concern.

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We may not be able to obtain exit financing to repay the DIP Facilities or, if we are able to obtain such exit financing, the agreements governing such exit financing may significantly restrict our financing and operations flexibility after emerging from bankruptcy.

It is expected that the DIP Facilities will be repaid using, in whole or in part, the proceeds from borrowings under exit financings. Our ability to obtain such exit financings will depend on, among other things, the timing and outcome of various ongoing matters in the Chapter 11 Cases, our business, operations and financial condition, and market conditions. We have not yet received any commitment with respect to any exit facilities, and there can be no assurance that we will be able to obtain such exit facilities on reasonable economic terms, or at all. If we cannot secure exit financing, we may not be able to emerge from bankruptcy and may not be able to repay the DIP Facilities at their respective maturities. Any exit financing that we are able to secure may include a number of significant restrictive covenants which could impair our financing and operational flexibility and make it difficult for us to react to market conditions and satisfy our ongoing capital needs and unanticipated cash requirements. In addition, such exit facilities may require us to periodically meet various financial ratios and tests. These financial covenants and tests could limit our ability to react to market conditions or satisfy extraordinary capital needs and could otherwise restrict our financing and operations.

As a result of the Chapter 11 Cases, net operating losses and other tax attributes are not expected to be available upon emergence from the Chapter 11 Cases.

Certain tax attributes, such as net operating loss carry-forwards and certain tax credits, are expected to be utilized in connection with the Chapter 11 Cases. Under the Internal Revenue Code, tax attributes are reduced to the extent discharge of indebtedness income is excluded from gross income arising from a Chapter 11 case. If any attributes are still available after the application of Section 108, such attributes may be limited or lost in the event EFH Corp. or any of its subsidiaries experience an ownership change as defined under the Internal Revenue Code. In addition, tax attributes may be utilized in a transaction such as a sale or transfer of assets that could result in a significant tax liability for EFH Corp. and its subsidiaries. As a result of the foregoing rules, any pre-emergence net operating losses and certain tax credits are not expected to be available to EFH Corp. and its subsidiaries to reduce taxable income for tax periods beginning after emergence from Chapter 11.

Risks Related to Our Structure

EFH Corp. and EFIH have a very limited ability to control activities at Oncor due to structural and operational ring-fencing measures.

EFH Corp. and EFIH depend upon Oncor for a significant amount of their cash flows and rely on such cash flows in order to satisfy their obligations. However, EFH Corp. and EFIH have a very limited ability to control the activities of Oncor. As part of the ring-fencing measures implemented by EFH Corp. and Oncor, including certain measures required by the PUCT's Order on Rehearing in Docket No. 34077, a majority of the members of Oncor's board of directors are required to meet the New York Stock Exchange requirements for independence in all material respects, and the unanimous, or majority, consent of such directors is required for Oncor to take certain actions. In addition, any new independent directors are required to be appointed by the nominating committee of Oncor Holdings' board of directors, a majority of whose members are independent directors. No member of EFH Corp.'s or EFIH's management is a member of Oncor's board of directors. Under Oncor Holdings' and Oncor's organizational documents, EFH Corp. has limited indirect consent rights with respect to the activities of Oncor, including (i) new issuances of equity securities by Oncor, (ii) material transactions with third parties involving Oncor outside of the ordinary course of business, (iii) actions that cause Oncor's assets to be subject to an increased level of jurisdiction of the FERC, (iv) any changes to the state of formation of Oncor, (v) material changes to accounting methods not required by US GAAP, and (vi) actions that fail to enforce certain tax sharing obligations between Oncor and EFH Corp. In addition, Oncor's organizational agreements contain restrictions on Oncor's ability to make distributions to its members, including indirectly to EFH Corp. or EFIH.

Additionally, the restrictive measures required by the PUCT's Order on Rehearing in Docket No. 34077, include, among other things:

• Oncor not being restricted from incurring its own debt;

• Oncor not guaranteeing or pledging any of its assets to secure the debt of any member of the Texas Holdings Group, and

• restrictions on distributions by Oncor, and the right of the independent members of Oncor's board of directors and the largest non-majority member of Oncor to block the payment of distributions to Oncor Holdings (i.e., such distributions not being available to EFH Corp. under certain circumstances).

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Oncor may or may not make any distributions to EFH Corp. or EFIH.

EFH Corp. and Oncor have implemented certain structural and operational ring-fencing measures, including certain measures required by the PUCT's Order on Rehearing in Docket No. 34077, that were based on principles articulated by rating agencies and commitments made by Texas Holdings and Oncor to the PUCT and the FERC to further enhance Oncor's credit quality. These measures were put in place to mitigate Oncor's credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in a bankruptcy of one or more of those entities.

As part of the ring-fencing measures, a majority of the members of the board of directors of Oncor are required to be, and are, independent from EFH Corp. and EFIH. Any new independent directors of Oncor are required to be appointed by the nominating committee of Oncor Holdings, which is required to be, and is, comprised of a majority of directors that are independent from EFH Corp. and EFIH. The organizational documents of Oncor give these independent directors, acting by majority vote, and, during certain periods, any director designated by Texas Transmission, the express right to prevent distributions from Oncor if they determine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements. The Chapter 11 Cases could result in Oncor limiting or suspending such dividends to EFIH during the pendency of such filing. Accordingly, there can be no assurance that Oncor will make any distributions to EFH Corp. or EFIH.

In addition, Oncor's organizational documents prohibit Oncor from making any distribution to its owners, including EFH Corp. and EFIH, so long as and to the extent that such distribution would cause Oncor's regulatory capital structure to exceed the debt-to-equity ratio established by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. Under the terms of a Federal and State Income Tax Allocation Agreement, Oncor makes tax payments to EFH Corp. (bypassing EFIH) based on its share of an amount calculated to approximate the amount of taxes Oncor would have paid to the IRS if it was a stand-alone taxpayer.

Market, Financial and Economic Risks

TCEH's revenues and results of operations generally are negatively impacted by decreases in market prices for electricity, natural gas prices and/or market heat rates.

TCEH is not guaranteed any rate of return on capital investments in its businesses. We market electricity, including electricity from our own generation facilities and generation contracted from third parties, as part of our wholesale operations. TCEH's results of operations depend in large part upon wholesale market prices for electricity, natural gas, uranium, coal, fuel oil and transportation in its regional market and other competitive markets and upon prevailing retail electricity rates, which may be impacted by, among other things, actions of regulatory authorities. Market prices may fluctuate substantially over relatively short periods of time. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, at times, there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets.

Some of the fuel for our generation facilities is purchased under short-term contracts. Prices of fuel (including diesel, natural gas, coal and nuclear fuel) may also be volatile, and the price we can obtain for electricity sales may not change at the same rate as changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting obligations.

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Volatility in market prices for fuel and electricity may result from the following:

• volatility in natural gas prices;

• volatility in ERCOT market heat rates;

• volatility in coal and rail transportation prices;

• severe or unexpected weather conditions, including drought and limitations on access to water;

• seasonality;

• changes in electricity and fuel usage;

• illiquidity in the wholesale electricity or other commodity markets;

• transmission or transportation constraints, inoperability or inefficiencies;

• availability of competitively-priced alternative energy sources or storage;

• changes in market structure;

• changes in supply and demand for energy commodities, including nuclear fuel and related enrichment and conversion services;

• changes in the manner in which we operate our facilities, including curtailed operation due to market pricing, environmental, safety or other factors;

• changes in generation efficiency;

• outages or otherwise reduced output from our generation facilities or those of our competitors;

• changes in the credit risk or payment practices of market participants;

• changes in production and storage levels of natural gas, lignite, coal, crude oil, diesel and other refined products;

• natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and

• federal, state and local energy, environmental and other regulation and legislation.

All of our generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas because marginal electricity demand is generally supplied by natural gas fueled generation facilities. Accordingly, our earnings, cash flows and the value of our nuclear and lignite/coal fueled generation assets, which provided a substantial portion of our supply volumes in 2015, are dependent in significant part upon the price of natural gas. Natural gas prices have generally trended downward since mid-2008 (from $11.12 per MMBtu in mid-2008 to $2.66 per MMBtu for the average settled price for the year ended December 31, 2015). In recent years natural gas supply has outpaced demand as a result of development and expansion of hydraulic fracturing in natural gas extraction. Many industry experts expect this supply/demand imbalance to persist for a number of years, thereby depressing natural gas prices for a long-term period. As a result, our generation assets could materially decrease in profitability and value unless natural gas prices rebound materially.

Wholesale electricity prices also move with ERCOT market heat rates, which could fall if demand for electricity were to decrease or if more efficient generation facilities are built in ERCOT. Accordingly, our earnings, cash flows and the value of our nuclear and lignite/coal fueled generation assets are also dependent in significant part upon market heat rates. As a result, our nuclear and lignite/coal fueled generation assets could significantly decrease in profitability and value if ERCOT market heat rates decline.

A sustained decrease in the profitability and/or value of our generation units could result in further impairments of such assets and ultimately could result in the retirement or mothballing of certain generation units.

Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations.

We cannot fully hedge the risk associated with changes in commodity prices, most notably electricity and natural gas prices, because of the expected useful life of our generation assets and the size of our position relative to market liquidity. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations, liquidity and financial position, either favorably or unfavorably. Taking together forward wholesale and retail electricity sales with all hedging positions, at December 31, 2015, we had effectively hedged an estimated 94% and 18% of the price exposure, on a natural gas equivalent basis, related to our expected generation output for 2016 and 2017, respectively (assuming an approximate 8.5 market heat rate).

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To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, diesel fuel, uranium and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment of risk management procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place may not always function as planned and cannot eliminate all the risks associated with these activities. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, consumer behavior, market constraints or other factors could cause us to purchase electricity to meet unexpected demand in periods of high wholesale market prices or resell excess electricity into the wholesale market in periods of low prices. As a result of these and other factors, we cannot precisely predict the impact that risk management decisions may have on our businesses, results of operations, liquidity or financial position.

With the tightening of credit markets that began in 2008 and the expansion of regulatory oversight through various financial reforms, there has been some decline in the number of market participants in the wholesale energy commodities markets, resulting in less liquidity, particularly in the ERCOT electricity market. Participation by financial institutions and other intermediaries (including investment banks) has particularly declined. Extended declines in market liquidity could materially affect our ability to hedge our financial exposure to desired levels. In addition, our financial condition and the Chapter 11 Cases have significantly limited the number of counterparties that will enter into commodity hedging transactions with us on attractive terms.

To the extent we engage in hedging and risk management activities, we are exposed to the risk that counterparties that owe us money, energy or other commodities as a result of these activities will not perform their obligations. Should the counterparties to these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. In such event, we could incur losses or forgo expected gains in addition to amounts, if any, already paid to the counterparties. This risk increased in the coal industry during 2015 when several coal producers filed for Chapter 11 bankruptcy protection predominately due to lower demand and increased regulatory pressure. We had no material exposure to the coal producers that filed bankruptcy during 2015. ERCOT market participants are also exposed to risks that another ERCOT market participant may default on its obligations to pay ERCOT for electricity taken, in which case such costs, to the extent not offset by posted security and other protections available to ERCOT, may be allocated to various non-defaulting ERCOT market participants, including us.

Changes in technology or increased electricity conservation efforts may reduce the value of our generation facilities and/or Oncor's electricity delivery facilities and may otherwise significantly impact our businesses.

Technological advances have improved, and are likely to continue to improve, existing and alternative technologies to produce or store electricity, including gas turbines, wind turbines, fuel cells, microturbines, photovoltaic (solar) cells, batteries and concentrated solar thermal devices. Such technological advances have reduced, and are expected to continue to reduce, the costs of electricity production or storage from these technologies to a level that will enable these technologies to compete effectively with traditional generation facilities. Consequently, the profitability and market value of our generation assets could be significantly reduced as a result of these advances. In addition, changes in technology have altered, and are expected to continue to alter, the channels through which retail customers buy electricity (i.e., self-generation facilities). To the extent self-generation facilities become a more cost-effective option for ERCOT customers, our revenues, liquidity and results of operations could be materially reduced.

Technological advances in demand-side management and increased conservation efforts have resulted, and are expected to continue to result, in a decrease in electricity demand. A significant decrease in electricity demand in ERCOT as a result of such efforts would significantly reduce the value of our generation assets and electricity delivery facilities. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption. 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, liquidity and results of operations. Furthermore, we may incur increased capital expenditures if we are required to increase investment in conservation measures.

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Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets and/or during times when there are significant changes in commodity prices. The inability to access liquidity, particularly on favorable terms, could materially affect our results of operations, liquidity and financial condition. We cannot be certain that the DIP Facilities will ultimately be adequate to cover all of our liquidity needs for the entirety of the Chapter 11 Cases.

Our businesses are capital intensive. In general, we rely on access to financial markets and credit facilities as a significant source of liquidity for our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows. The inability to raise capital or access credit facilities, particularly on favorable terms, could adversely impact our liquidity and our ability to meet our obligations or sustain and grow our businesses and could increase capital costs. Our access to the financial markets and credit facilities could be adversely impacted by various factors, such as:

• our Chapter 11 Cases and the related costs;

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

• economic weakness in the ERCOT or general US market;

• changes in interest rates;

• a deterioration, or perceived deterioration, of EFH Corp.'s (and/or its subsidiaries') creditworthiness or enterprise value;

• a reduction in EFH Corp.'s or its applicable subsidiaries' credit ratings;

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

• volatility in commodity prices that increases credit requirements;

• a material breakdown in our risk management procedures, and

• the occurrence of changes in our businesses that restrict our ability to access credit facilities.

In the event that the governmental agencies that regulate the activities of our businesses determine that the creditworthiness of any such business is inadequate to support our activities, such agencies could require us to provide additional cash or letter of credit collateral in substantial amounts to qualify to do business.

Further, a lack of available liquidity could adversely impact the evaluation of our creditworthiness by counterparties and rating agencies. In particular, such concerns by existing and potential counterparties could significantly limit TCEH's wholesale markets activities, including any future hedging activities.

We cannot be sure that the DIP Facilities will ultimately be adequate to cover all of our liquidity needs for the entirety of the Chapter 11 Cases, especially if the Plan of Reorganization does not become effective and we are subjected to a more lengthy bankruptcy proceeding. Additionally, the TCEH Debtors and EFIH Debtors, respectively, are subject to various covenants and events of default under their respective DIP Facilities. If we fail to comply with these covenants or an event of default occurs under the DIP Facilities, our liquidity, financial condition or operations may be materially impacted.

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Regulatory and Legislative Risks

Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the future impact, our businesses and/or results of operations, liquidity and financial condition.

Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in the generation and sale of electricity. We will need to continually adapt to these changes.

Our businesses are subject to changes in state and federal laws (including PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act, the Energy Policy Act of 2005 and the Dodd-Frank Wall Street Reform and Consumer Protection Act), changing governmental policy and regulatory actions (including those of the PUCT, the NERC, the TRE, the RCT, the TCEQ, the FERC, the MSHA, the EPA, the NRC and the CFTC) and the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, construction and operation of transmission facilities, development, operation and reclamation of lignite mines, acquisition, disposal, depreciation and amortization of regulated assets and facilities, recovery of costs and investments, decommissioning costs, return on invested capital for regulated businesses, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT. Changes in, revisions to, or reinterpretations of existing laws and regulations may have a material effect on our businesses.

The Texas Legislature meets every two years. The next regular legislative session is scheduled to begin in January 2017; 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 affect our businesses, including our results of operations, liquidity or financial condition.

Our cost of compliance with existing and new environmental laws could materially affect our results of operations, liquidity and financial condition.

We are subject to extensive environmental regulation by governmental authorities, including the EPA and the TCEQ. In operating our facilities, we are required to comply with numerous environmental laws and regulations and to obtain numerous governmental permits. We may incur significant additional costs beyond those currently contemplated to comply with these requirements. If we fail to comply with these requirements, we could be subject to civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements (see Note 14 to the Financial Statements).

The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources including electricity generation facilities. It is also currently considering several other regulatory actions, as well as contemplating future additional regulatory actions, in each case that may affect our generation facilities or our ability to cost-effectively develop new generation facilities. There is no assurance that the currently-installed emissions control equipment at our lignite/coal fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Some of the recent regulatory actions and proposed actions, such as the EPA's Regional Haze FIP, CSAPR and MATS, could require us to install significant additional control equipment, resulting in material costs of compliance for our generation units, including capital expenditures, higher operating and fuel costs and potential production curtailments if the rules take effect. These costs could result in material effects on our results of operations, liquidity and financial condition.

We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an approval is retroactively disallowed, the operation of our generation facilities could be stopped, curtailed or modified or become subject to additional costs.

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In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that we have acquired, leased or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or fail to meet its indemnification obligations to us.

Our results of operations, liquidity and financial condition may be materially affected if new federal and/or state legislation or regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions.

There is a concern nationally and internationally about global climate change and how greenhouse gas (GHG) emissions, such as carbon dioxide (CO₂), contribute to global climate change. Over the last few years, proposals have been debated in the US Congress or discussed by the Obama Administration that were intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG emissions, incentives for the development of low-carbon technology and federal renewable portfolio standards. In addition, a number of federal court cases have been filed in recent years asserting damage claims related to GHG emissions, and the results in those proceedings could establish adverse precedent that might apply to companies (including us) that produce GHG emissions. For more detailed discussion of recent global climate change legislation see Items 1 and 2, Business and Properties – Environmental Regulations and Related Considerations – Global Climate Change. Our results of operations, liquidity and financial condition may be materially affected if new federal and/or state legislation or regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions.

Luminant's mining permits are subject to RCT review.

The RCT reviews on an ongoing basis whether Luminant is compliant with RCT rules and regulations and whether it has met all of the requirements of its mining permits. Any revocation of a mining permit would mean that Luminant would no longer be allowed to mine lignite at the applicable mine to serve its generation facilities. Such event would have a material effect on our results of operations, liquidity and financial condition.

In June 2014, the RCT agreed to accept a collateral bond from TCEH of up to $1.1 billion, as a substitute for its self-bond, to secure mining land reclamation obligations. The collateral bond was a $1.1 billion carve-out from the super-priority liens under the TCEH DIP Facility that enables the RCT to be paid before the TCEH DIP Facility lenders in the event such collateral bond was called. There can be no assurance that the RCT will continue to accept this form of collateral bond throughout the pendency of the Chapter 11 Cases. If we were required to secure our mining reclamation with cash or a letter of credit, our liquidity and financial condition would be materially and adversely impacted.

A condition to the completion of the transactions contemplated by the Plan of Reorganization is that the RCT approve Luminant's post-emergence bonding application. If Luminant were required to secure its post-emergence reclamation obligations with cash or a letter of credit, its liquidity and financial condition would be materially and adversely affected. There can be no assurance that the RCT will approve Luminant's proposed post-emergence bonding application.

Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputation damage, and have a material effect on our results of operations, and the litigation environment in which we operate poses a significant risk to our businesses.

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. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these evaluations and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material effect on our results of operations. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment poses a significant business risk.

We are involved in the ordinary course of business in permit applications and renewals, and we are exposed to the risk that certain of our operating permit applications may not be granted or that certain of our operating permits may not be renewed on satisfactory terms. Failure to obtain and maintain the necessary permits to conduct our businesses could have a material effect on our results of operations, liquidity and financial condition.

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We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. See Note 14 to the Financial Statements, Litigation Related to EPA Reviews. While we cannot predict the outcome of any regulatory investigation or administrative proceeding, any such regulatory investigation or administrative proceeding could result in us incurring material penalties and/or other costs and have a material effect on our results of operations, liquidity and financial condition.

Our collateral requirements for hedging arrangements could be materially impacted if the remaining rules implementing the Financial Reform Act broaden the scope of the Act's provisions regarding the regulation of over-the-counter financial derivatives, making certain provisions applicable to end-users like us.

In July 2010, the US Congress enacted financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act). While the legislation is broad and detailed, a few key rulemaking decisions remain to be made by federal governmental agencies to fully implement the Financial Reform Act.

In November 2015 and January 2016, the prudential regulators and the CFTC, respectively, published final rules and interim final rules on margin requirements. The margin rules do not directly apply to non-financial end users. However, transaction costs may increase and liquidity may decrease as operating costs for registered entities increases under the margin rules. The rule has a phased in approach starting in September 2016. In addition, in December 2013, the CFTC published its new proposed Position Limit Rule (PLR). The PLR provides for specific position limits related to futures and swap contracts that we utilize in our hedging activities. The proposed PLR will require that we comply with the portion of the PLR applicable to these contracts, which will result in increased monitoring and reporting requirements and can also impact the types of contracts that we utilize as hedging instruments in our operations.

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

The rates charged by Oncor 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. Oncor's rates are regulated based on an analysis of Oncor's 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 Oncor's costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure that Oncor's 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 Oncor's costs, including regulatory assets reported on Oncor's balance sheet, and the return on invested capital allowed by the PUCT. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events and Items Influencing Future Performance – Oncor Matters with the PUCT for discussion of recent and pending rate-related filings with the PUCT.

The REP certification of our retail operation is subject to PUCT review.

The PUCT may at any time initiate an investigation into whether our retail operation complies with certain PUCT rules and whether we have met all of the requirements for REP certification, including financial requirements. In addition, as a result of the Chapter 11 Cases, the PUCT may initiate additional reviews of our retail operation, including with respect to its creditworthiness. Any removal or revocation of a REP certification would mean that we would no longer be allowed to provide electricity service to retail customers. Such decertification could have a material effect on our results of operations, liquidity and financial condition.

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Operational Risks

We may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear generation facility.

The ownership and operation of a nuclear generation facility involves certain risks. These risks include:

• unscheduled outages or unexpected costs due to equipment, mechanical, structural, cyber security or other problems;

• inadequacy or lapses in maintenance protocols;

• the impairment of reactor operation and safety systems due to human error or force majeure;

• the costs of storage, handling and disposal of nuclear materials, including availability of storage space;

• the costs of procuring nuclear fuel;

• terrorist or cyber security attacks and the cost to protect against any such attack;

• the impact of a natural disaster;

• limitations on the amounts and types of insurance coverage commercially available, and

• uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives.

The prolonged unavailability of Comanche Peak could materially affect our financial condition and results of operations. The following are among the more significant of these risks:

• Operational Risk — Operations at any nuclear generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at Comanche Peak.

• Regulatory Risk — The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, the NRC operating licenses for Comanche Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively. In addition, as a result of the Bankruptcy Filing, the NRC may initiate additional reviews of our operations at Comanche Peak, including with respect to our ability to fund our operations in compliance with our operating license. Changes in regulations by the NRC, including potential regulation as a result of the NRC's ongoing analysis and response to the effects of the natural disaster on nuclear generation facilities in Japan in 2010, could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

• Nuclear Accident Risk — Although the safety record of Comanche Peak and other nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred both in the US and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impact and property damage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage, and could ultimately result in the suspension or termination of electricity generation from Comanche Peak.

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

The operation and maintenance of electricity generation and delivery facilities involves many risks, including, as applicable, start-up risks, breakdown or failure of facilities, operator error, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source or the impact of unusual or adverse weather conditions or other natural events, or terrorist attacks, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. In particular, older generating equipment and 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 (i) increased starting and stopping of generation equipment due to the volatility of the competitive generation market and the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of all our generation facilities, (ii) any unexpected failure to generate electricity, including failure caused by equipment breakdown or forced outage, (iii) damage to facilities due to storms, natural disasters, wars, terrorist or cyber security acts and other catastrophic events and (iv) the passage of time and normal wear and tear. 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 and/or losses and write downs of our investment in the project or improvement.

We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist or cyber security attacks). The unexpected requirement of large capital expenditures could materially affect our results of operations, liquidity and financial condition.

Our employees, contractors, customers and the general public may be exposed to a risk of injury due to the nature of our operations.

Employees and contractors throughout our organization work in, and customers and the general public may be exposed to, potentially dangerous environments near our operations. As a result, employees, contractors, customers and the general public are at risk for serious injury, including loss of life. Significant risks include nuclear accidents, dam failure, gas explosions, mine area collapses, pole strikes and other cases.

Our results of operations, liquidity and financial condition may be materially affected by the effects of extreme weather conditions.

Our results of operations, liquidity and financial condition may be materially affected by weather conditions and may fluctuate substantially on a seasonal basis as the weather changes. In addition, we could be subject to the effects of extreme weather. Extreme weather conditions could stress our transmission and distribution system or our generation facilities resulting in outages, increased maintenance and capital expenditures. Extreme weather events, including sustained cold or hot temperatures, hurricanes, storms or other natural disasters, could be destructive and result in casualty losses that are not ultimately offset by insurance proceeds or in increased capital expenditures or costs, including supply chain costs.

Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, an extreme weather event might affect the availability of generation and transmission capacity, limiting our ability to source or deliver electricity where it is needed or limit our ability to source fuel for our plants (including due to damage to rail or natural gas pipeline infrastructure). Additionally, extreme weather may result in unexpected increases in customer load, requiring our retail operation to procure additional electricity supplies at wholesale prices in excess of customer sales prices for electricity. These conditions, which cannot be reliably predicted, could have an adverse consequence by requiring us to seek additional sources of electricity when wholesale market prices are high or to sell excess electricity when market prices are low.

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Attacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities and reputation damage and disrupt business operations, which could have a material effect on our results of operations, liquidity and financial condition.

Much of our information technology infrastructure is connected (directly or indirectly) to the Internet. There have been numerous attacks on government and industry information technology systems through the Internet that have resulted in material operational, reputation and/or financial costs. While we have controls in place designed to protect our infrastructure and have not had any significant breaches, 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 generation and transmission and distribution assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could adversely affect our reputation, expose the company to material legal/regulatory claims, impair our ability to execute on business strategies and/or materially affect our results of operations, liquidity and financial condition.

As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its Critical Infrastructure Protection reliability standards and has established standards for assets 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.

Further, our retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, driver license numbers, social security numbers and bank account information. Our retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. If a significant breach occurred, the reputation of our retail business may be adversely affected, customer confidence may be diminished, or our retail business may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and our results of operations, liquidity and financial condition.

Our retail operation (TXU Energy) may lose a significant number of customers due to competitive marketing activity by other retail electric providers.

Our retail operation faces competition for customers. Competitors may offer lower prices and other incentives, or attempt to use the Chapter 11 Cases against us, which, despite the business' long-standing relationship with customers, may attract customers away from us. We operate in a very competitive retail market, as is reflected in a 16% decline in customers (based on meters) served over the last five years.

In some retail electricity markets, our principal competitor may be the incumbent REP. The incumbent REP has the advantage of long-standing relationships with its customers, including well-known brand recognition.

In addition to competition from the incumbent REP, we may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with us. Some of these competitors or potential competitors may be larger or better capitalized than we are. If there is inadequate potential margin in these retail electricity markets, it may not be profitable for us to compete in these markets.

Our retail operations rely on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, our customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material negative impact on the business and results of operations.

Our retail operations depend on transmission and distribution facilities owned and operated by unaffiliated utilities, as well as Oncor's facilities, to deliver the electricity we sell to our customers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered, and we may have to forgo sales or buy more expensive wholesale electricity than is available in the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower profits. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer satisfaction with our service.

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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, liquidity and financial condition.

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

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 current personnel or in hiring or retaining qualified personnel in the future. Our failure to attract new personnel or retain existing personnel could have a material effect on our businesses.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 3. LEGAL PROCEEDINGS

See Note 14 to the Financial Statements for discussion of litigation, including matters related to our generation facilities, make-whole claims and EPA reviews. Also see Items 1 and 2, Business and Properties – Environmental Regulations and Related Considerations – Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions for discussion of litigation regarding the CSAPR and the Texas State Implementation Plan as well as certain other environmental regulations.

Item 4. MINE SAFETY DISCLOSURES

We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RCT and Office of Surface Mining. The MSHA inspects US mines, including ours, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders and proposed assessments are provided in Exhibit 95(a) to this annual report on Form 10-K.

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PART II.

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

EFH Corp.'s common stock is privately held and has no established public trading market.

See Note 15 to the Financial Statements for discussion of the restrictions on EFH Corp.'s ability to pay dividends.

The number of holders of EFH Corp.'s common stock at February 29, 2016 totaled 61.

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Item 6. SELECTED FINANCIAL DATA

EFH CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION

SELECTED CONSOLIDATED FINANCIAL DATA

(millions of dollars, except ratios)

	Year Ended December 31,
	2015			2014			2013			2012			2011
Operating revenues	$	5,370		$	5,978		$	5,899		$	5,636		$	7,040
Impairment of goodwill	$	(2,200	)	$	(1,600	)	$	(1,000	)	$	(1,200	)	$	—
Impairment of long-lived assets	$	(2,541	)	$	(4,670	)	$	(140	)	$	—		$	—
Net loss	$	(5,342	)	$	(6,406	)	$	(2,325	)	$	(3,360	)	$	(1,913	)
Net loss attributable to noncontrolling interests	$	—		$	—		$	107		$	—		$	—
Net loss attributable to EFH Corp.	$	(5,342	)	$	(6,406	)	$	(2,218	)	$	(3,360	)	$	(1,913	)
Ratio of earnings to fixed charges (a)	—			—			—			—			—
Cash provided by (used in) operating activities	$	3		$	404		$	(503	)	$	(818	)	$	841
Cash provided by (used in) financing activities	$	(552	)	$	2,257		$	(196	)	$	3,373		$	(1,014	)
Cash provided by (used in) investing activities	$	(593	)	$	(450	)	$	3		$	(1,468	)	$	(535	)
Capital expenditures, including nuclear fuel	$	(467	)	$	(463	)	$	(617	)	$	(877	)	$	(684	)
	At December 31,
	2015			2014			2013			2012			2011
Total assets	$	23,330		$	29,248		$	36,446		$	40,970		$	44,077
Property, plant & equipment — net	$	9,430		$	12,397		$	17,791		$	18,705		$	19,427
Goodwill and intangible assets	$	1,318		$	3,667		$	5,631		$	6,707		$	7,997
Investment in unconsolidated subsidiary (Note 4 to the Financial Statements)	$	6,064		$	6,058		$	5,959		$	5,850		$	5,720
Capitalization
Borrowings under debtor-in-possession credit facilities (b)	$	6,825		$	6,825		$	—		$	—		$	—
Debt, including capital leases (c)	60			128			34,150			37,815			35,360
Pre-petition notes, loans and other debt reported as liabilities subject to compromise (d)	35,560			35,857			—			—			—
EFH Corp. common stock equity	(25,061		)	(19,723		)	(13,256		)	(11,025		)	(7,852		)
Noncontrolling interests in subsidiaries	—			—			1			102			95
Total capitalization	$	17,384		$	23,087		$	20,895		$	26,892		$	27,603
Capitalization ratios
Borrowings under debtor-in-possession credit facilities (b)	39.3		%	29.6		%	—		%	—		%	—		%
Debt, including capital leases (c)	0.3		%	0.5		%	163.4		%	140.6		%	128.1		%
Pre-petition notes, loans and other debt reported as liabilities subject to compromise (d)	204.6		%	155.3		%	—		%	—		%	—		%
EFH Corp. common stock equity	(144.2		)%	(85.4		)%	(63.4		)%	(41.0		)%	(28.4		)%
Noncontrolling interests in subsidiaries	—		%	—		%	—		%	0.4		%	0.3		%
Total	100.0		%	100.0		%	100.0		%	100.0		%	100.0		%
Borrowings under credit and other facilities	$	—		$	—		$	2,054		$	2,136		$	774

___________

(a) Fixed charges exceeded earnings (see Exhibit 12(a)) by $7.024 billion, $9.172 billion, $3.718 billion, $4.715 billion and $3.217 billion for the years ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively.

(b) Borrowings under debtor-in-possession credit facilities are classified as due currently as of December 31, 2015 and as noncurrent as of December 31, 2014.

(c) For all periods presented, excludes amounts with contractual maturity dates in the following twelve months.

(d) For the years ended December 31, 2015 and 2014, includes both unsecured and under secured obligations incurred prior to the Petition Date, but excludes pre-petition obligations that are fully secured and other obligations that are allowed to be paid as ordered by the Bankruptcy Court. For the year ended December 31, 2014, excludes $733 million of deferred debt issuance and extension costs.

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Note: See Note 1 to the Financial Statements Basis of Presentation, Including Application of Bankruptcy Accounting. Results for 2015 and 2014 were significantly impacted by impairment of long-lived assets and intangible assets (see Notes 5 and 9). Results for 2012 through 2015 were significantly impacted by goodwill impairment charges as discussed in Note 5 to the Financial Statements. Results for 2011 were significantly impacted by an impairment charge related to emissions allowance intangible assets as discussed in Note 5 to the Financial Statements.

Quarterly Information (Unaudited)

Results of operations by quarter are summarized below. In our opinion, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily indicative of a full year's operations because of seasonal and other factors. All amounts are in millions of dollars and may not add to full year amounts due to rounding.

	First Quarter (a)			Second Quarter			Third Quarter (a)			Fourth Quarter (a)
2015:
Operating revenues	$	1,272		$	1,256		$	1,737		$	1,105
Net loss attributable to EFH Corp.	$	(1,527	)	$	(212	)	$	(1,460	)	$	(2,143	)

	First Quarter			Second Quarter			Third Quarter		Fourth Quarter (a)
2014:
Operating revenues	$	1,517		$	1,406		$	1,807	$	1,248
Net income (loss) attributable to EFH Corp.	$	(609	)	$	(774	)	$	49	$	(5,072	)

___________

(a) Net loss reflects goodwill and other intangible asset impairment charges of $2.282 billion and $1.863 billion in 2015 and 2014, respectively (see Note 5 to the Financial Statements). Additionally, net loss reflects impairment of long-lived assets of $2.541 billion and $4.670 billion in 2015 and 2014, respectively (see Note 9 to the Financial Statements).

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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 years ended December 31, 2015, 2014 and 2013 should be read in conjunction with Selected Consolidated Financial Data and our audited consolidated financial statements and the notes to those statements. Comparisons of year-over-year results are impacted by the effects of the Bankruptcy Filing and the application of Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, Reorganizations.

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

Business

EFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through its TCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management activities and retail electricity operations. TCEH is a wholly owned subsidiary of EFCH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Oncor Holdings, a holding company that holds an approximately 80% equity interest in Oncor, is a wholly owned subsidiary of EFIH, which is a holding company and a wholly owned subsidiary of EFH Corp.

Various ring-fencing measures have been taken to enhance the credit quality of Oncor. See Notes 1 and 4 to the Financial Statements for a discussion of the reporting of our investment in Oncor (and Oncor Holdings) as an equity method investment and a description of the ring-fencing measures implemented with respect to Oncor. These measures were put in place to mitigate Oncor's exposure to the Texas Holdings Group with the intent to minimize the risk that a court would order any of the assets and liabilities of the Oncor Ring-Fenced Entities to be substantively consolidated with those of any member of the Texas Holdings Group in the event any such member were to become a debtor in a bankruptcy case. Consistent with these ring-fencing measures, the assets and liabilities of the Oncor Ring-Fenced Entities have not been, and are not expected to be, substantively consolidated with the assets and liabilities of the Debtors in the Chapter 11 Cases.

Operating Segments

Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The Competitive Electric segment consists largely of TCEH. The Regulated Delivery segment consists largely of our investment in Oncor.

See Note 20 to the Financial Statements for further information regarding reportable business segments.

Significant Activities and Events and Items Influencing Future Performance

Filing under Chapter 11 of the United States Bankruptcy Code — On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities (the Debtors) filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). During the pendency of the Bankruptcy Filing (Chapter 11 Cases), the Debtors have operated and will continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

For additional discussion of the Bankruptcy Filing and its effects, see Note 2 to the Financial Statements and Item 1A, Risk Factors – Risks Related to the Chapter 11 Cases.

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Confirmation of the Plan of Reorganization — In September 2015, the Debtors filed the Plan of Reorganization and Disclosure Statement with the Bankruptcy Court. The Disclosure Statement was approved by the Bankruptcy Court in September 2015. In October 2015, the Debtors filed the Plan Supplement. In October 2015, the Plan of Reorganization was approved by the required creditors, and in December 2015, the Plan of Reorganization was confirmed by the Bankruptcy Court.For additional discussion see Note 2 to the Financial Statements.

Amended and Restated Settlement Agreement — In December 2015, the Settling Parties entered into the Amended and Restated Settlement Agreement, which was approved by the Bankruptcy Court in December 2015.

La Frontera CCGTs — In November 2015, Luminant entered into a purchase and sale agreement with La Frontera Ventures, LLC, a subsidiary of NextEra Energy, Inc., to purchase all of the membership interests in La Frontera Holdings, LLC, the indirect owner of two combined cycle gas turbine (CCGT) natural gas fueled generation facilities totaling 2,988 MW of capacity located in ERCOT. The aggregate purchase price to be paid by us under the agreement will be approximately $1.313 billion plus approximately $276 million for cash and net working capital, subject to customary adjustments based on the amounts of cash and net working capital at closing. The existing project indebtedness financing of La Frontera Holdings, LLC and its subsidiaries will be repaid at closing of the transaction. The purchase price is expected be funded by cash-on-hand and borrowings under the TCEH DIP Facility. The purchase and sale agreement contains customary closing conditions. The only remaining regulatory approval necessary to complete the acquisition is approval by the PUCT.

Extension of TCEH DIP Facility and TCEH Cash Collateral Order — In October 2015, the TCEH Debtors paid an $8 million extension fee and extended the maturity date of the TCEH DIP Facility to the earlier of (a) November 2016 or (b) the effective date of any reorganization plan of TCEH. The terms of the facility were otherwise unchanged by the extension. In September 2015, the TCEH Debtors extended their use of cash collateral to the earlier of (a) the effective date of a plan of reorganization or (b) 60 days following termination of the Debtors' Plan Support Agreement, provided that the TCEH Debtors do not otherwise cause an event of default under the cash collateral order. See Note 12 to the Financial Statements for discussion of the DIP Facilities.

Extension of EFIH DIP Facility — In January 2016, the EFIH Debtors paid a $13.5 million extension fee and extended the maturity date of the EFIH DIP Facility to the earlier of (a) December 2016 or (b) the effective date of any reorganization plan of EFIH. The terms of the facility were otherwise unchanged by the extension. See Note 12 to the Financial Statements for discussion of the DIP Facilities.

Repayment of EFIH Second Lien Notes —In March 2015, with the approval of the Bankruptcy Court, EFIH repaid (Repayment) $735 million, including interest at contractual rates, in amounts outstanding under EFIH's pre-petition 11.00% Fixed Senior Secured Second Lien Notes due October 1, 2021 (11.00% Notes) and 11.75% Fixed Senior Secured Second Lien Notes due March 1, 2022 (11.75% Notes) and $15 million in certain fees and expenses of the trustee for such notes. The Repayment resulted in an $84 million reduction in the principal amount of the 11.00% Notes, a $361 million reduction in the principal amount of the 11.75% Notes and the payment of $235 million and $55 million of accrued and unpaid post-petition and pre-petition interest, respectively, at contractual rates. The Repayment required the requisite consent of the lenders under EFIH's DIP Facility. EFIH received such consent from approximately 97% of the lenders under the EFIH DIP Facility and paid an aggregate consent fee equal to approximately $13 million. As a result of the Repayment, as of the date hereof, the principal amount outstanding on the 11.00% Notes and 11.75% Notes are $322 million and $1.389 billion, respectively.

EFIH First Lien Notes Settlement —See Note 12 to the Financial Statements for discussion of the incurrence of the EFIH DIP Facility and the use of certain proceeds to settle the EFIH First Lien Notes.

Overall Hedged Generation Position — Taking together forward wholesale and retail electricity sales with all hedging positions, at December 31, 2015, we had effectively hedged an estimated 94% and 18% of the price exposure, on a natural gas equivalent basis, related to our expected generation output for 2016 and 2017, respectively (assuming an approximate 8.5 market heat rate). The majority of our third-party hedges are financial natural gas positions.

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Impairment of Goodwill — In 2015, 2014, 2013 and 2012, we recorded $2.2 billion, $1.6 billion, $1.0 billion and $1.2 billion, respectively, in noncash goodwill impairment charges (which were not deductible for income tax purposes) related to the Competitive Electric segment. The write-offs reflected the effect of lower wholesale electricity prices in ERCOT, driven by the sustained decline in natural gas prices as discussed in Key Risks and Challenges – Natural Gas Price and Market Heat Rate Exposure below. Recorded goodwill related to the Competitive Electric segment totaled $152 million at December 31, 2015. See Note 5 to the Financial Statements for a description of the methods and key inputs and assumptions used by management to determine implied fair value of goodwill, the degree of uncertainty associated with those key inputs and assumptions, and the changes in circumstances that reasonably could be expected to affect the key inputs and assumptions.

The noncash impairment charges did not cause EFH Corp. or its subsidiaries to be in default under any of their respective debt covenants or have a material impact on liquidity.

See Note 5 to the Financial Statements and Application of Critical Accounting Policies below for more information on goodwill impairment testing and charges.

Impairment of Long-Lived Assets — We record impairment losses on long-lived assets used in our operations when events and circumstances indicate the long-lived assets might be impaired and the undiscounted cash flows generated by those assets are less than the carrying amounts of the assets. During 2014, the decrease in forecasted wholesale electricity prices in ERCOT, potential effects from environmental regulations and changes to our operating plans led to recording $4.670 billion in noncash impairment charges substantially all related to our Martin Lake, Monticello and Sandow 5 generation facilities. We evaluated our generation assets for impairment during 2015 as a result of impairment indicators related to the continued decline in forecasted wholesale electricity prices in ERCOT. Our evaluations concluded that impairments existed, and the carrying values at our Big Brown, Martin Lake, Monticello, Sandow 4 and Sandow 5 generation facilities were reduced in total by $2.541 billion. Additional material impairments related to these or other of our generation facilities may occur in the future if forward wholesale electricity prices in ERCOT continue to decline or if the forecasted costs of producing electricity at our generation facilities increase. See Note 9 to the Financial Statements for further discussion of impairment of long-lived assets.

OPEB Plan Actions — In accordance with an agreement between Oncor and EFH Corp., Oncor ceased participation in EFH Corp.'s OPEB Plan effective July 1, 2014 and established its own OPEB plan for Oncor's eligible existing and future retirees and their dependents, as well as split service participants as discussed in Note 19 to the Financial Statements. The separation resulted in the transfer of a significant portion of the liability associated with our plan to the new Oncor plan, which resulted in a reduction of our OPEB liability of approximately $758 million and a corresponding reduction of an equal amount in the receivable from unconsolidated subsidiary.

Global Climate Change and Other Environmental Matters — See Items 1 and 2, Business and Properties – Environmental Regulations and Related Considerations for discussion of global climate change, recent and anticipated EPA actions and various other environmental matters and their effects on the company.

Recent PUCT/ERCOT Actions — In the ERCOT market, a generation entity may submit a voluntary mitigation plan to the PUCT for ensuring compliance with the PUCT rules related to abuse of market power through economic withholding. In May 2015 the PUCT approved a voluntary mitigation plan submitted by Luminant. The plan specifies offering practices that Luminant could use when offering its generation into the ERCOT day-ahead and real-time markets. Adherence to the plan provides Luminant with an absolute defense under the PUCT rules against allegations of abuse of market power through economic withholding with respect to the specific behaviors addressed by the plan.

Oncor Matters with the PUCT —Change in Control Review (PUCT Docket No. 45188) — In connection with the EFH Acquisition contemplated by the Plan of Reorganization, in September 2015 Oncor and the Purchasers in the EFH Acquisition filed a joint report and application for regulatory approvals pursuant to PURA. See Note 2 to the Financial Statements for further discussion regarding the EFH Acquisition and the Plan of Reorganization.

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2008 Rate Review Filing (PUCT Docket No. 35717) — In August 2009, the PUCT issued a final order with respect to Oncor's June 2008 rate review filing with the PUCT and 204 cities based on a test year ended December 31, 2007, and new rates were implemented in September 2009. Oncor 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. Oncor filed an appeal with the Texas Third Court of Appeals (Austin Court of Appeals) in February 2011 with respect to the issues it 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. In August 2014, the Austin Court of Appeals reversed the district court and affirmed the PUCT with respect to 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. The Austin Court of Appeals also reversed the PUCT and district court's rejection of a proposed consolidated tax savings adjustment arising out of EFH Corp.'s ability to offset Oncor's taxable income against losses from other investments and remanded the issue to the PUCT to determine the amount of the consolidated tax savings adjustment. Oncor filed a motion on rehearing with the Austin Court of Appeals with respect to certain appeal issues on which Oncor was not successful, including the consolidated tax savings adjustment. In December 2014, the Austin Court of Appeals issued its opinion, clarifying that it was rendering judgment on the rate discount for state colleges and universities issue (affirming that PURA no longer requires imposition of the rate discount) rather than remanding it to the PUCT, and dismissing the motions for rehearing regarding the franchise fee issue and the consolidated tax savings adjustment. Oncor filed a petition for review with the Texas Supreme Court in February 2015. The Texas Supreme Court requested full briefing on the merits, and the briefing period ended in January 2016. In February 2016, the Texas Supreme Court granted the petition for review, with the date and time of oral arguments to be set at a later date. There is no deadline for the court to act. If Oncor's appeals efforts are unsuccessful and the proposed consolidated tax savings adjustment is implemented, Oncor estimates that on remand the impact on earnings of the consolidated tax savings adjustment's value could range from zero, as originally determined by the PUCT in Docket No. 35717, to a $135 million loss (after-tax) including taxes. Interest accrues at the PUCT approved rate for over-collections, which is 0.18% for 2016. Oncor does not believe that any of the other issues ruled upon by the Austin Court of Appeals would result in a material impact to its results of operations or financial condition.

Transmission Cost Recovery and Rates—In order to reflect increases or decreases in its wholesale transmission costs, including fees it pays to other transmission service providers, PUCT rules allow Oncor to update the transmission cost recovery factor (TCRF) component of its retail delivery rates charged to REPs on March 1 and September 1 each year. The table below lists TCRF filings impacting Oncor's cash flows for the year ended December 31, 2015, as well as filings that will impact Oncor's cash flows for the year ended December 31, 2016.

Docket No.	Filed	Effective	Semi-Annual Billing Impact Increase (Decrease)
45406	December 2015	March 2016 – August 2016	$	(64	)
44771	May 2015	September 2015 – February 2016	$	47
43858	December 2014	March 2015 – August 2015	$	(27	)
42558	May 2014	September 2014 – February 2015	$	71

Transmission Interim Rate Update Applications —In order to reflect changes in its invested transmission capital, PUCT rules allow Oncor to update its transmission cost of service (TCOS) rates by filing up to two interim TCOS rate adjustments in a calendar year. TCOS revenues are collected from load serving entities benefiting from Oncor's transmission system. REPs serving customers in Oncor's service territory are billed through the TCRF mechanism discussed above while other load serving entities are billed directly. The table below lists Transmission Interim Rate Update Applications impacting Oncor's revenues for the year ended December 31, 2015, as well as filings that will impact Oncor's revenues for the year ended December 31, 2016.

Docket No.	Filed	Effective	Oncor's Annual Revenue Impact		Third-Party Wholesale Transmission		Included in TCRF
44968	July 2015	September 2015	$	21	$	14	$	7
44363	January 2015	March 2015	$	35	$	23	$	12
42706	July 2014	September 2014	$	12	$	8	$	4
42267	February 2014	April 2014	$	74	$	47	$	27

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Application for 2016 Energy Efficiency Cost Recovery Factor Surcharge(PUCT Docket No. 44784) — In June 2015, Oncor filed an application with the PUCT to request approval of the energy efficiency cost recovery factor (EECRF) for 2016. PUCT rules require Oncor to make an annual EECRF filing by the first business day in June in each year for implementation on March 1 of the next calendar year. The requested 2016 EECRF was $67 million as compared to $68 million established for 2015, and would result in an average monthly charge for residential customers of $1.19 as compared to the 2015 average monthly residential charge of $1.23 per month. Average monthly charges are for a residential customer using 1,200 kilowatt-hours. In September 2015, the PUCT issued a final order approving the 2016 EECRF, which is designed to recover $61 million of Oncor's costs for the 2016 program year, a $10 million performance bonus based on Oncor's 2013 results and a $4 million decrease for over-recovery of 2014 costs.

KEY RISKS AND CHALLENGES

Following is a discussion of key risks and challenges facing management and the initiatives currently underway to manage such challenges. These matters involve risks that could have a material effect on our results of operations, liquidity or financial condition. Also see Item 1A, Risk Factors.

Chapter 11 Cases

As discussed above, we filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. For the duration of the Chapter 11 Cases, our business and operations will be subject to various risks, including but not limited to the following:

• increased levels of employee distraction, uncertainty and potential attrition;

• the inability to maintain or obtain sufficient debtor-in-possession financing sources for operations or to fund any reorganization plan and meet future obligations, and

• increased legal and other professional costs associated with the Chapter 11 Cases and our reorganization.

The duration of the Chapter 11 Cases is difficult to estimate and ultimately could be lengthy. The effectiveness of the Plan of Reorganization is subject to the satisfaction of certain conditions (some of which are not within our control). There can be no assurance that such conditions will be satisfied, and therefore, that the effectiveness of the Plan of Reorganization will occur. If the effective date of the reorganization does not occur, it may become necessary to amend the Plan of Reorganization to provide for alternative treatment of claims and interests which may result in holders of claims and interests receiving significantly less or no value for their claims and interests in the Chapter 11 Cases. If any modifications to the Plan of Reorganization are material, it may be necessary to re-solicit votes from holders of claims and interests adversely affected by the modifications with respect to such Plan. The resulting delay could require us to extend or refinance our DIP Facilities and could adversely impact our liquidity. We will also be required to seek approvals of certain federal and state regulators in connection with the Chapter 11 Cases, which approvals may be denied, conditioned or delayed, and certain parties may intervene and protest approval. An extended duration of the Chapter 11 Cases due to these factors could exacerbate the risks identified above and the contentiousness of the Chapter 11 Cases.

While we are operating under Chapter 11, transactions outside of the ordinary course of business will be subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities. Additionally, the terms of the DIP Facilities and the Plan of Reorganization limit our ability to undertake certain business initiatives.

We have engaged outside counsel and other advisors who are experts in bankruptcy matters to assist our management and other employees with legal and administrative matters related to the Chapter 11 Cases to minimize disruption to and distraction from our business operations and to help ensure that we have sufficient liquidity through the duration of the Chapter 11 Cases.

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Natural Gas Price and Market Heat Rate Exposure

Wholesale electricity prices in the ERCOT market have historically moved with the price of natural gas because marginal demand for electricity supply is generally met by natural gas fueled generation facilities. The price of natural gas has fluctuated due to changes in industrial demand, supply availability and other economic and market factors, and such prices have historically been volatile. As shown in the graph below, both settled and forward natural gas prices have generally declined over the last several years driven by development and expansion of hydraulic fracturing in natural gas extraction. (Amounts are per MMBtu.)

___________

(a) Settled prices represent the average of NYMEX Henry Hub monthly settled prices of financial contracts for the year ending on the date presented. Forward prices represent the annual average of NYMEX Henry Hub monthly forward prices at the date presented. Three year forward prices are presented as such period is generally deemed to be a liquid period.

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In contrast to our natural gas fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating electricity from our nuclear and lignite/coal fueled facilities, which represent the substantial majority of our generation capacity. All other factors being equal, these nuclear and lignite/coal fueled generation assets increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect on wholesale electricity prices in ERCOT. A persistent decline in the price of natural gas would likely result in a material and adverse impact on our results of operations, liquidity and financial condition.

The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Market heat rate can be affected by a number of factors including generation availability and the efficiency of the marginal supplier (generally natural gas fueled generation facilities) in generating electricity. Our market heat rate exposure is impacted by changes in the availability, such as additions and retirements of generation facilities, and mix of generation assets in ERCOT. For example, increasing renewable (wind and solar) generation capacity generally depresses market heat rates. Our heat rate exposure is impacted by potential economic backdown of our generation assets. Decreases in market heat rates decrease the value of our generation assets because lower market heat rates generally result in lower wholesale electricity prices, and vice versa. Even though market heat rates have generally increased over the past several years, wholesale electricity prices have declined due to the greater effect of falling natural gas prices.

With the exposure to variability of natural gas prices and market heat rates in ERCOT, retail sales price management and hedging activities are critical to the profitability of the business and maintaining consistent cash flow levels.

Our approach to managing electricity price risk focuses on the following:

• employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-related (electricity and natural gas) contracts intended to partially hedge gross margins;

• continuing focus on cost management to better withstand gross margin volatility;

• following a retail pricing strategy that appropriately reflects the magnitude and costs of commodity price, liquidity risk and retail demand variability, and

• improving retail customer service to attract and retain high-value customers.

We have engaged in natural gas hedging activities to mitigate the risk of lower wholesale electricity prices due to declines in natural gas prices. While current and forward natural gas prices are currently depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales. At December 31, 2015, we had natural gas hedges through 2016 and 2017 to hedge a portion of electricity price exposure for our expected lignite/coal and nuclear fueled generation.

We mitigate market heat rate risk through retail and wholesale electricity sales contracts and shorter-term heat rate hedging transactions. We evaluate opportunities to mitigate market heat rate risk over extended periods through longer-term electricity sales contracts where practical considering pricing, credit, liquidity and related factors.

The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas prices and market heat rates on realized pretax earnings for the periods presented. The estimates related to price sensitivity are based on our unhedged position and forward prices at December 31, 2015, which for natural gas reflects estimates of electricity generation less amounts under existing wholesale and retail sales contracts and amounts related to hedging positions. On a rolling basis, generally twelve-months, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

	Balance 2016	2017
$1.00/MMBtu change in natural gas price (a)(b)	$ ~30	$ ~345
0.1/MMBtu/MWh change in market heat rate (c)	$ ~2	$ ~15

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(a) Balance of 2016 is from February 1, 2016 through December 31, 2016.

(b) Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally being on the margin 70% to 90% of the time in the ERCOT market (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated). Excludes the impact of economic backdown.

(c) Based on Houston Ship Channel natural gas prices at December 31, 2015.

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On an ongoing basis, we will continue monitoring our overall commodity risks and seek to balance our portfolio based on our desired level of exposure to natural gas prices and market heat rates and potential changes to our operational forecasts of overall generation and consumption in our businesses (which is also subject to volatility resulting from customer churn, weather, economic and other factors). Portfolio balancing may include the execution of incremental transactions, including heat rate hedges, the unwinding of existing transactions and the substitution of natural gas hedges with commitments for the sale of electricity at fixed prices. As a result, commodity price exposures and their effect on earnings could materially change from time to time.

New and Changing Environmental Regulations

We are subject to various environmental laws and regulations related to SO₂, NO_X and mercury as well as other emissions that impact air and water quality. We believe we are in compliance with all current laws and regulations, but regulatory authorities have recently adopted or proposed new rules, such as the EPA's CSAPR, Regional Haze Program, MATS and GHG rules. Certain of these adopted or proposed rules could require material capital expenditures and challenge the economic viability of any affected generation facility. If we make any major modifications to our electricity generation facilities, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the Clean Air Act. Any such modifications would likely result in substantial additional capital expenditures and challenge the economic viability of any affected generation facility. (See Note 14 to the Financial Statements for discussion of litigation related to our generation facilities and Environmental Contingencies and Items 1 and 2, Business and Properties – Environmental Regulations and Related Considerations.)

We also continue to closely monitor any potential legislative, regulatory and judicial changes pertaining to global climate change. In view of the fact that a substantial portion of our generation portfolio consists of lignite/coal fueled generation facilities, our results of operations, liquidity or financial condition could be materially affected by the enactment of any legislation, regulation or judicial action that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes on entities that produce GHG emissions, or that establishes federal renewable energy portfolio standards. For example, federal, state or regional legislation or regulation addressing global climate change could result in us either incurring material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with a mandatory cap-and-trade emissions reduction program and/or challenge the economic viability of any affected generation facility. See further discussion under Items 1 and 2, Business and Properties – Environmental Regulations and Related Considerations.

Competitive Retail Markets and Customer Retention

Competitive retail activity in ERCOT has resulted in retail customer churn as customers switch providers for various reasons. Our total retail customer counts declined less than 1% in 2015, 1% in 2014 and 3% in 2013. Based upon 2015 results discussed below in Results of Operations – Competitive Electric Segment, a 1% decline in residential customers would result in a decline in annual revenues of approximately $29 million. In responding to the competitive landscape in the ERCOT marketplace, we have reduced overall customer losses by focusing on the following key initiatives:

• Maintaining competitive pricing initiatives on residential service plans;

• Actively competing for new customers in areas in ERCOT open to competition, while continuing to strive to enhance the experience of our existing customers. The customer retention strategy remains focused on continuing to implement initiatives to deliver world-class customer service and improve the overall customer experience;

• Establishing TXU Energy as the most innovative retailer in the ERCOT market by continuing to develop tailored product offerings to meet customer needs. Since the Merger, TXU Energy has invested more than $100 million in retail initiatives aimed at helping consumers conserve energy and demand-side management initiatives that are intended to moderate consumption and reduce peak demand for electricity, and

• Focusing business market initiatives largely on programs targeted to retain the existing highest-value customers and to recapture customers who have switched REPs. Initiatives include maintaining and continuously refining a disciplined contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy the direct-sales force. Tactical programs put into place include improved customer service, aided by an enhanced customer management system, new product price/service offerings and a multichannel approach for the small business market.

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Exposures Related to Nuclear Asset Outages

Our nuclear assets are comprised of two generation units at the Comanche Peak plant site, each with an installed nameplate capacity of 1,150 MW. These units represent approximately 17% of our total generation capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, the unfavorable impact to pretax earnings is estimated (based upon forward electricity market prices for 2016 at December 31, 2015) to be approximately $1 million per day before consideration of any costs to repair the cause of an outage or any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 14 to the Financial Statements.

The inherent complexities and related regulations associated with operating nuclear generation facilities result in environmental, regulatory and financial risks. The operation of nuclear generation facilities is subject to continuing review and regulation by the NRC, including potential regulation as a result of the NRC's ongoing analysis and response to the effects of the natural disaster on nuclear generation facilities in Fukushima, Japan in 2010, covering, among other things, operations, maintenance, emergency planning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increased capital or operating costs, and it may require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outage at another nuclear generation facility could result in the NRC taking action to shut down the Comanche Peak units as a precautionary measure.

We participate in industry groups and with regulators to remain current on the latest developments in nuclear safety, operation and maintenance and on emerging threats and mitigating techniques. These groups include, but are not limited to, the NRC and the Institute of Nuclear Power Operations (INPO). We also apply the knowledge gained by continuing to invest in technology, processes and services to improve our operations and detect, mitigate and protect our nuclear generation assets. The Comanche Peak plant has not experienced an extended unplanned outage, and management continues to focus on the safe, reliable and efficient operations at the plant.

Oncor's Capital Availability and Cost

Our investment in Oncor, which represents approximately 80% of its membership interests, is a significant value driver of our overall business. Oncor's access to capital markets and cost of debt could be directly affected by its credit ratings. Any adverse action with respect to Oncor's credit ratings could generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease and could result in reduced distributions from Oncor. Oncor's credit ratings are currently substantially higher than those of the Texas Holdings Group. If credit rating agencies were to change their views of Oncor's independence from any member of the Texas Holdings Group, Oncor's credit ratings would likely decline. We believe these risks are substantially mitigated by the significant ring-fencing measures implemented by EFH Corp. and Oncor as described in Note 1 to the Financial Statements.

Cyber Security and Infrastructure Protection Risk

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 generation and transmission assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could 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. These groups include, but are not limited to, the US Cyber Emergency Response Team, the National Electric Sector Cyber Security Organization, the NRC and NERC.

While the company has not experienced a cyber event causing any material operational, reputational or financial impact, we recognize the growing threat within our industry and are proactively making strategic investments in our perimeter and internal defenses, cyber security operations center and regulatory compliance activities. We also apply the knowledge gained through industry and government organizations to continuously improve our technology, processes and services to detect, mitigate and protect our cyber assets.

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APPLICATION OF CRITICAL ACCOUNTING POLICIES

Our significant accounting policies are discussed in Note 1 to the 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.

Impairment of Goodwill and Other Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. For our generation assets, possible indications include an expectation of continuing long-term declines in natural gas prices and/or market heat rates or an expectation that "more likely than not" a generation asset will be sold or otherwise disposed of significantly before the end of its estimated useful life. 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 related to an asset, group of assets or investment in unconsolidated subsidiary. Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual generation units that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing. We generally utilize an income approach measurement to derive fair values for our long-lived generation assets. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental rules, generation plant performance, forecasted capital expenditures and forecasted fuel prices. Any significant change to one or more of these factors can have a material impact on the fair value measurement of our long-lived assets. As a result of the decrease in forecasted wholesale electricity prices, potential effects from environmental regulations and changes to our operating plans in 2015 and 2014, we evaluated the recoverability of our generation assets. In 2013, we evaluated the recoverability of the assets of our joint venture to develop additional nuclear generation units. See Note 9 to the Financial Statements for a discussion of the impairment charges related to certain of those assets. Additional material impairments related to these or other of our generation facilities may occur in the future if forward wholesale electricity prices in ERCOT continue to decline or if additional environmental regulations increase the cost of producing electricity at our generation facilities.

Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (we have selected December 1 as our annual test date) or whenever events or changes in circumstances indicate an impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparable public companies in our industry. As required by accounting guidance related to goodwill, we have allocated goodwill to our reporting units, which are our two segments: Competitive Electric and Regulated Delivery, and goodwill impairment testing is performed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reporting unit's carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit's assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then 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.

The determination of enterprise value involves a number of assumptions and estimates. We use a combination of fair value measurements to estimate enterprise values of our reporting units including: internal discounted cash flow analyses (income approach), and comparable publicly traded company values (market approach). The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental rules, generation plant performance, forecasted capital expenditures and retail sales volume trends, as well as determination of a terminal value. Another key variable in the income approach is the discount rate, or weighted average cost of capital, applied to the forecasted cash flows. The determination of the discount rate takes into consideration the capital structure, debt ratings and current debt yields of comparable public companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry. Enterprise value estimates based on comparable company values involve using trading multiples of EBITDA of those selected public companies to derive appropriate multiples to apply to the EBITDA of the reporting units. Critical judgments include the selection of comparable companies and the weighting of the value metrics in developing the best estimate of enterprise value.

See Note 5 to the Financial Statements for additional discussion of goodwill impairment charges.

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Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. We estimate fair value as described in Note 16 to the Financial Statements and discussed under Fair Value Measurements below.

Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. Normal purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting if the election as normal is made. Hedge accounting designations are made with the intent to match the accounting recognition of the contract's financial performance to that of the transaction the contract is intended to hedge. The intent of our hedging activity is generally to enter into positions that reduce our exposure to future variable cash flows, and such hedges are referred to as cash flow hedges.

Under hedge accounting, changes in fair value of instruments designated as cash flow hedges are recorded in other comprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, it mirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectiveness of the hedge are recognized in net income immediately, and the effective portion of changes in fair value initially recorded in other comprehensive income are reclassified to net income in the period that the hedged transactions are recognized in net income. At December 31, 2015 and 2014 we did not have any derivatives designated as cash flow hedges.

We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets.

See Note 17 to the Financial Statements for further discussion regarding derivative instruments, including the termination of interest rate swaps and certain natural gas hedging agreements shortly after the Bankruptcy Filing.

Fair Value Measurements

For certain accounting measurements that require fair value we determine value under the fair value hierarchy established in accounting standards. We utilize several valuation techniques to measure the fair value, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis.

Under the fair value hierarchy, Level 1 and Level 2 valuations generally apply to our commodity-related contracts for natural gas, electricity and fuel, including coal and uranium, derivative instruments entered into for hedging purposes, securities associated with the nuclear decommissioning trust and interest rate swaps intended to fix interest payments on our debt. Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

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Our Level 3 valuations generally apply to our interest rate swaps on TCEH's debt, congestion revenue rights, certain coal contracts, options to purchase or sell electricity, and electricity purchase and sales agreements for which the valuations include unobservable inputs, including the hourly shaping of the price curve. Level 3 valuations use largely unobservable inputs, with little or no supporting market activity, and assets and liabilities are classified as Level 3 if such inputs are significant to the fair value determination. Valuation risk is mitigated through the performance of stress testing of the significant inputs to understand the impact that varying assumptions may have on the valuation and other review processes performed to ensure appropriate valuation.

As part of our valuation of assets subject to fair value measurement, counterparty credit risk is taken into consideration by measuring the extent of netting arrangements in place with the counterparty along with credit enhancements and the estimated credit ratings, default rate factors and debt trading values of the counterparty. Our valuation of liabilities subject to fair value accounting takes into consideration the market's view of our credit risk along with the existence of netting arrangements in place with the counterparty and credit enhancements posted by us. We consider the credit risk adjustment to be a Level 3 input since judgment is used to assign credit ratings, recovery rate factors and default rate factors. The risk adjustment for our credit is what drove our interest rate swap valuations to be classified as Level 3 in 2013.

Valuations of Level 3 assets and liabilities can be sensitive to the assumptions used for the significant inputs. Where market data is available, the inputs used for valuation reflect that information as of our valuation date. In periods of extreme volatility, lessened liquidity or in illiquid markets, there may be more variability in market pricing or a lack of market data to use in the valuation process. An illiquid market is one in which little or no observable activity has occurred or one that lacks willing buyers.

Valuations of several of our Level 3 assets and liabilities are sensitive to changes in discount rates, option-pricing model inputs such as volatility factors and credit risk adjustments. At December 31, 2015 and 2014, a 10% change in electricity price (per MWh) assumptions across unobservable inputs would cause an approximate $4 million and $3 million change, respectively, in net Level 3 assets and liabilities. At December 31, 2014, a 10% change in coal price assumptions across unobservable inputs would cause an approximate $7 million change in net Level 3 assets and liabilities.

See Note 16 to the Financial Statements for additional information about fair value measurements, including information on unobservable inputs and related valuation sensitivities and a table presenting the changes in Level 3 assets and liabilities for the years ended December 31, 2015, 2014 and 2013.

Variable Interest Entities

A variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. Determining whether or not to consolidate a VIE requires interpretation of accounting rules and their application to existing business relationships and underlying agreements. Amended accounting rules related to VIEs resulted in the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor. In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the rights granted to the interest holders of the VIE to determine whether we have the right or obligation to absorb profit and loss from the VIE and the power to direct the significant activities of the VIE. See Note 4 to the Financial Statements for our analysis of the Oncor relationship and information regarding our consolidated variable interest entities.

Revenue Recognition

Our revenue includes an estimate for unbilled revenue related to our electricity customers that represents estimated daily kWh consumption after the meter read date to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using metered consumption as well as historical kWh usage information adjusted for weather and other measurable factors affecting consumption. Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because of seasonal changes in demand. Accrued unbilled revenues totaled $231 million, $239 million and $272 million at December 31, 2015, 2014 and 2013, respectively.

Accounting for Income Taxes

EFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. Oncor is a partnership for US federal income tax purposes and is not a corporate member of the EFH Corp. consolidated group.

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EFH Corp., Oncor Holdings, Oncor and Oncor's third-party minority investor are parties to a Federal and State Income Tax Allocation Agreement, which governs the computation of federal income tax liability among such parties, and similarly provides, among other things, that each of Oncor Holdings and Oncor will pay EFH Corp. its share of an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return.

Our income tax expense and related consolidated balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates and judgments of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual 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. Our 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 taxes that may be owed as a result of any examination.

We recorded income tax benefits totaling $2 million, $35 million and $305 million in the years ended December 31, 2015, 2014 and 2013, respectively, related to resolution of IRS audit matters. See Note 6 to the Financial Statements regarding uncertain tax positions.

See Notes 1, 6 and 7 to the Financial Statements for discussion of income tax matters.

Accounting in Reorganization

Consolidated financial statements for periods following the Petition Date have been prepared in accordance with ASC 852, Reorganizations, which contemplates the realization of assets and the satisfaction of liabilities on a going concern basis. However, as a result of the Chapter 11 Cases, such realization of assets and satisfaction of liabilities are subject to a number of uncertainties. ASC 852 requires the following:

• Reclassification of unsecured or under-secured pre-petition debt, including unamortized deferred financing costs and discounts/premiums associated with debt, and other liabilities to a separate line item in the consolidated balance sheets, called "Liabilities subject to compromise;"

• Nonaccrual of interest expense for financial reporting purposes, to the extent not paid during bankruptcy;

• Reporting in a new line in the statements of consolidated income (loss) of incremental items of income or loss related to bankruptcy, such as professional fees, as well as adjustments of liabilities to their estimated allowed claim amounts and ultimately settlement amounts as a separate line item in the statements of consolidated income (loss);

• Evaluation of actual or potential bankruptcy claims, which are not already reflected as a liability on the consolidated balance sheets, under ASC 450, Contingencies. If valid unrecorded claims meeting the ASC 450 criteria are presented to us in future periods, we will accrue for these amounts at the expected amount of the allowed claim, and

• Upon emergence from Chapter 11 reorganization, fresh-start accounting under GAAP may be required. Under fresh-start accounting, the reorganization value of the entity would be allocated to the entity's individual assets and liabilities on a fair value basis in conformity with the procedures specified by ASC 805, Business Combinations.

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RESULTS OF OPERATIONS

Consolidated Financial Results — Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

See Competitive Electric Segment – Financial Results below for a discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain (loss) from commodity hedging and trading activities; operating costs; depreciation and amortization and SG&A expenses.

In 2015 and 2014, noncash impairments of goodwill totaling $2.2 billion and $1.6 billion, respectively, were recorded in the Competitive Electric segment as discussed in Note 5 to the Financial Statements.

In 2015 and 2014, noncash impairments of certain long-lived assets totaling $2.541 billion and $4.670 billion, respectively, were recorded in the Competitive Electric segment as discussed in Note 9 to the Financial Statements.

See Note 8 to the Financial Statements for details of other income and deductions.

Results in 2014 include fees for legal and other professional services associated with our debt restructuring activities prior to the Petition Date, which totaled $49 million and are reported in SG&A expenses. Of this amount, $28 million is included in the Competitive Electric segment results and $21 million is included in Corporate and Other activities. Legal and other professional services costs incurred with the Chapter 11 Cases since the Petition Date are now being reported in reorganization items as discussed below.

Interest expense and related charges decreased $441 million to $1.760 billion in 2015. The decrease reflected:

• $979 million in lower interest expense on pre-petition debt due to the discontinuance of interest due to the Chapter 11 Cases, and

• $66 million in lower amortization of pre-petition debt issuance, amendment and extension costs and discounts due to reclassification of such amounts to liabilities subject to compromise in 2014,

partially offset by

• $405 million in higher expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of TCEH secured creditors in the year ended December 31, 2015 as compared to the post-petition period ended December 31, 2014;

• $133 million in higher interest expense on debtor-in-possession financing in the year ended December 31, 2015 as compared to the post-petition period ended December 31, 2014, and

• $66 million in mark-to-market net gains on interest rate swaps in 2014.

See Note 10 to the Financial Statements for details of interest expense and related charges.

Reorganization items totaled $1.355 billion and $815 million in 2015 and 2014, respectively. Activity in 2015 included $926 million related to the adjustment of expected allowed claims of pre-petition debt to remove issuance costs and debt premiums/discounts, $310 million in legal advisory and representation services, $128 million in other professional consulting and advisory services, $38 million primarily related to net contract claim and assumption adjustments and $28 million in fees associated with the repayment of EFIH Second Lien Notes in March 2015, partially offset by an $86 million gain due to the settlement of liabilities under a management agreement with our Sponsors (see Note 19 to the Financial Statements). Activity in 2014 included a $278 million expense related to a liability adjustment arising from termination of interest rate swap agreements and natural gas hedging positions (see Note 17 to the Financial Statements), $187 million in fees associated with completion of the TCEH and EFIH DIP facilities (see Note 12 to the Financial Statements), a $108 million net loss on exchange and settlement of the EFIH First Lien Notes, $127 million in legal advisory and representation services fees, $95 million in other professional consulting and advisory services fees and $20 million primarily related to contract claim adjustments. See Note 11 to the Financial Statements for additional discussion.

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Income tax benefit totaled $1.670 billion and $2.619 billion in 2015 and 2014, respectively. Excluding the $39 million income tax benefit recorded in 2014 related to an adjustment of reserves for uncertain tax positions for the 2007 tax year (see Note 6 to the Financial Statements) and the nondeductible goodwill impairment charges in both 2015 and 2014, the effective tax benefit rate was 32.5% and 33.2% in 2015 and 2014, respectively. See Note 7 to the Financial Statements for reconciliation of these comparable effective rates to the US federal statutory rate.

Net loss for EFH Corp. decreased $1.064 billion to $5.342 billion in 2015.

• Net loss for the Competitive Electric segment decreased $1.582 billion to $4.678 billion.

• Earnings from the Regulated Delivery segment decreased $15 million to $334 million.

• After-tax net expenses from Corporate and Other activities totaled $998 million and $495 million in 2015 and 2014, respectively. The change primarily reflects an increase in the Corporate and Other portion of reorganization items discussed above.

Consolidated Financial Results — Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

See Competitive Electric Segment – Financial Results below for a discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain (loss) from commodity hedging and trading activities; operating costs; depreciation and amortization and SG&A expenses.

In 2014 and 2013, noncash impairments of goodwill totaling $1.6 billion and $1.0 billion, respectively, were recorded in the Competitive Electric segment as discussed in Note 5 to the Financial Statements.

In 2014 and 2013, noncash impairments of certain long-lived assets totaling $4.670 billion and $140 million, respectively, were recorded in the Competitive Electric segment as discussed in Note 9 to the Financial Statements.

See Note 8 to the Financial Statements for details of other income and deductions.

Results include fees for legal and other professional services associated with our debt restructuring activities prior to the Petition Date, which totaled $49 million in 2014 and $105 million in 2013 and are reported in SG&A expenses. Of the 2014 amount, $28 million is included in the Competitive Electric segment results and $21 million is included in Corporate and Other activities. Legal and other professional services costs incurred with the Chapter 11 Cases since the Petition Date are now being reported in reorganization items as discussed below. Of the 2013 amount, $63 million is included in the Competitive Electric segment results and $42 million is included in Corporate and Other activities.

Interest expense and related charges decreased $503 million to $2.201 billion in 2014. The decrease reflected:

• $2.329 billion in lower interest expense on pre-petition debt due to the discontinuance of interest upon the Bankruptcy Filing and the termination of the interest rate swap agreements shortly after the Bankruptcy Filing, and

• $141 million in lower amortization of pre-petition debt issuance, amendment and extension costs and discounts due to reclassification of such amounts to liabilities subject to compromise,

partially offset by

• $992 million in lower mark-to-market net gains on interest rate swaps due to the termination of the agreements;

• $827 million in expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of TCEH secured creditors; and

• $162 million in interest expense on debtor-in-possession financing.

See Note 10 to the Financial Statements for details of interest expense and related charges.

50

Reorganization items totaled $815 million in 2014 and included a $278 million expense related to a liability adjustment arising from termination of interest rate swap agreements and natural gas hedging positions (see Note 17 to the Financial Statements), $187 million in fees associated with completion of the TCEH and EFIH DIP facilities (see Note 12 to the Financial Statements), a $108 million net loss on exchange and settlement of the EFIH First Lien Notes, $127 million in legal advisory and representation services fees, $95 million in other professional consulting and advisory services fees and $20 million primarily related to contract claim adjustments. See Note 11 to the Financial Statements for additional discussion.

Income tax benefit totaled $2.619 billion and $1.271 billion in 2014 and 2013, respectively. Excluding the $39 million income tax benefit recorded in the third quarter of 2014 related to an adjustment of reserves for uncertain tax positions for the 2007 tax year, the $305 million income tax benefit recorded in 2013 related to resolution of IRS audit matters, the 2013 impairment of the assets of the nuclear generation development joint venture and the nondeductible goodwill impairment charges in both years, the effective tax benefit rate was 33.2% and 34.2% in 2014 and 2013, respectively. The change in the effective income tax rate is driven primarily by higher nondeductible legal and other professional services costs related to the Chapter 11 Cases in 2014. See Note 6 to the Financial Statements for discussion of uncertain tax positions. See Note 9 to the Financial Statements for discussion of the impairment of the joint venture's assets. See Note 5 to the Financial Statements for discussion of goodwill impairments. See Note 7 to the Financial Statements for reconciliation of these comparable effective rates to the US federal statutory rate.

Net loss for EFH Corp. increased $4.188 billion to $6.406 billion in 2014.

• Net loss for the Competitive Electric segment increased $3.951 billion to $6.260 billion.

• Earnings from the Regulated Delivery segment increased $14 million to $349 million.

• After-tax net expenses from Corporate and Other activities totaled $495 million and $244 million in 2014 and 2013, respectively. The change reflects a $226 million income tax benefit in 2013 related to the Corporate and Other portion of the $305 million income tax benefit related to resolution of IRS audit matters referred to above and charges of $190 million ($295 million pre-tax) for the Corporate and Other portion of reorganization items discussed above, partially offset by $155 million ($240 million pre-tax) in lower interest expense, $24 million in income tax benefit recorded in 2014 related to an adjustment of reserves for uncertain tax positions discussed above and $14 million ($21 million pretax) in lower legal and professional fees for the Corporate and Other portion of our debt restructuring activities.

Net loss attributable to noncontrolling interests of $107 million in 2013 represents the noncontrolling interest share of the impairment of the assets of the nuclear generation development joint venture.

Non-GAAP Earnings Measures

In communications with investors, we use a non-GAAP earnings measure that reflects adjustments to earnings reported in accordance with US GAAP in order to review and analyze underlying operating performance. These adjustments, which are generally noncash, consist of unrealized mark-to-market gains and losses, impairment charges, debt extinguishment gains and other charges, and credits or gains that are unusual or nonrecurring. All such items and related amounts are disclosed in our annual report on Form 10-K and quarterly reports on Form 10-Q.

51

Competitive Electric Segment

Financial Results

	Year Ended December 31,
	2015			2014			2013
Operating revenues	$	5,370		$	5,978		$	5,899
Fuel, purchased power costs and delivery fees	(2,692		)	(2,842		)	(2,848		)
Net gain (loss) from commodity hedging and trading activities	334			11			(54		)
Operating costs	(834		)	(914		)	(881		)
Depreciation and amortization	(852		)	(1,270		)	(1,333		)
Selling, general and administrative expenses	(676		)	(708		)	(756		)
Impairment of goodwill	(2,200		)	(1,600		)	(1,000		)
Impairment of long-lived assets	(2,541		)	(4,670		)	(140		)
Other income	17			16			9
Other deductions	(94		)	(281		)	(50		)
Interest income	1			—			6
Interest expense and related charges	(1,289		)	(1,799		)	(2,062		)
Reorganization items	(101		)	(520		)	—
Loss before income taxes	(5,557		)	(8,599		)	(3,210		)
Income tax benefit	879			2,339			794
Net loss	(4,678		)	(6,260		)	(2,416		)
Net loss attributable to noncontrolling interests	—			—			107
Net loss attributable to the Competitive Electric segment	$	(4,678	)	$	(6,260	)	$	(2,309	)

52

Competitive Electric Segment

Sales Volume and Customer Count Data

	Year Ended December 31,						2015		2014
	2015		2014		2013		% Change		% Change
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential	21,923		21,910		22,791		0.1		(3.9	)
Small business (a)(b)	5,180		5,250		4,976		(1.3	)	5.5
Large business and other customers (b)	14,109		11,351		10,227		24.3		11.0
Total retail electricity	41,212		38,511		37,994		7.0		1.4
Wholesale electricity sales volumes (c)	23,533		32,965		38,320		(28.6	)	(14.0	)
Total sales volumes	64,745		71,476		76,314		(9.4	)	(6.3	)
Average volume (kWh) per residential customer (d)	14,673		14,530		14,815		1.0		(1.9	)
Weather (North Texas average) – percent of normal (e):
Cooling degree days	105.4	%	101.4	%	103.0	%	3.9		(1.6	)
Heating degree days	103.8	%	117.8	%	117.8	%	(11.9	)	—
Customer counts:
Retail electricity customers (end of period, in thousands) (f):
Residential	1,489		1,500		1,516		(0.7	)	(1.1	)
Small business (a)(g)	162		168		171		(3.6	)	(1.8	)
Large business and other customers (g)	42		29		22		44.8		31.8
Total retail electricity customers	1,693		1,697		1,709		(0.2	)	(0.7	)

___________

(a) Customers with demand of less than 1 MW annually.

(b) Year ended December 31, 2014 and 2013 volumes reflect a reclassification of 638 GWh and 411 GWh, respectively, of retail electricity sales volumes from small business to large business and other customers to conform to current presentation.

(c) Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.

(d) Calculated using average number of customers for the period.

(e) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over the 10-year period from 2000 to 2010.

(f) Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers.

(g) Year ended December 31, 2014 and 2013 counts reflect reclassification of eight thousand and five thousand, respectively, retail electricity customers from small business to large business and other customers to conform to current presentation.

53

Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

	Year Ended December 31,								2015		2014
	2015		2014			2013			% Change		% Change
Operating revenues:
Retail electricity revenues:
Residential	$	2,931	$	2,970		$	2,984		(1.3	)	(0.5	)
Small business (a) (b)	634		657			647			(3.5	)	1.5
Large business and other customers (b)	884		786			708			12.5		11.0
Total retail electricity revenues	4,449		4,413			4,339			0.8		1.7
Wholesale electricity revenues (c)(d)	680		1,267			1,282			(46.3	)	(1.2	)
Amortization of intangibles (e)	23		23			22			—		4.5
Other operating revenues	218		275			256			(20.7	)	7.4
Total operating revenues	$	5,370	$	5,978		$	5,899		(10.2	)	1.3
Net gain (loss) from commodity hedging and trading activities:
Realized net gains	$	217	$	387		$	1,057
Unrealized net gains (losses)	117		(376		)	(1,111		)
Total	$	334	$	11		$	(54	)

___________

(a) Customers with demand of less than 1 MW annually.

(b) Year ended December 31, 2014 and 2013 amounts reflect a reclassification of $44 million and $33 million, respectively, of retail electricity revenues from small business to large business and other customers to conform to current presentation.

(c) Upon settlement of physical derivative commodity contracts that we mark-to-market in net income, such as certain electricity sales and purchase agreements and coal purchase contracts, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, rather than contract price. The offsetting differences between contract and market prices are reported in net gain (loss) from commodity hedging and trading activities.

(d) Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.

(e) Represents amortization of the intangible net asset value of retail and wholesale electricity sales agreements resulting from purchase accounting.

54

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Year Ended December 31,									2015		2014
	2015			2014			2013			% Change		% Change
Fuel, purchased power costs and delivery fees ($ millions):
Fuel for nuclear facilities	$	146		$	147		$	173		(0.7	)	(15.0	)
Fuel for lignite/coal facilities	736			784			869			(6.1	)	(9.8	)
Total nuclear and lignite/coal facilities (a)	882			931			1,042			(5.3	)	(10.7	)
Fuel for natural gas facilities and purchased power costs (a)	252			316			292			(20.3	)	8.2
Amortization of intangibles	6			40			37			(85.0	)	8.1
Other costs	160			227			196			(29.5	)	15.8
Fuel and purchased power costs	1,300			1,514			1,567			(14.1	)	(3.4	)
Delivery fees	1,392			1,328			1,281			4.8		3.7
Total	$	2,692		$	2,842		$	2,848		(5.3	)	(0.2	)
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
Nuclear facilities	$	7.32		$	7.90		$	8.45		(7.3	)	(6.5	)
Lignite/coal facilities (b)	$	21.03		$	19.79		$	19.93		6.3		(0.7	)
Natural gas facilities and purchased power (c)	$	46.16		$	49.48		$	46.62		(6.7	)	6.1
Delivery fees per MWh	$	33.64		$	34.36		$	33.57		(2.1	)	2.4
Production and purchased power volumes (GWh):
Nuclear facilities	19,954			18,636			20,487			7.1		(9.0	)
Lignite/coal facilities (d)	41,817			48,878			52,023			(14.4	)	(6.0	)
Total nuclear and lignite/coal facilities	61,771			67,514			72,510			(8.5	)	(6.9	)
Natural gas facilities	709			816			899			(13.1	)	(9.2	)
Purchased power (e)	2,265			3,146			2,905			(28.0	)	8.3
Total energy supply volumes	64,745			71,476			76,314			(9.4	)	(6.3	)
Capacity factors:
Nuclear facilities	99.0		%	92.5		%	101.7		%	7.0		(9.0	)
Lignite/coal facilities (d)	59.5		%	69.6		%	74.1		%	(14.5	)	(6.1	)
Total	68.3		%	74.7		%	80.2		%	(8.6	)	(6.9	)

___________

(a) See footnote (c) to the Revenue and Commodity Hedging and Trading Activities table on previous page.

(b) Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs and excludes unrealized amounts as discussed in footnote (c) to the Revenue and Commodity Hedging and Trading Activities table on previous page.

(c) Excludes volumes related to line loss and power imbalances and unrealized amounts as discussed in footnote (c) to the Revenue and Commodity Hedging and Trading Activities table on previous page.

(d) Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal fueled units totaling 19,900 GWh, 15,770 GWh and 12,460 GWh in 2015, 2014 and 2013, respectively.

(e) Includes amounts related to line loss and power imbalances.

55

Competitive Electric Segment – Financial Results – Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Operating revenues decreased $608 million, or 10%, to $5.370 billion in 2015.

Retail electricity revenues increased $36 million, or 1%, to $4.449 billion in 2015 primarily reflecting a $310 million increase due to volumes, partially offset by a $274 million decrease due to lower average prices. The increase in retail sales volumes primarily reflected net increases in business sales volumes, which was offset by lower average retail prices primarily for business markets customers.

Wholesale electricity revenues decreased $587 million, or 46%, to $680 million in 2015 reflecting a $362 million decrease in sales volumes and a $225 million decrease due to lower average wholesale electricity prices. A 29% decrease in wholesale electricity sales volumes was driven by lower generation volumes that resulted from increased economic backdown (including seasonal operations) at our lignite/coal generation facilities. The increased economic backdown at our generation facilities and the lower average wholesale electricity sales prices were driven by a 35% decline in average wholesale electricity prices in the year ended December 31, 2015, which was impacted by lower natural gas prices during the period compared to natural gas prices in 2014.

Fuel, purchased power costs and delivery fees decreased $150 million, or 5%, to $2.692 billion in 2015. Fuel for lignite/coal facilities decreased $48 million reflecting lower generation volumes, partially offset by higher lignite mining costs and more western coal in the fuel blend. Fuel for natural gas facilities and purchased power costs decreased $64 million primarily reflecting a 28% decrease in purchased power volumes and lower natural gas prices and generation for natural gas generation units. Amortization of intangibles decreased $34 million reflecting decreased amortization of favorable purchase contracts due to impairments recorded at the end of 2014. See Note 5 to the Financial Statements for further discussion of the impairment charges. Other costs decreased $67 million reflecting a $49 million decrease in natural gas purchases for resale and an $18 million decrease in ERCOT ancillary service fees, both driven by lower market prices. Delivery fees increased $64 million primarily reflecting higher retail volumes.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $334 million and $11 million in net gains for the years ended December 31, 2015 and 2014, respectively.

	Year Ended December 31, 2015
	Net Realized Gains		Net Unrealized Gains (Losses)			Total
Hedging positions	$	206	$	126		$	332
Trading positions	11		(9		)	2
Total	$	217	$	117		$	334

	Year Ended December 31, 2014
	Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Total
Hedging positions	$	397		$	(393	)	$	4
Trading positions	(10		)	17			7
Total	$	387		$	(376	)	$	11

Net realized gains on hedging and trading positions decreased $170 million, reflecting lower gains due to the 2014 termination of our favorable long-term natural gas hedging program, partially offset by other realized gains from declining market prices in 2015.

The $493 million favorable change in net unrealized results primarily reflected the 2014 reversal of previously recorded unrealized gains related to the favorable pricing of our long-term natural gas hedging program that terminated in 2014 along with favorable unrealized gains in 2015 due to the impact of declining natural gas prices on our hedging positions.

Operating costs decreased $80 million, or 9%, to $834 million in 2015. The decrease was driven by $55 million in lower nuclear maintenance costs reflecting a spring refueling in 2014 that was absent in 2015, as well as lower lignite/coal facilities operating costs reflecting lower generation.

56

Depreciation and amortization expenses decreased $418 million, or 33%, to $852 million in 2015 primarily reflecting reduced depreciation expense resulting from the effect of noncash impairments of certain long-lived assets recorded at the end of 2014 and during 2015.

In 2015 and 2014, noncash impairments of goodwill totaling $2.2 billion and $1.6 billion, respectively, were recorded as discussed in Note 5 to the Financial Statements.

In 2015 and 2014, noncash impairments of certain long-lived assets totaling $2.541 billion and $4.670 billion, respectively, were recorded as discussed in Note 9 to the Financial Statements.

Other deductions totaled $94 million in 2015 and $281 million in 2014. Other deductions in 2015 included impairments of identifiable intangible assets totaling $84 million. Other deductions in 2014 include a $183 million impairment of intangible assets related to favorable purchase contracts and $80 million related to environmental credits. See Note 8 to the Financial Statements.

Interest expense and related charges decreased $510 million, or 28%, to $1.289 billion in 2015. The decrease reflected:

• $925 million in lower interest expense on pre-petition debt due to the discontinuance of interest due to the Chapter 11 Cases, and

• $86 million in lower amortization of pre-petition debt issuances, amendment and extension costs and discounts due to reclassification of such amounts to liabilities subject to compromise in 2014,

partially offset by

• $405 million in higher expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of TCEH secured creditors in the year ended December 31, 2015 as compared to the post-petition period ended December 31, 2014;

• $66 million in mark-to-market net gains on interest rate swaps in 2014, and

• $26 million in higher interest expense on debtor-in-possession financing in the year ended December 31, 2015 as compared to the post-petition period ended December 31, 2014.

Reorganization items totaled $101 million and $520 million in 2015 and 2014, respectively. Activity in 2015 included $896 million related to the adjustment of expected allowed claims of pre-petition debt to remove issuance costs and debt premiums/discounts, $141 million in legal advisory and representation services, $69 million in other professional consulting and advisory services and $40 million in expense primarily related to net contract claim and assumption adjustments, partially offset by a $635 million gain associated with the impacts of the Settlement Agreement on certain pre-petition intercompany claims, debt reorganization adjustments of $382 million, interest reorganization adjustments of $20 million and a $19 million gain due to the settlement of liabilities under a management agreement with our Sponsors (see Note 19 to the Financial Statements). Activity in 2014 included a $277 million expense related to a liability adjustment arising from termination of interest rate swap agreements and natural gas hedging positions (see Note 17 to Financial Statements), $92 million in fees associated with completion of the TCEH DIP Facility discussed in Note 12 to Financial Statements, $65 million in legal advisory and representation services and $67 million in other professional consulting and advisory services. See Note 11 to the Financial Statements for additional discussion.

Income tax benefit totaled $879 million and $2.339 billion on pretax losses in 2015 and 2014, respectively. Excluding the $15 million income tax benefit recorded in 2014 related to an adjustment of reserves for uncertain tax positions for the 2007 tax year, the nondeductible goodwill impairment charges in both 2015 and 2014 and a valuation allowance of $210 million in 2015, the effective tax rate was 32.4% in 2015 and 33.2% in 2014. The decrease in the effective income tax rate was driven by higher nondeductible professional fees.

Net loss for the Competitive Electric segment decreased $1.582 billion to a net loss of $4.678 billion in 2015. The decrease primarily reflected the larger noncash impairment charges of certain long-lived assets in 2014, the decrease in interest expense, the decrease in depreciation and amortization expense and a decrease in reorganization items expense.

57

Competitive Electric Segment – Financial Results – Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Operating revenues increased $79 million, or 1%, to $5.978 billion in 2014.

Retail electricity revenues increased $74 million, or 2%, to $4.413 billion in 2014 reflecting a $59 million increase in sales volumes and $15 million in higher average prices. Retail sales volumes increased 1% reflecting higher sales growth in small and large business largely offset by a decline in residential volumes. The decrease in residential volumes reflects milder weather and a 1% decline in customer counts.

Wholesale electricity revenues decreased $15 million, or 1%, to $1.267 billion in 2014 reflecting a $179 million decrease due to lower sales volumes, largely offset by a $164 million increase due to higher average prices. A 14% decrease in wholesale sales volumes reflected lower generation volumes. Higher average prices were driven by an overall 16% increase in natural gas prices in 2014, predominately in the first half of the year.

Fuel, purchased power costs and delivery fees decreased $6 million to $2.842 billion in 2014. Lignite/coal fuel costs decreased $85 million reflecting lower generation volumes and higher lignite in the fuel blend, partially offset by higher western coal prices. Nuclear fuel costs decreased $26 million reflecting lower generation volumes and the discontinuance of DOE billing for spent fuel handling costs beginning in May 2014. Delivery fees increased $47 million primarily reflecting higher delivery rates. ERCOT ancillary fees were $26 million higher in 2014 due to higher prices that resulted from colder weather in early 2014 and decreasing supply being offered into the ancillary services market as the year progressed. Fuel for natural gas facilities and purchased power costs increased $24 million reflecting the effect of colder weather on natural gas prices and purchased power costs in the first quarter 2014.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $11 million in net gains and $54 million in net losses for the years ended December 31, 2014 and 2013, respectively, and includes the natural gas hedging positions discussed in Note 17 to the Financial Statements, as well as other hedging positions.

	Year Ended December 31, 2014
	Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Total
Hedging positions	$	397		$	(393	)	$	4
Trading positions	(10		)	17			7
Total	$	387		$	(376	)	$	11

	Year Ended December 31, 2013
	Net Realized Gains		Net Unrealized Losses			Total
Hedging positions	$	1,055	$	(1,090	)	$	(35	)
Trading positions	2		(21		)	(19		)
Total	$	1,057	$	(1,111	)	$	(54	)

Net realized gains on hedging and trading positions decreased by $670 million reflecting lower hedging gains from the natural gas hedging program in 2014 due to lower hedge prices.

The favorable change in net unrealized losses on hedging and trading positions of $735 million also reflected the lower gains in the natural gas hedging program. As realized gains were recognized, unrealized losses were recognized for the reversal of previously recognized unrealized gains.

Operating costs increased $33 million, or 4%, to $914 million in 2014. The increase was due to $57 million in higher nuclear maintenance costs primarily reflecting refueling outages for both generation units in 2014 as compared to only one unit in 2013 and maintenance costs incurred during the unplanned outage time experienced during the fall refueling outage, partially offset by lower maintenance and other costs of $14 million at lignite/coal fueled generation units and $5 million at natural gas fueled plants.

Depreciation and amortization expenses decreased $63 million, or 5%, to $1.270 billion reflecting reduced depreciation expense resulting from the effect of noncash impairments of certain long-lived assets and useful lives of certain lignite/coal generation equipment being longer than originally estimated.

58

SG&A expenses decreased $48 million, or 6%, to $708 million in 2014 reflecting $41 million in lower legal and other professional services costs associated with our debt restructuring activities prior to the Petition Date and $29 million in lower allocated Sponsor Group management fees, partially offset by $14 million in higher employee compensation and benefit costs. Legal and other professional services costs associated with the Chapter 11 Cases since the Petition Date are reported in reorganization items as discussed below.

In 2014 and 2013, noncash impairments of goodwill totaling $1.6 billion and $1.0 billion, respectively, were recorded as discussed in Note 5 to the Financial Statements.

In 2014 and 2013, noncash impairments of certain long-lived assets totaling $4.670 billion and $140 million, respectively, were recorded as discussed in Note 9 to the Financial Statements.

Other income totaled $16 million in 2014 and $9 million in 2013. See Note 8 to the Financial Statements.

Other deductions totaled $281 million in 2014 and $50 million in 2013. Other deductions in 2014 include a $183 million impairment of intangible assets related to favorable purchase contracts and $80 million related to environmental credits. Other deductions in 2013 include a $27 million impairment charge to write down equipment remaining from cancelled generation projects and $10 million in other asset impairments. See Notes 5 and 8 to the Financial Statements.

Interest expense and related charges decreased $263 million, or 13%, to $1.799 billion in 2014. The decrease reflected:

• $1.931 billion in lower interest expense on pre-petition debt due to the discontinuance of interest upon the Bankruptcy Filing and the termination of the interest rate swap agreements shortly after the Bankruptcy Filing, and

• $178 million in lower amortization of pre-petition debt issuances, amendment and extension costs and discounts due to reclassification of such amounts to liabilities subject to compromise,

partially offset by

• $987 million in lower mark-to-market net gains on interest rate swaps due to the termination of the agreements;

• $828 million in expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of secured creditors; and

• $37 million in interest expense on debtor-in-possession financing.

Reorganization items totaled $520 million in 2014 and included a $277 million expense related to adjustment of a liability arising from termination of interest rate swap agreements and natural gas hedging positions (see Note 17 to the Financial Statements), $92 million in fees associated with completion of the TCEH DIP Facility (see Note 12 to the Financial Statements), $67 million in professional consulting and advisory services fees, $65 million in legal advisory and representation services fees and $19 million primarily related to contract claim adjustments. See Note 11 to the Financial Statements for additional discussion.

Income tax benefit totaled $2.339 billion and $794 million on pretax losses in 2014 and 2013, respectively. Excluding the $15 million income tax benefit recorded in the third quarter of 2014 related to an adjustment of reserves for uncertain tax positions for the 2007 tax year, the $79 million in total income tax benefit recorded in 2013 related to resolution of IRS audit matters, the 2013 impairment of the assets of the nuclear generation development joint venture and the nondeductible goodwill impairment charges in both years, the effective tax rates were 33.2% and 34.0% in 2014 and 2013, respectively. The change in the effective tax rate is driven primarily by higher nondeductible legal and other professional services costs related to the Chapter 11 Cases in 2014. See Note 6 to the Financial Statements for discussion of uncertain tax positions. See Note 9 to the Financial Statements for discussion of the impairment of the joint venture's assets. See Note 5 to the Financial Statements for discussion of goodwill impairments. See Note 7 to the Financial Statements for reconciliation of these comparable effective rates to the US federal statutory rate.

Net loss for the Competitive Electric segment increased $3.951 billion to $6.260 billion in 2014. The increase primarily reflected the noncash impairments of certain long-lived assets, the noncash impairment of goodwill and reorganization items, partially offset by the decrease in interest expense and related charges.

Net loss attributable to noncontrolling interests of $107 million in 2013 represents the noncontrolling interest share of the impairment of the assets of the nuclear generation development joint venture.

59

Competitive Electric Segment – Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2015, 2014 and 2013. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $117 million in unrealized net gains, $368 million in unrealized net losses and $1.093 billion in unrealized net losses in 2015, 2014 and 2013, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio. The reduction in the net asset value in the portfolio in 2013 and 2014 primarily reflects the maturity and termination of positions in our long-term natural gas hedging program as a result of the Bankruptcy Filing. The portfolio consists primarily of economic hedges but also includes proprietary trading positions.

	Year Ended December 31,
	2015			2014			2013
Commodity contract net asset at beginning of period	$	180		$	525		$	1,664
Settlements/termination of positions (a)	(263		)	(385		)	(1,039		)
Changes in fair value of positions in the portfolio (b)	380			17			(54		)
Other activity (c)	(26		)	23			(46		)
Commodity contract net asset at end of period	$	271		$	180		$	525

____________

(a) Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month.

(b) Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month.

(c) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold.

Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values at December 31, 2015, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract net asset at December 31, 2015
Source of fair value	Less than 1 year			1-3 years			Total
Prices actively quoted	$	258		$	(1	)	$	257
Prices provided by other external sources	(26		)	3			(23		)
Prices based on models	31			6			37
Total	$	263		$	8		$	271

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FINANCIAL CONDITION

Operating Cash Flows

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 — Cash provided by operating activities totaled $3 million in 2015 compared to cash provided by operating activities of $404 million in 2014. The change of $401 million was driven by cash used to pay interest payments as a result of the EFIH Second Lien Note repayment (see Note 13 to the Financial Statements), higher cash used to pay for reorganization costs and higher cash used to reduce the net payables due to unconsolidated subsidiary (see Note 19 to the Financial Statements); partially offset by a decrease in cash used for margin deposits.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013 — Cash provided by operating activities totaled $404 million in 2014 compared to cash used in operating activities of $503 million in 2013. The change of $907 million was primarily driven by lower cash interest payments due to the discontinuation of interest paid on pre-petition debt (see Note 10 to the Financial Statements) partially offset by lower cash received from commodity hedging and trading activities reflecting lower gains on the natural gas hedging program and a decrease in cash used for margin deposits.

Depreciation and amortization expense reported in the statements of consolidated cash flows exceeded the amount reported in the statements of consolidated income (loss) by $142 million, $170 million and $166 million for the years ended December 31, 2015, 2014 and 2013, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statements of consolidated income (loss) consistent with industry practice, and amortization of intangible net assets arising from purchase accounting that is reported in various other statements of consolidated income (loss) line items including operating revenues and fuel and purchased power costs and delivery fees.

Financing Cash Flows

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 — Cash used in financing activities totaled $552 million in 2015 compared to cash provided by financing activities of $2.257 billion in 2014. Activity in 2015 reflected the repayments of principal and fees including a portion of the EFIH Second Lien Notes, charging liens and other repayments (see Notes 12 and 13 to the Financial Statements). Activity in 2014 reflected $4.989 billion in borrowings from the DIP Facilities, partially offset by $2.438 billion in repayments of EFIH First Lien Notes and $187 million in payments for fees associated with completion of the DIP Facilities.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013 — Cash provided by financing activities totaled $2.257 billion in 2014 compared to cash used in financing activities of $196 million in 2013. Activity in 2014 reflected $4.989 billion in borrowings from the DIP Facilities, partially offset by $2.438 billion in repayments of EFIH First Lien Notes and $187 million in payments for fees associated with completion of the DIP Facilities.

See Notes 12 and 13 to the Financial Statements for further details of the DIP Facilities and pre-petition debt.

Investing Cash Flows

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 — Cash used in investing activities totaled $593 million and $450 million in 2015 and 2014, respectively. Cash used in 2015 included capital expenditures (including nuclear fuel purchases) totaling $467 million. Cash used in 2014 included capital expenditures (including nuclear fuel purchases) totaling $463 million and a $350 million increase in restricted cash supporting letters of credit issued under the TCEH DIP Facility, partially offset by $394 million in restricted cash released from an escrow account when certain letters of credit were drawn.

Capital expenditures, including nuclear fuel, in 2015 totaled $467 million and consisted of:

• $230 million for major maintenance, primarily in existing generation operations;

• $82 million for environmental expenditures related to generation units;

• $123 million for nuclear fuel purchases, and

• $32 million for information technology and other corporate investments.

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Cash capital expenditures in 2015 are net of $2 million of reimbursements from the DOE related to dry cask storage. We expect to be reimbursed for our allowable costs of constructing dry cask storage for spent nuclear fuel through 2016 in accordance with a settlement agreement with the DOE.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013 — Cash used in investing activities totaled $450 million in 2014 compared to cash provided by investing activities of $3 million in 2013. The change of $453 million was largely driven by a net use of restricted cash of $636 million, partially offset by a reduction in capital expenditures (including nuclear fuel purchases) of $154 million. Cash provided by restricted cash activity in 2014 reflected a $391 million source of cash from an escrow account when certain letters of credit were drawn (see Note 13 to the Financial Statements), partially offset by a $350 million use of restricted cash supporting new letters of credit issued under the TCEH DIP Facility. Cash provided by restricted cash activity in 2013 reflected a $680 million cash source released from a collateral account to repay the balance of the TCEH Demand Notes (see Note 19 to the Financial Statements). The decrease in capital expenditures (including nuclear fuel purchases) of $154 million, to $463 million, was due to scope and timing of capital projects, including certain cancelled or deferred mining and generation projects, timing and costs of nuclear fuel purchases and pre-petition payments that were stayed due to the Bankruptcy Filing. Investing cash flows were also favorably affected by $40 million in cash used in 2013 to acquire the owner participant interest in a trust established to lease six natural gas-fired combustion turbines to TCEH.

Capital expenditures, including nuclear fuel, in 2014 totaled $463 million and consisted of:

• $248 million for major maintenance, primarily in existing generation operations;

• $76 million for environmental expenditures related to generation units;

• $77 million for nuclear fuel purchases, and

• $62 million for information technology, nuclear generation development and other corporate investments.

Cash capital expenditures in 2014 are net of $11 million of reimbursements from the DOE related to dry cask storage.

Debt Activity— Debt activities during the year ended December 31, 2015 are as follows (all amounts presented are principal, and settlements include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses). There were no additional borrowings during the year ended December 31, 2015.

	Settlements
TCEH (a)	$	(55	)
EFCH	(13		)
EFIH (b)	(481		)
EFH Corp. (c)	(12		)
Total	$	(561	)

___________

(a) Settlements include $34 million related to a noncash reduction of debt related to a capital lease that was restructured as an operating lease, $16 million of payments of principal at scheduled maturity dates and $5 million of payments of capital lease liabilities.

(b) Settlements include $445 million in cash repayments and $36 million in charging lien advances, both related to pre-petition debt as approved by the Bankruptcy Court (see Note 13 to the Financial Statements).

(c) Settlements include $7 million in charging lien advances and $5 million in noncash retirements.

See Notes 12 and 13 to the Financial Statements for further detail of debtor-in-possession borrowing facilities and pre-petition debt.

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Available Liquidity — The following table summarizes changes in available liquidity for the year ended December 31, 2015.

	Available Liquidity
	December 31, 2015		December 31, 2014		Change
Cash and cash equivalents – EFH Corp. and other	$	532	$	428	$	104
Cash and cash equivalents – EFIH	354		1,157		(803		)
Cash and cash equivalents – TCEH (a)	1,400		1,843		(443		)
Total cash and cash equivalents	2,286		3,428		(1,142		)
TCEH DIP Revolving Credit Facility (b)	1,950		1,950		—
Total liquidity (b)	$	4,236	$	5,378	$	(1,142	)

___________

(a) Cash and cash equivalents at December 31, 2015 and 2014 exclude $1.026 billion and $901 million, respectively, of restricted cash held for letter of credit support. The December 31, 2015 restricted cash balance includes $507 million under the TCEH pre-petition Letter of Credit Facility and $519 million under the TCEH DIP Facility.

(b) Pursuant to an order of the Bankruptcy Court, the TCEH Debtors may not have more than $1.650 billion of cash borrowings outstanding under the TCEH DIP Revolving Credit Facility without written consent of the TCEH committee of unsecured creditors and the ad hoc group of TCEH unsecured noteholders or further order of the Bankruptcy Court.

The decrease in available liquidity of $1.142 billion in the year ended December 31, 2015 was primarily driven by the EFIH Second Lien Note repayment totaling $750 million (see Note 13 to the Financial Statements). The decrease also reflected $467 million in capital expenditures (including nuclear fuel purchases) and $404 million of cash used to pay for reorganization expense in 2015, partially offset by $322 million from the distribution of earnings from Oncor Holdings. See discussion of cash flows above.

Subject to certain exceptions under the Bankruptcy Code, the Bankruptcy Filing automatically enjoined, or stayed, the continuation of most pending judicial or administrative proceedings and the filing of other actions against the Debtors or their property to recover on, collect or secure a claim arising prior to the Petition Date (including with respect to our pre-petition debt instruments).

The Bankruptcy Court approved final orders in June 2014 authorizing the DIP Facilities (see Note 12 to the Financial Statements). The TCEH DIP Facility provides for $3.375 billion in senior secured, super-priority financing. The EFIH First Lien DIP Facility provides for $5.4 billion in senior secured, super-priority financing.

We have incurred and expect to continue to incur significant costs associated with the Chapter 11 Cases and our reorganization, but we cannot accurately predict the effect the Chapter 11 Cases will have on our operations, liquidity, financial position and results of operations. Based upon our current internal financial forecasts, we believe that we will have sufficient amounts available under the DIP Facilities, plus cash generated from operations, to fund our anticipated cash requirements through at least the maturity dates of the DIP Facilities.

Debt Capacity — The TCEH DIP Facility permits, subject to certain terms, conditions and limitations, TCEH to request additional term loans or increases in the amount of the revolving credit commitment, not to exceed $750 million. The EFIH DIP Facility permits, subject to certain terms, conditions and limitations, EFIH to incur incremental junior lien subordinated debt in an aggregate amount not to exceed $3 billion.

Capital Expenditures — Capital expenditures and nuclear fuel purchases for 2016 are expected to total approximately $400 million and include:

• $275 million for investments in TCEH generation facilities, including approximately:

• $225 million for major maintenance and

• $50 million for environmental expenditures related to the MATS and other regulations;

• $75 million for nuclear fuel purchases and

• $50 million for information technology and other corporate investments.

Distributions of Earnings from Oncor Holdings and Related Considerations —Oncor Holdings' distributions of earnings to us totaled $322 million, $202 million and $213 million for the years ended December 31, 2015, 2014 and 2013, respectively. In February 2016, we received a distribution totaling $40 million from Oncor Holdings. See Note 4 to the Financial Statements for discussion of limitations on amounts Oncor can distribute to its members.

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EFH Corp., Oncor Holdings, Oncor and Oncor's minority investor are parties to a Federal and State Income Tax Allocation Agreement. Additional income tax amounts receivable or payable may arise in the normal course under that agreement.

Pension and OPEB Plan Funding — See Note 18 to the Financial Statements.

Liquidity Effects of Commodity Hedging and Trading Activities —We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. TCEH uses cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 12 to the Financial Statements for discussion of the TCEH DIP Facility.

Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variation margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other corporate purposes, including reducing borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. At December 31, 2015, essentially all cash collateral held was unrestricted. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted.

At December 31, 2015, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $6 million in cash has been posted with counterparties as compared to $9 million posted at December 31, 2014;

• $152 million in cash has been received from counterparties as compared to $26 million received at December 31, 2014;

• $230 million in letters of credit have been posted with counterparties, as compared to $329 million posted at December 31, 2014, and

• $3 million in letters of credit have been received from counterparties, as compared to $3 million received at December 31, 2014.

Income Tax Matters —EFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. EFH Corp. (parent entity) is a corporate member of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH is classified as a disregarded entity for US federal income tax purposes. Oncor is a partnership for US federal income tax purposes and is not a corporate member of the EFH Corp. consolidated group. Pursuant to applicable US Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.

EFH Corp. and certain of its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) are parties to a Federal and State Income Tax Allocation Agreement, which provides, among other things, that any corporate member or disregarded entity in the EFH Corp. group is required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. The Plan of Reorganization provides that the Debtors will reject this agreement at the effective time of the Plan of Reorganization. Under the terms of the Settlement Agreement, no further cash payments among the Debtors will be made in respect of federal income taxes. However, solely for accounting purposes, the EFH Corp. group continues to allocate federal income taxes among the entities that are parties to the Federal and State Income Tax Allocation Agreement. The Settlement Agreement did not alter the allocation and payment for state income taxes, which will continue to be settled.

EFH Corp., Oncor Holdings, Oncor and Oncor's third-party minority investor are parties to a separate Federal and State Income Tax Allocation Agreement, which governs the computation of federal income tax liability among such parties, and similarly provides, among other things, that each of Oncor Holdings and Oncor will pay EFH Corp. its share of an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. The Settlement Agreement had no impact on the tax sharing agreement among EFH Corp., Oncor Holdings and Oncor.

In June 2015, the Texas margin tax rate was permanently reduced from 1.0% to 0.75% effective for tax years beginning on or after January 1, 2015. Due to the rate reduction, deferred tax balances have been adjusted, resulting in an income tax benefit of $9 million recorded in the second quarter of 2015 (see Note 7 to the Financial Statements).

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We expect to generate additional net operating losses (NOLs) during our Chapter 11 Cases and estimate that we will have approximately $6.8 billion of NOLs at the time of emergence (assuming a June 30, 2016 emergence date). In addition to the NOLs generated through 2015 of approximately $2.8 billion, we expect to generate approximately $4.0 billion of NOLs during the six months ended June 30, 2016 (assuming a June 30, 2016 emergence date), primarily attributable to projected deferred interest deductions associated with debt extinguishment gains of approximately $2.3 billion that are expected to be recognized at emergence, projected deferred losses associated with termination of certain interest rate swaps of approximately $600 million, and projected net losses from ordinary course operations, including interest and tax depreciation deductions of approximately $1.1 billion. See Note 7 to the Financial Statements for detail of deferred income tax assets and liabilities and NOL carryforwards as of December 31, 2015. The projected amount of NOLs at emergence is an estimate that is subject to adjustment, including but not limited to, as a result of the ultimate outcome of the claim against Texas Transmission described in Note 2 to the Financial Statements. Of the projected $6.8 billion of NOLs, we intend to utilize up to approximately $6.3 billion of NOLs to offset taxable gain recognized in connection with the Plan of Reorganization that will result in a step-up in the tax basis of certain assets of TCEH, with the exact amount being utilized depending on, among other things, the fair value and tax basis of the assets included in the transaction resulting in the step-up in tax basis. It is expected that the assets of TCEH (including assets expected to be contributed to Reorganized TCEH as contemplated by the Plan of Reorganization at the time of emergence) will have an aggregate tax basis (exclusive of cash, net working capital, and certain other assets with minimal tax basis) of approximately $5.3 billion at the time of emergence (prior to giving effect to such step-up in tax basis). These amounts do not include any tax basis attributable to the La Frontera CCGTs that would be included in TCEH's assets as of June 30, 2016 if the acquisition of such assets occurs on or prior to such date (see Note 3 to the Financial Statements). The table below provides an estimate of the projected tax basis of certain of our assets at the time of emergence.

Plant/Asset	Projected Tax Basis as of June 30, 2016 of Depreciable Assets Placed in Service as of December 31, 2014		Projected Tax Basis of Inventory, Construction Work in Process and 2015 and 2016 Capital Expenditures as of June 30, 2016		Projected Tax Basis of Non-Depreciable Assets as of June 30, 2016		Projected Tax Basis as of June 30, 2016
Big Brown	$	120			$	50	$	170
Monticello	$	340	$	150	$	160	$	650
Martin Lake	$	420	$	270	$	220	$	910
Sandow 4	$	140	$	70			$	210
Sandow 5	$	540	$	20	$	50	$	610
Oak Grove	$	1,220	$	130	$	100	$	1,450
Comanche Peak	$	260	$	230	$	10	$	500
Nuclear fuel							$	210
Gas plants	$	140	$	10			$	150
TXU Energy	$	100	$	20			$	120
EFH Corporate Services, EFH Properties and other	$	90	$	180	$	10	$	280
Total							$	5,260

We are seeking a private letter ruling from the IRS regarding the proposed transaction that would result in the step-up in tax basis described above (see Note 2 to the Financial Statements). The determination of which assets will receive a step-up in tax basis depends upon the fair market value and the tax basis of such assets at the time of emergence under the Plan of Reorganization. Applicable GAAP guidance may require deferred tax assets reflected in our financial statements be subjected to a full or partial valuation allowance in future periods, unless and until a transaction occurs that results in the utilization of such deferred tax assets.

Income Tax Payments— In the next twelve months, income tax payments related to the Texas margin tax are expected to total approximately $38 million, and no payments or refunds of federal income taxes are expected. However, see Note 6 to the Financial Statements for discussion of future payments to the IRS that were formally assessed in 2015 related to the final conclusion of audit issues for tax years 2008 and 2009. Forecasted payments related to the Texas margin tax have been reduced due to the recent enactment of a rate reduction in the Texas margin tax rate. Income tax payments totaled $53 million, $55 million and $65 million for the years ended December 31, 2015, 2014 and 2013, respectively.

We cannot reasonably estimate the ultimate amounts and timing of tax payments associated with uncertain tax positions, but expect that no material federal income tax payments related to such positions will be made in the next twelve months (see Note 6 to the Financial Statements).

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Capitalization — At December 31, 2015, our capitalization ratios consisted of 244.2% borrowings under debtor-in-possession credit facilities (classified as due currently), debt (less amounts due currently) and pre-petition notes, loans and other debt reported as liabilities subject to compromise, and (144.2)% common stock equity. Total borrowings under debtor-in-possession credit facilities, debt and pre-petition notes, loans and other debt reported as liabilities subject to compromise to capitalization was 243.9% at December 31, 2015. At December 31, 2014, our capitalization ratios consisted of 185.4% debt, less amounts with contractual maturity dates in the next twelve months, and (85.4)% common stock equity. Total debt to capitalization was 185.3% at December 31, 2014.

Financial Covenants — The Bankruptcy Filing constituted an event of default and automatic acceleration under the agreements governing the pre-petition debt of EFH Corp. and its subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities. The creditors are, however, stayed from taking any action against the Debtors as a result of such defaults and accelerations under the Bankruptcy Code.

The agreement governing the TCEH DIP Facility includes a covenant that requires the Consolidated Superpriority Secured Net Debt to Consolidated EBITDA ratio not exceed 3.50 to 1.00, beginning with the test period ending June 30, 2014. The ratio was 1.39 to 1.00 at December 31, 2015, and TCEH is in compliance with this covenant. Consolidated Superpriority Secured Net Debt consists of outstanding term loans and revolving credit exposure under the TCEH DIP Facility less unrestricted cash. TCEH's Consolidated EBITDA (as used in the covenant contained in the agreement governing the TCEH DIP Facility) for the year ended December 31, 2015 totaled $1.628 billion. See Exhibit 99(b) for a reconciliation of TCEH's net income (loss) to Consolidated EBITDA. The EFIH DIP Facility also includes a minimum liquidity covenant pursuant to which EFIH cannot allow unrestricted cash (as defined in the EFIH DIP Facility) to be less than $150 million. EFIH is in compliance with this covenant.

See Note 12 to the Financial Statements for discussion of other covenants related to the DIP Facilities.

Collateral Support Obligations — The RCT has rules in place to assure that parties can meet their mining reclamation obligations, including through self-bonding when appropriate. In June 2014, the RCT agreed to accept a collateral bond from TCEH of up to $1.1 billion as a substitute for its self-bond. The collateral bond is a $1.1 billion carve out from the super-priority liens under the TCEH DIP Facility that will enable the RCT to be paid before the TCEH DIP Facility lenders in the event of a liquidation of TCEH's assets. Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts.

Certain transmission and distribution utilities in Texas are required to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, as a result of TCEH's below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. At December 31, 2015, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $21 million, with $6 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at December 31, 2015, TCEH posted letters of credit in the amount of $55 million, which are subject to adjustments.

ERCOT has rules in place to assure adequate creditworthiness of parties that participate in the day-ahead, real-time and congestion revenue rights markets operated by ERCOT. Under these rules, TCEH has posted collateral support, in the form of letters of credit, totaling $65 million at December 31, 2015 (which is subject to daily adjustments based on settlement activity with ERCOT).

Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred, two or more rating agencies downgrade Oncor's credit ratings below investment grade.

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Material Cross Default/Acceleration Provisions — Certain of our financing arrangements contain provisions that result in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenants that could or does result in an acceleration of payments due. Such provisions are referred to as "cross default" or "cross acceleration" provisions. The Bankruptcy Filing triggered defaults on our pre-petition debt obligations, but pursuant to the Bankruptcy Code, the creditors are stayed from taking any actions against the Debtors as a result of such defaults.

Under the terms of a TCEH rail car lease, which has $16 million in remaining lease payments at December 31, 2015 and terminates in 2020, if TCEH fails to perform under agreements causing its indebtedness in an aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease. Under the Bankruptcy Code, the lessors are stayed from taking any action against the Debtors as a result of the default.

Under the terms of another TCEH rail car lease, which has $6 million in remaining lease payments at December 31, 2015 and terminates in 2018, if payment obligations of TCEH in excess of $200 million in the aggregate to third-party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease. Under the Bankruptcy Code, the lessors are stayed from taking any action against the Debtors as a result of the default.

Contractual Obligations and Commitments — The following table summarizes the amounts and related maturities of our contractual cash obligations at December 31, 2015 (see Notes 12 and 14 to the Financial Statements for additional disclosures regarding these debt and noncancellable purchase obligations). Pre-petition liabilities subject to compromise (i.e., obligations incurred or accrued prior to the Bankruptcy Filing) are being administered by the Bankruptcy Court and are excluded from the table below due to the uncertainty related to when those obligations will mature. As part of the Chapter 11 Cases, we have rejected or renegotiated certain contractual obligations and commitments, including certain leases, commodity purchase and service agreements. These new terms are reflected in the table below.

Contractual Cash Obligations:	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years		Total
Debt – principal, including capital leases (a)	$	6,860	$	26	$	19	$	12	$	6,917
Debt – interest (b)	277		5		3		—		285
Operating leases	26		62		54		139		281
Obligations under commodity purchase and services agreements (c)	578		220		113		146		1,057
Total contractual cash obligations	$	7,741	$	313	$	189	$	297	$	8,540

___________

(a) Includes $6.825 billion of borrowings under the TCEH and EFIH DIP Facilities and $92 million principal amount of long-term debt, including capital leases. Excludes unamortized discounts and fair value premiums and discounts related to purchase accounting.

(b) Contractual and adequate protection interest payments are excluded.

(c) Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear related outsourcing and other purchase commitments. Amounts presented for variable priced contracts reflect the year-end 2015 price for all periods except where contractual price adjustment or index-based prices are specified.

The following are not included in the table above:

• liabilities subject to compromise (see Note 13 to the Financial Statements);

• arrangements between affiliated entities and intercompany debt (see Note 19 to the Financial Statements);

• 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);

• contracts that are cancellable without payment of a substantial cancellation penalty;

• employment contracts with management, and

• liabilities related to uncertain tax positions totaling $36 million (as well as accrued interest totaling $4 million) discussed in Note 6 to the Financial Statements as the ultimate timing of payment, if any, is not known.

Guarantees — See Note 14 to the Financial Statements for discussion of guarantees.

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OFF–BALANCE SHEET ARRANGEMENTS

See Notes 4 and 14 to the Financial Statements regarding VIEs and guarantees, respectively.

COMMITMENTS AND CONTINGENCIES

See Note 14 to the Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to the Financial Statements for discussion of changes in accounting standards.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Market risk is the risk that in the ordinary course of business we may experience a loss in value as a result of changes in market conditions that affect economic factors such as commodity prices, interest rates and counterparty credit. Our exposure to market risk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to hedge debt costs, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge commodity prices.

Risk Oversight

We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, position review, Value at Risk (VaR) methodologies and stress test scenarios. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validation and reporting, and portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

We have a corporate risk management organization that is headed by the Chief Financial Officer, who also functions as the Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits, and evaluates the risks inherent in our businesses.

Commodity Price Risk

The competitive business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. We actively manage the portfolio of generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices.

In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. We continuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

VaR Methodology — A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidence level and considers, among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.

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A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlation data. The tables below detail certain VaR measures related to various portfolios of contracts; however, we have excluded a table for proprietary trading activity due to the de minimis size of that activity.

VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period of five to 60 days.

	Year Ended December 31,
	2015		2014
Month-end average MtM VaR:	$	68	$	50
Month-end high MtM VaR:	$	97	$	129
Month-end low MtM VaR:	$	49	$	22

Earnings at Risk (EaR) — This measurement estimates the potential reduction of pretax earnings for the periods presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities), based on a 95% confidence level and an assumed holding period of five to 60 days.

	Year Ended December 31,
	2015		2014
Month-end average EaR:	$	45	$	27
Month-end high EaR:	$	92	$	60
Month-end low EaR:	$	26	$	4

The increase in the month end average MtM VaR risk measure during 2015 reflected increased net commodity positions and increased price volatility.

Interest Rate Risk

The following table provides information concerning our financial instruments at December 31, 2015 and 2014 that are sensitive to changes in interest rates, which consist of debtor-in-possession financing and pre-petition obligations that are fully secured and other obligations that are allowed to be paid as ordered by the Bankruptcy Court. Other pre-petition obligations (i.e., obligations incurred or accrued prior to the Bankruptcy Filing) are being administered by the Bankruptcy Court and are excluded from the table below due to the uncertainty related to when those obligations will mature. See Note 12 to the Financial Statements for further discussion of these financial instruments.

	2015 Total Carrying Amount			2015 Total Fair Value		2014 Total Carrying Amount			2014 Total Fair Value
Debt amounts (a):
Long-term debt not subject to compromise	$	87		$	89	$	121		$	119
Average interest rate	8.43		%			8.35		%
Borrowings under debtor-in-possession credit facilities	$	6,825		$	6,804	$	6,825		$	6,830
Average interest rate (b)	4.15		%			4.15		%
Total debt	$	6,912		$	6,893	$	6,946		$	6,949

___________

(a) Capital leases and the effects of unamortized premiums and discounts are excluded from the table.

(b) The weighted average interest rate presented is based on the rate in effect at December 31, 2015.

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Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty's financial condition, credit rating and other quantitative and qualitative credit criteria and authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties' financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and setoff. Credit enhancements such as parental guarantees, letters of credit, surety bonds, margin deposits and customer deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure.

Credit Exposure — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $790 million at December 31, 2015. The components of this exposure are discussed in more detail below.

Assets subject to credit risk at December 31, 2015 include $426 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $51 million. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

The remaining credit exposure arises from wholesale trade receivables and amounts associated with derivative instruments related to hedging and trading activities. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. At December 31, 2015, the exposure to credit risk from these counterparties totaled $364 million consisting of accounts receivable of $40 million and net asset positions related to commodity contracts of $324 million, after taking into account the netting provisions of the master agreements described above but before taking into account $150 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $214 milliondecreased$31 million in the year ended December 31, 2015.

Of this $214 million net exposure, 90% is with investment grade customers and counterparties, as determined by our internal credit evaluation process which includes publicly available information including major rating agencies' published ratings as well as internal credit methodologies and credit scoring models. Those customers and counterparties without an S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate an S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties based on, but not limited to, the assigned credit rating, margining and collateral management.

The following table presents the distribution of credit exposure at December 31, 2015. This credit exposure largely represents wholesale trade accounts receivable and net asset positions related to commodity contracts and hedging and trading activities (a substantial majority of which mature in 2015) recognized as derivative assets in the consolidated balance sheets, after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. Credit collateral includes cash and letters of credit, but excludes other credit enhancements such as liens on assets. See Note 17 to the Financial Statements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.

	Exposure Before Credit Collateral			Credit Collateral		Net Exposure
Investment grade	$	339		$	147	$	192
Below investment grade or no rating	25			3		22
Totals	$	364		$	150	$	214
Investment grade	93.1		%			89.7		%
Below investment grade or no rating	6.9		%			10.3		%

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In addition to the exposures in the table above, contracts classified as normal purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform. Nonperformance could have a material impact on future results of operations, liquidity and financial condition.

Significant (10% or greater) concentration of credit exposure exists with two counterparties, which represented 51% and 22% of the $214 million net exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, each of which is rated as investment grade, the counterparties' market role and deemed creditworthiness and the importance of our business relationship with the counterparties. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through the various ongoing risk management measures described above.

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including such matters as activities related to our bankruptcy, financial or operational projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "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 our actual results to differ materially from those projected in such forward-looking statements:

• our ability to satisfy the terms and conditions set forth in, and to receive the required approvals required under, the Plan of Reorganization, the Merger and Purchase Agreement and the Plan Support Agreement;

• the breach by one or more of our counterparties under the Merger and Purchase Agreement and/or the Plan Support Agreement;

• the effectiveness of the overall restructuring activities pursuant to the Chapter 11 Cases, including the Plan of Reorganization, and any additional strategies we employ to address our liquidity and capital resources;

• the extent to which the Chapter 11 Cases cause customers, suppliers and others with whom we have commercial relationships to lose confidence in us, which may make it more difficult for us to obtain and maintain such commercial relationships on competitive terms;

• difficulties we may face in retaining and motivating our key employees through the bankruptcy process, and difficulties we may face in attracting new employees;

• the significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations;

• our ability to remain in compliance with the requirements of the DIP Facilities;

• our ability to maintain or obtain sufficient financing sources for our operations during the pendency of the Chapter 11 Cases and our ability to obtain sufficient exit financing to fund any Chapter 11 plan of reorganization;

• limitations on our ability to utilize previously incurred federal net operating losses or alternative minimum tax credits;

• the actions and decisions of creditors, regulators and other third parties that have an interest in the Chapter 11 Cases or reorganization that may be inconsistent with, or interfere with, our business and/or plans;

• the duration and related costs of the Chapter 11 Cases;

• the actions and decisions of regulatory authorities relative to the Plan of Reorganization;

• restrictions on our operations due to the terms of our debt agreements, including the DIP Facilities, and restrictions imposed by the Bankruptcy Court;

• our ability to obtain any required regulatory consent necessary to implement any Chapter 11 plan of reorganization;

• prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the FERC, the NERC, the TRE, the PUCT, the RCT, the NRC, the EPA, the TCEQ, the US Mine Safety and Health Administration and the CFTC, with respect to, among other things:

◦ allowed prices;

◦ allowed rates of return;

◦ permitted capital structure;

◦ industry, market and rate structure;

◦ purchased power and recovery of investments;

◦ operations of nuclear generation facilities;

◦ operations of fossil fueled generation facilities;

◦ operations of mines;

◦ self-bonding requirements;

◦ acquisition and disposal of assets and facilities;

◦ development, construction and operation of facilities;

◦ decommissioning costs;

◦ present or prospective wholesale and retail competition;

◦ changes in tax laws and policies;

◦ changes in and compliance with environmental and safety laws and policies, including the CSAPR, MATS, regional haze program implementation and greenhouse gas and other climate change initiatives, and

◦ clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith;

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• legal and administrative proceedings and settlements, including the legal proceedings arising out of the Chapter 11 Cases;

• general industry trends;

• economic conditions, including the impact of an economic downturn;

• our ability to collect trade receivables from counterparties;

• our ability to attract and retain profitable customers;

• our ability to profitably serve our customers;

• restrictions on competitive retail pricing;

• changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;

• changes in prices of transportation of natural gas, coal, fuel oil and other refined products;

• changes in the ability of vendors to provide or deliver commodities as needed;

• changes in market heat rates in the ERCOT electricity market;

• our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;

• weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, wars or terrorist or cyber security threats or activities;

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

• access to adequate transmission facilities to meet changing demands;

• changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;

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

• commercial bank market and capital market conditions and the potential impact of disruptions in US and international credit markets;

• access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets;

• our ability to generate sufficient cash flow to make interest or adequate protection payments, or refinance, our debt instruments, including the DIP Facilities;

• competition for new energy development and other business opportunities;

• inability of various counterparties to meet their obligations with respect to our financial instruments;

• changes in technology (including large scale electricity storage) used by and services offered by us;

• changes in electricity transmission that allow additional electricity generation to compete with our generation assets;

• 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 medical and dental benefits, pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure under ERISA;

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

• actions by credit rating agencies.

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 or circumstances. 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.

INDUSTRY AND MARKET INFORMATION

The industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT, the PUCT and NYMEX. We did not commission any of these publications or reports. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly, while we believe that such internal and external research is reliable, it has not been verified by any independent sources, and we make no assurances that the predictions contained therein are accurate.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energy Future Holdings Corp. (Debtor-in-Possession)

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Energy Future Holdings Corp. and subsidiaries (Debtor-in-Possession) ("EFH Corp.") as of December 31, 2015 and 2014, and the related statements of consolidated income (loss), comprehensive income (loss), cash flows and equity for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and financial statement schedule are the responsibility of EFH Corp.'s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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 Energy Future Holdings Corp. and subsidiaries (Debtor-in-Possession) as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, on April 29, 2014 Energy Future Holdings Corp. and the substantial majority of its direct and indirect subsidiaries, excluding Oncor Electric Delivery Holdings Company LLC and its subsidiaries, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of the bankruptcy proceedings. In particular, such financial statements do not purport to show (1) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (2) as to prepetition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (3) as to shareholder accounts, the effect of any changes that may be made in the capitalization of EFH Corp.; or (4) as to operations, the effect of any changes that may be made in its business.

The accompanying consolidated financial statements for the years ended December 31, 2015 and 2014 have been prepared assuming that EFH Corp. will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, EFH Corp.’s ability to continue as a going concern is contingent upon its ability to comply with the financial and other covenants contained in the DIP Facilities described in Note 12, its ability to obtain new debtor in possession financing in the event the DIP Facilities were to expire during the pendency of the Chapter 11 Cases, its ability to complete a Chapter 11 plan of reorganization in a timely manner, including obtaining applicable regulatory approvals required for such plan, and its ability to obtain any exit financing needed to implement such plan, among other factors. These circumstances and uncertainties inherent in the bankruptcy proceedings raise substantial doubt about EFH Corp.’s ability to continue as a going concern. Management’s plans concerning these matters are also discussed in Note 2 to the consolidated financial statements. The consolidated financial statements do not include adjustments that might result from the outcome of these uncertainties.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EFH Corp.'s internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2016 expressed an unqualified opinion on EFH Corp.'s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Dallas, Texas

February 29, 2016

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION

STATEMENTS OF CONSOLIDATED INCOME (LOSS)

	Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Operating revenues	$	5,370		$	5,978		$	5,899
Fuel, purchased power costs and delivery fees	(2,692		)	(2,842		)	(2,848		)
Net gain (loss) from commodity hedging and trading activities	334			11			(54		)
Operating costs	(834		)	(914		)	(881		)
Depreciation and amortization	(864		)	(1,283		)	(1,355		)
Selling, general and administrative expenses	(745		)	(794		)	(822		)
Impairment of goodwill (Note 5)	(2,200		)	(1,600		)	(1,000		)
Impairment of long-lived assets (Note 9)	(2,541		)	(4,670		)	(140		)
Other income (Note 8)	35			31			26
Other deductions (Note 8)	(95		)	(276		)	(53		)
Interest income	1			1			1
Interest expense and related charges (Note 10)	(1,760		)	(2,201		)	(2,704		)
Reorganization items (Note 11)	(1,355		)	(815		)	—
Loss before income taxes and equity in earnings of unconsolidated subsidiaries	(7,346		)	(9,374		)	(3,931		)
Income tax benefit (Note 7)	1,670			2,619			1,271
Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 4)	334			349			335
Net loss	(5,342		)	(6,406		)	(2,325		)
Net loss attributable to noncontrolling interests	—			—			107
Net loss attributable to EFH Corp.	$	(5,342	)	$	(6,406	)	$	(2,218	)

See Notes to the Financial Statements.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Net loss	$	(5,342	)	$	(6,406	)	$	(2,325	)
Other comprehensive income (loss), net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax (expense) benefit of $(4), $12 and $5) (Note 18)	7			(21		)	(8		)
Cash flow hedges derivative value net loss related to hedged transactions recognized during the period (net of tax benefit of $—, $1 and $3)	2			1			6
Net effects related to Oncor — reported in equity in earnings of unconsolidated subsidiaries (net of tax)	(5		)	(47		)	(14		)
Total other comprehensive income (loss)	4			(67		)	(16		)
Comprehensive loss	(5,338		)	(6,473		)	(2,341		)
Comprehensive loss attributable to noncontrolling interests	—			—			107
Comprehensive loss attributable to EFH Corp.	$	(5,338	)	$	(6,473	)	$	(2,234	)

See Notes to the Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION STATEMENTS OF CONSOLIDATED CASH FLOWS
	Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Cash flows — operating activities:
Net loss	$	(5,342	)	$	(6,406	)	$	(2,325	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation and amortization	1,006			1,453			1,521
Deferred income tax benefit, net	(1,484		)	(2,539		)	(992		)
Income tax benefit due to IRS audit resolutions (Note 6)	—			7			(305		)
Impairment of goodwill (Note 5)	2,200			1,600			1,000
Impairment of long-lived assets and nuclear generation joint venture (Note 9)	2,541			4,670			140
Noncash adjustment for estimated allowed claims related to debt (Note 11)	926			—			—
Contract claims adjustments (Note 11)	52			20			—
Management fee settlement adjustment (Note 11 and 19)	(49		)	—			—
Unrealized net (gain) loss from mark-to-market of commodity positions	(119		)	370			1,091
Unrealized net gain from mark-to-market of interest rate swaps (Note 10)	—			(1,303		)	(1,058		)
Liability adjustment arising from termination of interest rate swaps (Note 17)	—			278			—
Noncash realized loss on termination of interest rate swaps (Note 10)	—			1,237			—
Noncash realized gain on termination of natural gas positions (Note 17)	—			(117		)	—
Fees paid on EFIH Second Lien Notes repayment and DIP Facilities (Notes 12 and 13) (reported as financing activities)	37			187			—
Loss on exchange and settlement of EFIH First Lien Notes (Note 12)	—			108			—
Interest expense on toggle notes paid in additional principal (Note 10)	—			65			176
Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 10)	—			72			235
Equity in earnings of unconsolidated subsidiaries	(334		)	(349		)	(335		)
Distributions of earnings from unconsolidated subsidiaries (Note 4)	322			202			213
Impairment of intangible and other assets (Note 5)	84			263			37
Other, net	65			63			82
Changes in operating assets and liabilities:
Accounts receivable — trade	17			63			(33		)
Inventories	34			(67		)	(6		)
Accounts payable — trade	41			108			11
Payables due to unconsolidated subsidiary	(33		)	109			109
Commodity and other derivative contractual assets and liabilities	30			(25		)	49
Margin deposits, net	129			(192		)	(320		)
Accrued interest	5			519			(8		)
Other — net assets	20			(43		)	131
Other — net liabilities	(145		)	51			84
Cash provided by (used in) operating activities	$	3		$	404		$	(503	)
Cash flows — financing activities:
Repayments/repurchases of debt (Notes 12 and 13)	$	(515	)	$	(2,546	)	$	(187	)
Fees paid on EFIH Second Lien Notes repayment and DIP Facilities (Notes 12 and 13)	(37		)	(187		)	—
Proceeds from DIP Facilities before fees paid (Note 12)	—			4,989			—
Other, net	—			1			(9		)
Cash provided by (used in) financing activities	(552		)	2,257			(196		)

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION STATEMENTS OF CONSOLIDATED CASH FLOWS
	Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Cash flows — investing activities:
Capital expenditures	(344		)	(386		)	(501		)
Nuclear fuel purchases	(123		)	(77		)	(116		)
Acquisition of combustion turbine trust interest	—			—			(40		)
Restricted cash investment used to settle TCEH Demand Notes (Note 19)	—			—			680
Other changes in restricted cash	(122		)	42			(2		)
Proceeds from sales of nuclear decommissioning trust fund securities (Note 21)	401			314			175
Investments in nuclear decommissioning trust fund securities (Note 21)	(418		)	(331		)	(191		)
Other, net	13			(12		)	(2		)
Cash provided by (used in) investing activities	(593		)	(450		)	3
Net change in cash and cash equivalents	(1,142		)	2,211			(696		)
Cash and cash equivalents — beginning balance	3,428			1,217			1,913
Cash and cash equivalents — ending balance	$	2,286		$	3,428		$	1,217

See Notes to the Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION CONSOLIDATED BALANCE SHEETS
	December 31,
	2015			2014
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	2,286		$	3,428
Restricted cash (Note 21)	524			6
Trade accounts receivable — net (Note 21)	533			589
Inventories (Note 21)	428			468
Commodity and other derivative contractual assets (Note 17)	465			492
Other current assets	87			100
Total current assets	4,323			5,083
Restricted cash (Note 21)	507			901
Receivable from unconsolidated subsidiary (Note 19)	—			47
Investment in unconsolidated subsidiary (Note 4)	6,064			6,058
Other investments (Note 21)	984			995
Property, plant and equipment — net (Note 21)	9,430			12,397
Goodwill (Note 5)	152			2,352
Identifiable intangible assets — net (Note 5)	1,166			1,315
Accumulated deferred income taxes (Note 7)	609			—
Other noncurrent assets	95			100
Total assets	$	23,330		$	29,248
LIABILITIES AND EQUITY
Current liabilities:
Borrowings under debtor-in-possession credit facilities (Note 12)	$	6,825		$	—
Long-term debt due currently (Note 12)	35			39
Trade accounts payable	413			406
Net payables due to unconsolidated subsidiary (Note 19)	204			237
Commodity and other derivative contractual liabilities (Note 17)	203			316
Margin deposits related to commodity contracts	152			26
Accumulated deferred income taxes (Note 7)	—			135
Accrued taxes	134			157
Accrued interest	121			119
Other current liabilities	425			360
Total current liabilities	8,512			1,795
Borrowings under debtor-in-possession credit facilities (Note 12)	—			6,825
Long-term debt, less amounts due currently (Note 12)	60			128
Liabilities subject to compromise (Note 13)	37,786			37,432
Accumulated deferred income taxes (Note 7)	—			713
Other noncurrent liabilities and deferred credits (Note 21)	2,033			2,078
Total liabilities	48,391			48,971
Commitments and Contingencies (Note 14)
Equity (Note 15):
Common stock (shares outstanding 2015 — 1,669,861,379; 2014 — 1,669,861,379)	2			2
Additional paid-in capital	7,968			7,968
Retained deficit	(32,905		)	(27,563		)
Accumulated other comprehensive loss	(126		)	(130		)
Total equity	(25,061		)	(19,723		)
Total liabilities and equity	$	23,330		$	29,248

See Notes to the Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION

STATEMENTS OF CONSOLIDATED EQUITY

	Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Common stock stated value of $0.001 effective May 2009 (number of authorized shares — 2,000,000,000):
Balance at beginning of period	$	2		$	2		$	2
Balance at end of period (number of shares outstanding: 2015 — 1,669,861,379; 2014 — 1,669,861,379; 2013 — 1,669,861,383)	2			2			2
Additional paid-in capital:
Balance at beginning of period	7,968			7,962			7,959
Effects of stock-based incentive compensation plans	—			6			7
Common stock repurchases	—			—			(5		)
Other	—			—			1
Balance at end of period	7,968			7,968			7,962
Retained earnings (deficit):
Balance at beginning of period	(27,563		)	(21,157		)	(18,939		)
Net loss attributable to EFH Corp.	(5,342		)	(6,406		)	(2,218		)
Balance at end of period	(32,905		)	(27,563		)	(21,157		)
Accumulated other comprehensive loss, net of tax effects:
Pension and other postretirement employee benefit liability adjustments:
Balance at beginning of period	(77		)	(7		)	17
Change in unrecognized (gains) losses related to pension and OPEB plans	1			(70		)	(24		)
Balance at end of period	(76		)	(77		)	(7		)
Amounts related to dedesignated cash flow hedges:
Balance at beginning of period	(53		)	(56		)	(64		)
Change during the period	3			3			8
Balance at end of period	(50		)	(53		)	(56		)
Total accumulated other comprehensive loss at end of period	(126		)	(130		)	(63		)
EFH Corp. shareholders' equity at end of period (Note 15)	(25,061		)	(19,723		)	(13,256		)
Noncontrolling interests in subsidiaries (Note 15):
Balance at beginning of period	—			1			102
Net loss attributable to noncontrolling interests	—			—			(107		)
Investments by noncontrolling interests	—			1			6
Other	—			(2		)	—
Noncontrolling interests in subsidiaries at end of period	—			—			1
Total equity at end of period	$	(25,061	)	$	(19,723	)	$	(13,255	)

See Notes to the Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

References in this report to "we," "our," "us" and "the Company" are to EFH Corp. and/or its subsidiaries, as apparent in the context. See Glossary for defined terms.

EFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through its TCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity operations. TCEH is a wholly owned subsidiary of EFCH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Oncor Holdings, a holding company that holds an approximate 80% equity interest in Oncor, is a wholly owned subsidiary of EFIH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor Holdings and its subsidiaries (the Oncor Ring-Fenced Entities) are not consolidated in EFH Corp.'s financial statements in accordance with consolidation accounting standards related to variable interest entities (VIEs) (see Note 4).

Various ring-fencing measures have been taken to enhance the credit quality of Oncor. Such measures include, among other things: the sale in November 2008 of a 19.75% equity interest in Oncor to Texas Transmission; maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor's 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, 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. Moreover, Oncor's operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.

Consistent with the ring-fencing measures discussed above, the assets and liabilities of the Oncor Ring-Fenced Entities have not been, and are not expected to be, substantively consolidated with the assets and liabilities of the Debtors in the Chapter 11 Cases.

We have two reportable segments: the Competitive Electric segment, consisting largely of TCEH, and the Regulated Delivery segment, consisting largely of our investment in Oncor. See Note 20 for further information concerning reportable business segments.

Chapter 11 Cases

On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities (collectively, the Debtors), filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). In September 2015, the Debtors filed the Fifth Plan of Reorganization (which was amended by the Sixth Plan of Reorganization in November 2015) and the Disclosure Statement. The Disclosure Statement was approved by the Bankruptcy Court in September 2015.

Following the approval of the Disclosure Statement by the Bankruptcy Court, the Debtors solicited the vote of their required creditors for approval of the Plan of Reorganization. In October 2015, the required creditors voted to approve the Plan of Reorganization. The Bankruptcy Court confirmed the Plan of Reorganization in December 2015. See Note 2 for further discussion regarding the Chapter 11 Cases, the Plan of Reorganization and the Disclosure Statement.

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Basis of Presentation, Including Application of Bankruptcy Accounting

The consolidated financial statements have been prepared in accordance with US GAAP. The consolidated financial statements have been prepared as if EFH Corp. is a going concern and contemplate the realization of assets and liabilities in the normal course of business. The consolidated financial statements reflect the application of Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, Reorganizations. During the pendency of the Chapter 11 Cases, the Debtors will operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. ASC 852 applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. See Notes 11 and 13 for discussion of these accounting and reporting changes.

Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method (see Note 4). All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

Use of Estimates

Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements and estimates of expected allowed claims. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.

Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage our commodity price and interest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses, unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the consolidated balance sheets. This recognition is referred to as mark-to-market accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities. We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 16 and 17 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accounting standards related to derivative instruments and hedging activities, we may elect the normal purchase and sale exemption. A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.

Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for hedge accounting, which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. At December 31, 2015 and 2014, there were no derivative positions accounted for as cash flow or fair value hedges. Accumulated other comprehensive loss includes amounts related to interest rate swaps previously designated as cash flow hedges that are being reclassified to net loss as the hedged transactions impact net loss (see Note 17).

Realized and unrealized gains and losses from transacting in energy-related derivative instruments are primarily reported in the statements of consolidated income (loss) in net gain (loss) from commodity hedging and trading activities.

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Revenue Recognition

We record revenue from electricity sales and delivery fees under the accrual method of accounting. Revenues are recognized when electricity or delivery fees are provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue).

We report physically delivered commodity sales and purchases in the statements of consolidated income (loss) on a gross basis in revenues and fuel, purchased power and delivery fees, respectively, and we report all other commodity related contracts and financial instruments (primarily derivatives) in the statements of consolidated income (loss) on a net basis in net gain (loss) from commodity hedging and trading activities. Volumes under bilateral purchase and sales contracts, including contracts intended as hedges, are not scheduled as physical power with ERCOT. Accordingly, unless the volumes represent physical deliveries to customers or purchases from counterparties, such contracts are reported net in the statements of consolidated income (loss) in net gain (loss) from commodity hedging and trading activities instead of reported gross as wholesale revenues or purchased power costs. If volumes delivered to our retail and wholesale customers are less than our generation volumes (as determined on a daily settlement basis), we record additional wholesale revenues, and if volumes delivered to our retail and wholesale customers exceed our generation volumes, we record additional purchased power costs. The additional wholesale revenues or purchased power costs are offset in net gain (loss) from commodity hedging and trading activities.

Impairment of Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 9 for discussion of impairments of certain long-lived assets.

We evaluate investments in unconsolidated subsidiaries for impairment when factors indicate that a decrease in the value of the investment has occurred that is not temporary. Indicators that should be evaluated for possible impairment of investments include recurring operating losses of the investee or fair value measures that are less than carrying value. Any impairment recognition is based on fair value that is not reflective of temporary conditions. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable.

Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 5 for additional information.

Goodwill and Intangible Assets with Indefinite Lives

We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually (at December 1), or when indications of impairment exist. See Note 5 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations and goodwill impairments.

Amortization of Nuclear Fuel

Amortization of nuclear fuel is calculated on the units-of-production method and is reported as fuel costs.

Major Maintenance

Major maintenance costs incurred during generation plant outages and the costs of other maintenance activities are charged to expense as incurred and reported as operating costs.

Defined Benefit Pension Plans and OPEB Plans

We offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the company and also offer pension benefits to eligible employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. See Notes 18 and 19 for additional information regarding pension and OPEB plans, including a discussion of the separation of the EFH Corp. and Oncor OPEB plans effective July 1, 2014.

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Sales and Excise Taxes

Sales and excise taxes are accounted for as a "pass through" item on the consolidated balance sheets with no effect on the statements of consolidated income (loss); i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction.

Franchise and Revenue-Based Taxes

Unlike sales and excise taxes, franchise and gross receipt taxes are not a "pass through" item. These taxes are assessed to us by state and local government bodies, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and gross receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense in our statements of consolidated income (loss).

Income Taxes

EFH Corp. files a consolidated US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. Oncor is a partnership for US federal income tax purposes and is not a corporate member of the EFH Corp. consolidated group. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities as required under accounting rules. See Note 7. We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 6.

Accounting for Contingencies

Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. As part of our Chapter 11 Cases we have received numerous pre-petition claims, many of which are unsubstantiated or irrelevant to our business operations. Further, at this time, some of those claims might be relevant but are not reasonably estimable. See Notes 2 and 14 for a discussion of contingencies.

Restricted Cash

The terms of certain agreements require the restriction of cash for specific purposes. See Notes 12, 13 and 21 for more details regarding restricted cash.

Property, Plant and Equipment

As a result of purchase accounting, carrying amounts of property, plant and equipment related to competitive businesses were adjusted to estimated fair values at the Merger date. Subsequent additions have been recorded at cost. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 10.

Depreciation of our property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on a component asset-by-asset basis. Estimated depreciable lives are based on management's estimates of the assets' economic useful lives. See Note 21.

Asset Retirement Obligations

A liability is initially recorded at fair value for an asset retirement obligation associated with the retirement of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. Over time, the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. See Note 21.

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Inventories

Inventories are reported at the lower of cost (on a weighted average basis) or market unless expected to be used in the generation of electricity.

Investments

Investments in a nuclear decommissioning trust fund are carried at current market value in the consolidated balance sheets. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value. See Note 21 for discussion of these and other investments.

Noncontrolling Interests

See Note 15 for discussion of accounting for noncontrolling interests in subsidiaries.

Changes in Accounting Standards

In April 2014, the FASB issued Accounting Standards Update No. 2014-08 (ASU 2014-08), Presentation of Financial Statements (Topic 205) and Property Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which changes the requirements for reporting discontinued operations. The ASU states that a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity's operations andfinancial results when the component of an entity or group of components of an entity meets the criteria to be classified as held for sale, is disposed of by sale, or is disposed of other than by sale. The amendments in this ASU also require additional disclosures about discontinued operations. ASU 2014-08 was effective for the Company for the first quarter of 2015. This new requirement is relevant to our presentation of the equity method investment in Oncor and our presentation of TCEH. The new guidance eliminated a scope exception previously applicable to equity method investments, resulting in the requirement of further analysis of the presentation of the Oncor equity method investment. Based on our analysis, ASU 2014-08 will not materially affect our results of operations, financial position, or cash flows, unless a sale of our Oncor investment and/or a spin-off of TCEH is approved by each of the Bankruptcy Court and all of the other regulatory entities with approval authority (see Note 2), at which time presentation as discontinued operations may be appropriate.

In April 2015, the FASB issued Accounting Standards Update 2015-03 (ASU 2015-03), Simplifying Balance Sheet Presentation by Presenting Debt Issuance Costs as a Deduction from Recognized Debt Liability. The ASU is effective for annual reporting periods, including interim reporting periods, beginning after December 15, 2015. The new standard requires debt issuance costs to be classified as reductions to the face value of the related debt. We do not expect ASU 2015-03 to materially affect our financial position until we issue new debt. In August 2015, the FASB issued Accounting Standards Update 2015-15 (ASU 2015-15), Interest-Imputation of Interest (Topic 835-30) Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line of Credit Arrangements. ASU 2015-15 provides guidance on the presentation of debt issuance costs associated with line-of-credit arrangements and allows an entity to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit.

In November 2015, the FASB issued Accounting Standards Update 2015-17 (ASU 2015-17), Balance Sheet Classification of Deferred Taxes. The ASU simplifies the presentation of deferred income taxes by requiring that deferred tax assets and liabilities be classified as noncurrent in a statement of financial position. We early adopted ASU 2015-17 effective December 31, 2015 on a prospective basis. Adoption of this ASU resulted in a reclassification of our net current deferred tax asset and liability to the net noncurrent deferred tax asset and liability in our consolidated balance sheet as of December 31, 2015. No prior periods were retrospectively adjusted.

In February 2016, the FASB issued Accounting Standards Update 2016-2 (ASU 2016-2), Leases. The ASU amends previous GAAP to require the recognition of lease assets and liabilities for operating leases. The ASU will be effective for fiscal years beginning after December 15, 2018, including interim periods within those years. We are currently evaluating the impact of this ASU on our financial statements.

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2. CHAPTER 11 CASES

On the Petition Date, EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. During the pendency of the Chapter 11 Cases, the Debtors will operate their businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

The Bankruptcy Filing resulted primarily from the adverse effects on EFH Corp.'s competitive businesses of lower wholesale electricity prices in ERCOT driven by the sustained decline in natural gas prices since mid-2008. Further, the natural gas hedges that TCEH entered into when forward market prices of natural gas were significantly higher than current prices had largely matured before the remaining positions were terminated shortly after the Bankruptcy Filing. These market conditions challenged the profitability and operating cash flows of EFH Corp.'s competitive businesses and resulted in the inability to support their significant interest payments and debt maturities, including the remaining debt obligations due in 2014, and the inability to refinance and/or extend the maturities of their outstanding debt.

Plan of Reorganization

A Chapter 11 plan of reorganization, among other things, determines the rights and satisfaction of claims of various creditors and security holders of an entity operating under the protection of the Bankruptcy Court. In order for the Debtors to emerge successfully from the Chapter 11 Cases as reorganized companies, they must obtain approval from the Bankruptcy Court and certain of their respective creditors for a Chapter 11 plan of reorganization. In September 2015, the Debtors filed the Plan of Reorganization and the Disclosure Statement. The Disclosure Statement was approved by the Bankruptcy Court in September 2015. In October 2015, the Debtors filed the Plan Supplement. In October 2015, the Plan of Reorganization was approved by the required creditors, and in December 2015, the Plan of Reorganization was confirmed by the Bankruptcy Court.

In general, the Plan of Reorganization contemplates a structure that involves a tax-free deconsolidation or tax-free spin-off of TCEH from EFH Corp. (Reorganized TCEH Spin-Off), immediately followed by the acquisition of reorganized EFH Corp. financed by existing TCEH creditors and third-party investors. Pursuant to the Plan of Reorganization and subject to certain conditions and required regulatory approvals, among other things:

• TCEH will execute a transaction that will result in a partial step-up in the tax basis of certain TCEH assets;

• the Reorganized TCEH Spin-Off will occur;

• a consortium (collectively, the Investor Group) consisting of certain TCEH creditors, an affiliate of Hunt Consolidated, Inc. (Hunt) and certain other investors designated by Hunt will acquire (the EFH Acquisition) reorganized EFH Corp. (Reorganized EFH);

• in connection with the EFH Acquisition, (i) the Investor Group will raise up to approximately $12.6 billion of equity and debt financing to invest in Reorganized EFH, (ii) a successor to Reorganized EFH will be converted to a real estate investment trust (REIT) under the Internal Revenue Code and (iii) all allowed claims against the EFH Corp. debtors and the EFIH Debtors will receive treatment rendering them unimpaired (excluding any claims derived from or based upon make-whole, applicable premium, redemption premium or other similar payment provisions, or any other alleged premiums, fees, or claims relating to the repayment of claims and certain unsecured claims for post-petition interest in excess of the federal judgment rate of interest, each of which will be disallowed under the Plan of Reorganization), and

• the Debtors, the Sponsor Group, certain settling TCEH first lien creditors, certain settling TCEH second lien creditors, certain settling TCEH unsecured creditors and the official committee of unsecured creditors of the TCEH Debtors (collectively, the Settling Parties) agreed to settle certain disputes, claims and causes of action pursuant to the Settlement Agreement (described below).

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Plan Support Agreement

In August 2015 (as amended in September 2015), each of the Debtors entered into a Plan Support Agreement (Plan Support Agreement) with various of their respective creditors, the Sponsor Group, the official committee of unsecured creditors of the TCEH Debtors and the Investor Group in order to effect an agreed upon restructuring of the Debtors pursuant to the Plan of Reorganization. Pursuant to the Plan Support Agreement, the parties agreed, subject to the terms and conditions contained in the Plan Support Agreement, to support the Debtors' Plan of Reorganization. The Bankruptcy Court approved the Debtors' entry into the Plan Support Agreement in September 2015.

Pursuant to the Plan Support Agreement, certain of the parties to the Plan Support Agreement are required to not object to or interfere with an alternative plan of reorganization even if the EFH Acquisition is not completed so long as such plan meets certain minimum conditions. All or part of the Plan Support Agreement may be terminated upon the occurrence of certain events described in the Plan Support Agreement. In addition, under the Plan Support Agreement, the supporting parties have committed to support the inclusion of releases with respect to the claims described in the Settlement Agreement (described below) in the context of an alternative plan (which would become effective when an alternative plan of reorganization becomes effective).

Settlement Agreement

The Settling Parties entered into a settlement agreement (the Settlement Agreement) in August 2015 (as amended in September 2015) to compromise and settle, among other things (a) intercompany claims among the Debtors, (b) claims and causes of actions against holders of first lien claims against TCEH and the agents under the TCEH Senior Secured Facilities, (c) claims and causes of action against holders of interests in EFH Corp. and certain related entities and (d) claims and causes of action against each of the Debtors' current and former directors, the Sponsor Group, managers and officers and other related entities. The Settlement Agreement is expected to remain effective regardless of whether the EFH Acquisition is completed. The Bankruptcy Court approved the Settlement Agreement in December 2015.

In December 2015, pursuant to the approved Settlement Agreement, Backstop Agreement, Merger Agreement and Plan of Reorganization, we recorded legal and representation service fees, financial advisory fees and other professional fees of $144 million, along with a gain for an adjustment related to the Sponsor Group's agreement to forego claims related to a management agreement of $86 million, both of which are reported in our statement of consolidated income (loss) in reorganization items. Additionally, we recorded an adjustment to intercompany claims among the debtors to adjust for a TCEH unsecured claim against EFH Corp. of $700 million as contemplated by the Plan of Reorganization. See Notes 13 and 19 for discussion of additional transactions resulting from the Settlement Agreement.

Merger and Purchase Agreement

In August 2015, EFH Corp. and EFIH entered into a Purchase Agreement and Agreement and Plan of Merger (Merger and Purchase Agreement) with two acquisition entities, Ovation Acquisition I, L.L.C. (OV1) and Ovation Acquisition II, L.L.C. (collectively, the Purchasers), which are controlled by the Investor Group. Pursuant to the Merger and Purchase Agreement, at the effective time of the Plan of Reorganization and immediately after consummation of the Reorganized TCEH Spin-Off, the Investor Group will acquire Reorganized EFH.

The Merger and Purchase Agreement contemplates that funds received by the Purchasers pursuant to the Equity Commitment Letter, the Debt Commitment Letter and the Rights Offering and Backstop (each as defined below) will be used to facilitate the acquisition of Reorganized EFH and, as applicable, repay the allowed claims of holders of claims and interests in EFH Corp. and EFIH in full in cash (or otherwise render such claims unimpaired) pursuant to the Plan of Reorganization and, if applicable, to complete the Texas Transmission Acquisition (as defined below). The Merger and Purchase Agreement includes various conditions precedent to consummation of the transactions contemplated thereby, including a condition that certain approvals and rulings be obtained, including from the PUCT and the IRS, that are necessary to consummate the EFH Acquisition and convert Reorganized EFH into a REIT.

The Merger and Purchase Agreement may be terminated upon certain events, including, among other things, (a) by either party, if certain termination events occur under the Plan Support Agreement, including if the EFH Acquisition is not completed by April 30, 2016, subject to extension to June 30, 2016 or August 31, 2016 under certain conditions, (b) by EFH Corp. or EFIH, if their respective board of directors or managers determines in good faith that proceeding with the transactions contemplated by the Merger and Purchase Agreement would be inconsistent with its applicable fiduciary duties or (c) by the Purchasers, if EFH Corp. or EFIH fails to meet various milestones related to the Debtors' Chapter 11 Cases or otherwise materially breaches the Merger and Purchase Agreement.

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The Bankruptcy Court approved the Merger and Purchase Agreement in connection with confirmation of the Plan of Reorganization in December 2015.

Rights Offering

As contemplated by the Plan of Reorganization, OV1 intends to conduct an offering of equity rights (each, a Right, and such offering, the Rights Offering) to holders of unsecured debt claims, second lien debt claims, general unsecured claims and first lien secured claims against TCEH (Rights Offering Participants) enabling the Rights Offering Participants to purchase an aggregate of $5.787 billion of common stock of OV1 (as the successor by merger of Reorganized EFH). This annual report on Form 10-K does not constitute an offer to sell, or a solicitation of an offer to purchase, the Rights.

Pursuant to a Backstop Agreement (Backstop Agreement), among certain investors named therein and their permitted assignees (Backstop Purchasers), EFH Corp., EFIH and OV1, the Backstop Purchasers have agreed to backstop $5.087 billion of Rights offered to certain of the Rights Offering Participants (Backstop).

In connection with the execution of the Merger and Purchase Agreement, each member of the Investor Group (collectively, the Equity Commitment Parties) delivered (a) an equity commitment letter (Equity Commitment Letter) in favor of EFH Corp. (including Reorganized EFH), EFIH and the Purchasers pursuant to which the Equity Commitment Parties committed to invest in one or more of the Purchasers an aggregate amount of approximately $2.513 billion (assuming the Texas Transmission Acquisition (as described below) is completed) and (b) a limited guarantee (Guarantee) in favor of EFH Corp. (including Reorganized EFH) and EFIH pursuant to which each such Equity Commitment Party committed to pay its pro rata share of all fees, costs or expenses payable by the Purchasers under the Merger and Purchase Agreement or under the Plan of Reorganization if such fees, costs or expenses become payable pursuant thereto. The aggregate liability of the Equity Commitment Parties under the Guarantee for fees and expenses is capped at $35 million.

If the Merger and Purchase Agreement, the Backstop Agreement or the Equity Commitment Letter are terminated for any reason, EFH Corp. and EFIH have waived their rights to seek any legal or equitable remedies, except in connection with the reimbursement of certain fees and expenses capped at $35 million, against the Purchasers or the Investor Group, the Backstop Purchasers or the Equity Commitment Parties, respectively. In December 2015, pursuant to the court approved Merger and Purchase Agreement and the Backstop Agreement, we incurred approximately $49 million in fees to the Purchasers for expenses incurred in connection with those agreements.

Debt Funding Arrangements

In August 2015, in connection with the execution of the Merger and Purchase Agreement, the Investor Group entered into a commitment letter (Debt Commitment Letter) with Morgan Stanley Senior Funding, Inc. (Debt Commitment Lender) pursuant to which the Debt Commitment Lender committed to fund up to $5.5 billion under a senior secured term loan facility and $250 million under a senior secured bridge loan facility to reorganized EFIH and its subsidiaries at the closing of the EFH Acquisition.

Texas Transmission Acquisition

In connection with the EFH Acquisition and the Rights Offering, the Purchasers, EFH Corp. and EFIH have formulated a plan to create and implement an IPO Conversion (as such term is defined in the Investor Rights Agreement (Investor Rights Agreement), dated November 2008 among Oncor and certain of its direct and indirect equity holders, including EFH Corp. and Texas Transmission, pursuant to which one of the Purchasers, as the successor to Reorganized EFH as a result of the EFH Acquisition, would serve as an IPO corporation (as defined in the Investor Rights Agreement). In connection with the execution of the Merger and Purchase Agreement, the Purchasers have delivered to EFH Corp. an offer to purchase substantially all of the outstanding IPO Units (as defined in the Investor Rights Agreement) in the IPO corporation and all of the LLC Units (as defined in the Investor Rights Agreement) in Oncor held by Texas Transmission (the Texas Transmission Acquisition). EFH Corp. has instituted an adversary proceeding in the Bankruptcy Court to enforce certain rights against Texas Transmission under the Investor Rights Agreement (see Note 14).

Other

Although the Plan of Reorganization has been confirmed by the Bankruptcy Court, the effective date of the Plan of Reorganization has not occurred and there are no assurances that the transactions contemplated thereby will occur because they are subject to completion of various conditions including, but not limited to, receipt of regulatory approval from the PUCT, NRC and FERC, receipt of the Private Letter Ruling from the IRS and the repayment of the DIP Facilities.

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Tax Matters

In June 2014, EFH Corp. filed a request with the IRS for a private letter ruling, which request has been supplemented from time to time in response to requests from the IRS for information or as required by changes in the contemplated transactions (as supplemented, the Private Letter Ruling). It is expected that, among other things, the Private Letter Ruling if obtained will provide (A) for certain rulings regarding the qualification of (i) the transfer of certain assets and ordinary course operating liabilities to a newly-formed entity wholly-owned by TCEH (Reorganized TCEH) and (ii) the distribution of the equity of Reorganized TCEH, the cash proceeds from Reorganized TCEH debt, the cash proceeds from the sale of preferred stock in a newly-formed entity, and the right to receive payments under a tax receivables agreement (if any), to holders of TCEH first lien claims and (B) certain rulings regarding the eligibility of EFH Corp. to qualify as a REIT for federal income tax purposes. The Debtors intend to continue to pursue the Private Letter Ruling to support the Plan of Reorganization.

Implications of the Chapter 11 Cases

Our ability to continue as a going concern is contingent upon, among other factors, our ability to comply with the financial and other covenants contained in the DIP Facilities described in Note 12, our ability to obtain new debtor in possession financing in the event the DIP Facilities were to expire during the pendency of the Chapter 11 Cases as well as our ability to obtain applicable regulatory approvals required for the effectiveness of the Plan of Reorganization and our ability to obtain any exit financing needed to implement the Plan of Reorganization. These circumstances and uncertainties inherent in the bankruptcy proceedings raise substantial doubt about our ability to continue as a going concern.

Operations During the Chapter 11 Cases

In general, the Debtors have received final bankruptcy court orders with respect to first day motions and other operating motions that allow the Debtors to operate their businesses in the ordinary course, including, among others, providing for the payment of certain pre-petition employee and retiree expenses and benefits, the use of the Debtors' existing cash management system, the segregation of certain cash balances which require further order of the Bankruptcy Court for distribution, the continuation of customer contracts and programs at our retail electricity operations, the payment of certain pre-petition amounts to certain critical vendors, the ability to perform under certain pre-petition hedging and trading arrangements and the ability to pay certain pre-petition taxes and regulatory fees. In addition, the Bankruptcy Court has issued orders approving the DIP Facilities discussed in Note 12.

Pursuant to the Bankruptcy Code, the Debtors intend to comply with all applicable regulatory requirements, including all requirements related to environmental and safety law compliance, during the pendency of the Chapter 11 Cases. Further, the Debtors have been complying, and intend to continue to comply, with the various reporting obligations that are required by the Bankruptcy Court during the pendency of the Chapter 11 Cases. Moreover, to the extent the Debtors either maintain insurance policies or self-insure their regulatory compliance obligations, the Debtors intend to continue such insurance policies or self-insurance in the ordinary course of business.

Pre-Petition Claims

Holders of the substantial majority of pre-petition claims were required to file proofs of claims by the bar date established by the Bankruptcy Court. A bar date is the date by which certain claims against the Debtors must be filed if the claimants wish to receive any distribution in the Chapter 11 Cases. The Bankruptcy Court established a bar date of October 27, 2014 for the substantial majority of claims. In addition, in July 2015, the Bankruptcy Court entered an order establishing December 14, 2015 as the bar date for certain asbestos claims that arose or are deemed to have arisen before the Petition Date, except for certain specifically exempt claims.

We have received approximately 41,300 filed claims since the Petition Date, including approximately 30,900 in filed asbestos claims. Most of the asbestos claims were received at or near the bar date and we are actively validating, reconciling and reviewing those claims. For all of the claims, we are in the process of reconciling those claims to the amounts listed in our schedules of assets and liabilities, which includes communications with claimants to acquire additional information required for reconciliation. As of February 29, 2016, approximately 5,500 of those claims have been settled, withdrawn or expunged. To the extent claims are reconciled and resolved, we have recorded them at the expected allowed amount. Certain claims filed or reflected in our schedules of assets and liabilities will be resolved on the effective date of the Plan of Reorganization, including certain claims filed by holders of funded debt and contract counterparties. Claims that remain unresolved or unreconciled through the filing of this report have been estimated based upon management's best estimate of the likely claim amounts that the Bankruptcy Court will ultimately allow.

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In November 2014, we began the process to request the Bankruptcy Court to disallow claims that we believe are duplicative, have been later amended or superseded, are without merit, are overstated or should be disallowed for other reasons. Given the substantial number of claims filed, the claims resolution process will take considerable time to complete. Differences between liability amounts recorded by the Debtors as liabilities subject to compromise and claims filed by creditors will be investigated and, if necessary, the Bankruptcy Court will make a final determination of the allowable claim. Differences between those final allowed claims and the liabilities recorded in the consolidated balance sheets will be recognized as reorganization items in our statements of consolidated income (loss) as they are resolved. The determination of how liabilities will ultimately be resolved cannot be made until a plan of reorganization or a court approved order related to settlement of specific liabilities becomes effective. Accordingly, the ultimate amount or resolution of such liabilities is not determinable at this time. The resolution of such claims could result in material adjustments to our financial statements.

Executory Contracts and Unexpired Leases

Under the Bankruptcy Code, we have the right to assume, assume and assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of an executory contract or unexpired lease requires a debtor to satisfy pre-petition obligations under contracts, which may include payment of pre-petition liabilities in whole or in part. Rejection of an executory contract or unexpired lease is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to executory contracts or unexpired leases rejected by a debtor may file proofs of claim against that debtor's estate for rejection damages.

Since the Petition Date, we have renegotiated or rejected a limited number of executory contracts and unexpired leases. For the years ended December 31, 2015 and 2014 this activity has resulted in the recognition of approximately $38 million and $20 million, respectively, in contract claim and assumption adjustments recorded in reorganization items as detailed in Note 11. The Plan Supplement includes a list of contracts that the Debtors intend to either assume or reject pursuant to the Bankruptcy Code.

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3. PENDING PURCHASE OF LA FRONTERA HOLDINGS, LLC

In November 2015, Luminant entered into a purchase and sale agreement with La Frontera Ventures, LLC, a subsidiary of NextEra Energy, Inc., to purchase all of the membership interests in La Frontera Holdings, LLC, the indirect owner of two natural gas fueled generation facilities totaling 2,988 MW of capacity located in ERCOT. The aggregate purchase price under the agreement is approximately $1.313 billion plus approximately $276 million for cash and net working capital, subject to customary adjustments based on the amounts of cash and net working capital at closing. The existing project financing of La Frontera Holdings, LLC and its subsidiaries will be repaid at closing of the transaction. The purchase price is expected to be funded by cash-on-hand and borrowings under the TCEH DIP Facility. The purchase and sale agreement contains customary closing conditions for transactions of this type. The only remaining regulatory approval necessary to complete the acquisition is approval by the PUCT.

4. VARIABLE INTEREST ENTITIES

A variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. Accounting standards require consolidation of a VIE if we have (a) the power to direct the significant activities of the VIE and (b) the right or obligation to absorb profit and loss from the VIE (i.e., we are the primary beneficiary of the VIE). In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE.

Oncor Holdings, an indirect wholly owned subsidiary of EFH Corp. that holds an approximate 80% interest in Oncor, is not consolidated in EFH Corp.'s financial statements, and instead is accounted for as an equity method investment, because the structural and operational ring-fencing measures discussed in Note 1 prevent us from having power to direct the significant activities of Oncor Holdings or Oncor. In accordance with accounting standards, we account for our investment in Oncor Holdings under the equity method, as opposed to the cost method, based on our level of influence over its activities. See below for additional information about our equity method investment in Oncor Holdings. There are no other material investments accounted for under the equity or cost method. The maximum exposure to loss from our interests in VIEs does not exceed our carrying value.

Non-Consolidation of Oncor and Oncor Holdings

In reaching the conclusion to deconsolidate, we conducted an extensive analysis of Oncor Holdings' underlying governing documents and management structure. Oncor Holdings' unique governance structure was adopted in conjunction with the Merger, when the Sponsor Group, EFH Corp. and Oncor agreed to implement structural and operational measures to ring-fence (the Ring-Fencing Measures) Oncor Holdings and Oncor as discussed in Note 1. The Ring-Fencing Measures were designed to prevent, among other things, (i) increased borrowing costs at Oncor due to the attribution to Oncor of debt from any of our other subsidiaries, (ii) the activities of our competitive operations following the Merger resulting in the deterioration of Oncor's business, financial condition and/or investment in infrastructure, and (iii) Oncor becoming substantively consolidated into a bankruptcy proceeding involving any member of the Texas Holdings Group. The Ring-Fencing Measures effectively separate the daily operational and management control of Oncor Holdings and Oncor from EFH Corp. and its other subsidiaries. By implementing the Ring-Fencing Measures, Oncor maintained its investment grade credit rating following the Merger, and we reaffirmed Oncor's independence from our competitive businesses to the PUCT.

We determined the most significant activities affecting the economic performance of Oncor Holdings (and Oncor) are the operation, maintenance and growth of Oncor's electric transmission and distribution assets and the preservation of its investment grade credit profile. The boards of directors of Oncor Holdings and Oncor have ultimate responsibility for the management of the day-to-day operations of their respective businesses, including the approval of Oncor's capital expenditure and operating budgets and the timing and prosecution of Oncor's rate cases. While both boards include members appointed by EFH Corp., a majority of the board members are independent in accordance with rules established by the New York Stock Exchange, and therefore, we concluded for purposes of applying the amended accounting standards that EFH Corp. does not have the power to control the activities deemed most significant to Oncor Holdings' (and Oncor's) economic performance.

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In assessing EFH Corp.'s ability to exercise control over Oncor Holdings and Oncor, we considered whether it could take actions to circumvent the purpose and intent of the Ring-Fencing Measures (including changing the composition of Oncor Holdings' or Oncor's board) in order to gain control over the day-to-day operations of either Oncor Holdings or Oncor. We also considered whether (i) EFH Corp. has the unilateral power to dissolve, liquidate or force into bankruptcy either Oncor Holdings or Oncor, (ii) EFH Corp. could unilaterally amend the Ring-Fencing Measures contained in the underlying governing documents of Oncor Holdings or Oncor, and (iii) EFH Corp. could control Oncor's ability to pay distributions and thereby enhance its own cash flow. We concluded that, in each case, no such opportunity exists.

Our investment in unconsolidated subsidiary as presented in the consolidated balance sheets totaled $6.064 billion and $6.058 billion at December 31, 2015 and 2014, respectively, and consists almost entirely of our interest in Oncor Holdings, which we account for under the equity method as described above. Oncor provides services, principally electricity distribution, to TCEH's retail operations, and the related revenues represented 25%, 25% and 27% of Oncor Holdings' consolidated operating revenues for the years ended December 31, 2015, 2014 and 2013, respectively.

See Note 19 for discussion of Oncor Holdings' and Oncor's transactions with EFH Corp. and its other subsidiaries.

Distributions from Oncor Holdings and Related Considerations —Oncor Holdings' distributions of earnings to us totaled $322 million, $202 million and $213 million for the years ended December 31, 2015, 2014 and 2013, respectively. Distributions may not be paid except to the extent Oncor maintains a required regulatory capital structure as discussed below. At December 31, 2015, $30 million was eligible to be distributed to Oncor's members after taking into account the regulatory capital structure limit, of which approximately 80% relates to our ownership interest in Oncor. The boards of directors of each of Oncor and Oncor Holdings can withhold distributions to the extent the applicable board determines in good faith that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings.

Oncor's distributions are limited by its regulatory capital structure, which is required to be at or below the assumed debt-to-equity ratio established by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. At December 31, 2015, Oncor's regulatory capitalization ratio was 59.8% debt and 40.2% equity. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes bonds issued by Oncor Electric Delivery Transition Bond Company LLC, which were issued in 2003 and 2004 to recover specific generation-related regulatory assets and other qualified costs. Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of accounting for the Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization).

As a result of the Bankruptcy Filing, Oncor had credit risk exposure to trade accounts receivable from subsidiaries of TCEH, which related to delivery services provided by Oncor to TCEH's retail electricity operations. At the Petition Date, these accounts receivable totaled $109 million. In June 2014, the Bankruptcy Court authorized the Debtors to pay all pre-petition delivery charges due Oncor, and such amounts were paid in full.

EFH Corp., Oncor Holdings, Oncor and Oncor's minority investor are parties to a Federal and State Income Tax Allocation Agreement. Additional income tax amounts receivable or payable may arise in the normal course under that agreement.

Oncor Holdings Financial Statements —Condensed statements of consolidated income of Oncor Holdings and its subsidiaries for the years ended December 31, 2015, 2014 and 2013 are presented below:

	Year Ended December 31,
	2015			2014			2013
Operating revenues	$	3,878		$	3,822		$	3,552
Operation and maintenance expenses	(1,526		)	(1,453		)	(1,269		)
Depreciation and amortization	(863		)	(851		)	(814		)
Taxes other than income taxes	(450		)	(438		)	(424		)
Other income	6			13			18
Other deductions	(28		)	(15		)	(15		)
Interest income	—			3			4
Interest expense and related charges	(333		)	(353		)	(371		)
Income before income taxes	684			728			681
Income tax expense	(264		)	(289		)	(259		)
Net income	420			439			422
Net income attributable to noncontrolling interests	(86		)	(90		)	(87		)
Net income attributable to Oncor Holdings	$	334		$	349		$	335

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Assets and liabilities of Oncor Holdings at December 31, 2015 and 2014 are presented below:

	December 31,
	2015		2014
ASSETS
Current assets:
Cash and cash equivalents	$	26	$	5
Restricted cash	38		56
Trade accounts receivable — net	388		407
Trade accounts and other receivables from affiliates	118		118
Income taxes receivable from EFH Corp.	107		144
Inventories	82		73
Accumulated deferred income taxes	—		10
Prepayments and other current assets	88		91
Total current assets	847		904
Restricted cash	—		16
Other investments	97		97
Property, plant and equipment — net	13,024		12,463
Goodwill	4,064		4,064
Regulatory assets — net	1,194		1,429
Other noncurrent assets	31		34
Total assets	$	19,257	$	19,007
LIABILITIES
Current liabilities:
Short-term borrowings	$	840	$	711
Long-term debt due currently	41		639
Trade accounts payable — nonaffiliates	150		202
Income taxes payable to EFH Corp.	20		24
Accrued taxes other than income	181		174
Accrued interest	82		93
Other current liabilities	144		156
Total current liabilities	1,458		1,999
Accumulated deferred income taxes	1,985		1,978
Long-term debt, less amounts due currently	5,646		4,964
Other noncurrent liabilities and deferred credits	2,306		2,245
Total liabilities	$	11,395	$	11,186

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5. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides information regarding our goodwill balance, all of which relates to the Competitive Electric segment and arose in connection with accounting for the Merger. None of the goodwill is being deducted for tax purposes.

Goodwill before impairment charges	$	18,342
Accumulated noncash impairment charges through 2014	(15,990		)
Balance at December 31, 2014	2,352
Additional noncash impairment charges in 2015	(2,200		)
Balance at December 31, 2015 (a)	$	152

____________

(a) Net of accumulated impairment charges totaling $18.190 billion.

Goodwill Impairments

Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (we have selected a December 1 test date) or whenever events or changes in circumstances indicate an impairment may exist.

We perform the following steps in testing goodwill for impairment: first, we estimate the debt-free enterprise value of the business as of the testing date taking into account future estimated cash flows and current securities values of comparable companies; second, we estimate the fair values of the individual assets and liabilities of the business at that date; third, we calculate implied goodwill as the excess of the estimated enterprise value over the estimated value of the net operating assets; and finally, we compare the implied goodwill amount to the carrying value of goodwill and, if the carrying amount exceeds the implied value, we record an impairment charge for the amount the carrying value of goodwill exceeds implied goodwill.

Wholesale electricity prices in the ERCOT market, in which our Competitive Electric segment largely operates, have generally moved with natural gas prices as marginal electricity demand is generally supplied by natural gas fueled generation facilities. Accordingly, the sustained decline in natural gas prices, which we have experienced since mid-2008, negatively impacts our profitability and cash flows and reduces the value of our generation assets, which consist largely of lignite/coal and nuclear fueled facilities. While we had partially mitigated these effects with hedging activities, we are now significantly exposed to this price risk. Because of this market condition, our analyses over the past several years have indicated that the carrying value of the Competitive Electric segment exceeds its estimated fair value (enterprise value). Consequently, we continually monitor trends in electricity prices, natural gas prices, market heat rates, capital spending for environmental and other projects and other operational factors to determine if goodwill impairment testing should be done during the course of a year and not only at the annual December 1 testing date.

During the fourth quarter of 2015, we performed our goodwill impairment analysis as of our annual testing date of December 1. Further, during the fourth quarter of 2015, there were significant declines in the market values of several similarly situated peer companies (with respect to our Competitive Electric segment) with publicly traded equity, which indicated the overall enterprise value of our Competitive Electric segment should be reassessed. Our testing resulted in an impairment of goodwill of $800 million at December 1, 2015, which we reported in the Competitive Electric segment results.

During the first nine months of 2015, we experienced impairment indicators related to decreases in forward wholesale electricity prices when compared to those prices reflected in our December 1, 2014 goodwill impairment testing analysis. As a result, the likelihood of a goodwill impairment had increased, and we initiated further testing of goodwill. Our testing of goodwill for impairment during the first nine months of 2015 resulted in impairment charges totaling $1.4 billion, which we reported in the Competitive Electric segment results.

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Key inputs into our goodwill impairment testing at December 1, September 30 and March 31, 2015 and December 1, 2014 were as follows:

• The carrying value (excluding debt) of the Competitive Electric segment exceeded its estimated enterprise value by approximately 48% at December 1, 2015 and 17% at December 1, 2014.

• The fair value of the Competitive Electric segment was estimated using a two-thirds weighting of value based on internally developed cash flow projections and a one-third weighting of value using implied cash flow multiples based on current securities values of comparable publicly traded companies. The internally developed cash flow projections reflect annual estimates through a terminal year calculated using a terminal year EBITDA multiple approach.

• The discount rates applied to internally developed cash flow projections were 6.00% for the impairments recorded in 2015 and 6.25% at December 1, 2014. The discount rate represents the weighted average cost of capital consistent with our views of the rate that an expected market participant would utilize for valuation, including the risk inherent in future cash flows, taking into account the capital structure, debt ratings and current debt yields of comparable public companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry.

• The cash flow projections used in both 2015 and 2014 assume rising wholesale electricity prices, although the forecasted electricity prices are less than those assumed in the cash flow projections used in prior goodwill impairment testing.

Changes in the above and other assumptions could materially affect the calculated amount of implied goodwill and any resulting goodwill impairment charge.

During the third quarter of 2014, we experienced an impairment indicator related to significant decreases in forward wholesale electricity prices when compared to those prices reflected in our December 1, 2013 goodwill impairment testing analysis. As a result, the likelihood of a goodwill impairment had increased, and we initiated further testing of goodwill as of September 30, 2014, which was completed during the fourth quarter. Our testing resulted in an impairment of $1.6 billion of goodwill at September 30, 2014, which we recorded in the fourth quarter of 2014 and is reported in the Competitive Electric segment results.

During the fourth quarter of 2014, we also performed our goodwill impairment analysis as of our annual testing date of December 1. During the fourth quarter of 2014, we completed our annual update of our long-range financial and operating plan, which reflected extended seasonal outages and reduced operations at several of our older lignite/coal fueled generation facilities as a result of the lower wholesale electricity prices and potential impacts to those facilities from proposed environmental regulations. The resulting impairment charge recorded on our long-lived assets was factored into our December 1 goodwill impairment test. Our testing did not result in an additional impairment of goodwill at December 1, 2014.

During the fourth quarter of 2013, we recorded a $1.0 billion goodwill impairment charge related to the Competitive Electric segment. The impairment charge in 2013 reflected declines in the estimated fair value of the Competitive Electric segment as a result of lower wholesale electricity prices, the sustained decline in natural gas prices, the maturing of positions in our natural gas hedge program and declines in market values of securities of comparable companies.

The impairment determinations involved significant assumptions and judgments. The calculations supporting the estimates of the fair value of our Competitive Electric segment and the fair values of its assets and liabilities utilized models that take into consideration multiple inputs, including commodity prices, operating parameters, discount rates, capital expenditures, the effects of proposed and final environmental regulations, securities prices of comparable publicly traded companies and other inputs. Assumptions regarding each of these inputs could have a significant effect on the related valuations. In performing these calculations, we also take into consideration assumptions on how current market participants would value the Competitive Electric segment and its operating assets and liabilities. Changes to assumptions that reflect the views of current market participants can also have a significant effect on the related valuations. The fair value measurements resulting from these models are classified as non-recurring Level 3 measurements consistent with accounting standards related to the determination of fair value (see Note 16). Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.

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Identifiable Intangible Assets

Identifiable intangible assets, including amounts that arose in connection with accounting for the Merger, are comprised of the following:

	December 31, 2015						December 31, 2014
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	442	$	21	$	463	$	425	$	38
Capitalized in-service software	362		214		148		362		216		146
Other identifiable intangible assets (a)	72		35		37		460		291		169
Total identifiable intangible assets subject to amortization	$	897	$	691	206		$	1,285	$	932	353
Retail trade name (not subject to amortization)					955						955
Mineral interests (not currently subject to amortization)					5						7
Total identifiable intangible assets					$	1,166					$	1,315

____________

(a) Includes favorable purchase and sales contracts, environmental allowances and credits and mining development costs. See discussion below regarding impairment charges recorded in 2014 and 2015 related to other identifiable intangible assets.

At December 31, 2015 and 2014, amounts related to fully amortized assets that are expired or of no economic value have been excluded from both the gross carrying and accumulated amortization amounts in the table above.

Amortization expense related to finite-lived identifiable intangible assets (including the statements of consolidated income (loss) line item) consisted of:

Identifiable Intangible Asset	Statements of Consolidated Income (Loss) Line	Segment	Remaining useful lives at December 31, 2015 (weighted average in years)	Year Ended December 31,
				2015		2014		2013
Retail customer relationship	Depreciation and amortization	Competitive Electric	2	$	17	$	23	$	24
Capitalized in-service software	Depreciation and amortization	Competitive Electric and Corporate and Other	3	49		45		42
Other identifiable intangible assets	Operating revenues/fuel, purchased power costs and delivery fees /depreciation and amortization	Competitive Electric	8	30		88		69
Total amortization expense (a)				$	96	$	156	$	135

____________

(a) Amounts recorded in depreciation and amortization totaled $74 million, $102 million and $97 million in 2015, 2014 and 2013, respectively.

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Following is a description of the separately identifiable intangible assets recorded as part of purchase accounting for the Merger. The intangible assets were recorded at estimated fair value as of the Merger date, based on observable prices or estimates of fair value using valuation models.

• Retail customer relationship – Retail customer relationship intangible asset represents the fair value of the non-contracted customer base and is being amortized using an accelerated method based on customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.

• Retail trade name – The trade name intangible asset represents the fair value of the TXU Energy trade name, and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset is evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other intangible assets. Significant assumptions included within the development of the fair value estimate include TXU Energy's estimated gross margin for future periods and an implied royalty rate. No impairment was recorded as a result of our 2015 analysis.

• Favorable purchase and sales contracts – Favorable purchase and sales contracts intangible asset primarily represents the above market value of commodity contracts for which: (i) we had made the normal purchase or sale election allowed by accounting standards related to derivative instruments and hedging transactions or (ii) the contracts did not meet the definition of a derivative. The amortization periods of these intangible assets are based on the terms of the contracts. Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits (see Note 21). See below for discussion of impairment of certain intangible assets related to favorable purchase and sales contracts in 2015 and 2014.

Environmental allowances and credits – This intangible asset represents the fair value of environmental credits, substantially all of which were expected to be used in our power generation activities. These credits are amortized utilizing a units-of-production method. See below for discussion of impairment of certain allowances in 2015 and 2014.

Intangible Impairments

The impairments of our generation facilities in 2015 (see Note 9) resulted in the impairment of the SO₂ allowances under the Clean Air Act's acid rain cap-and-trade program that are associated with those facilities to the extent they are not projected to be used at other sites. The fair market values of the SO₂ allowances were estimated to be de minimis based on Level 3 fair value estimates (see Note 16). We also impaired certain of our SO₂ allowances under the Cross-State Air Pollution Rule (CSAPR) related to the impaired generation facilities. Accordingly, in the year ended December 31, 2015, we recorded noncash impairment charges of $55 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions related to our existing environmental allowances and credits intangible asset. SO₂ emission allowances granted to us under the acid rain cap-and-trade program were recorded as intangible assets at fair value in connection with purchase accounting related to the Merger in 2007. Additionally, the impairments of our generation and related mining facilities in September 2015 resulted in our recording noncash impairment charges of $19 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions (see Note 8) related to mine development costs (included in other identifiable intangible assets in the table above) at the facilities.

During the first quarter of 2015, we determined that certain intangible assets related to favorable power purchase contracts should be evaluated for impairment. That conclusion was based on further declines in wholesale electricity prices in ERCOT experienced during the first quarter of 2015. Our fair value measurement was based on a discounted cash flow analysis of the contracts that compared the contractual price and terms of the contract to forecasted wholesale electricity and renewable energy credit (REC) prices in ERCOT. As a result of the analysis, we recorded a noncash impairment charge of $8 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions (see Note 8).

During the fourth quarter of 2014, we determined that certain intangible assets related to favorable power purchase contracts should be evaluated for impairment. That conclusion was based on the combination of (1) the review of contracts for rejection as part of the Chapter 11 Cases, which could result in termination of contracts before the end of their estimated useful life and (2) declines in wholesale electricity prices. Our fair value measurement was based on a discounted cash flow analysis of the contracts that compared the contractual price and terms of the contract to forecasted wholesale electricity and REC prices in ERCOT. As a result of the analysis, we recorded a noncash impairment charge of $183 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions (see Note 8).

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As a result of the CSAPR, which became effective on January 1, 2015, and other new or proposed EPA rules, we projected that as of December 31, 2014 we had excess SO₂ emission allowances under the Clean Air Act's existing acid rain cap-and-trade program. In addition, the impairments of our Monticello, Martin Lake and Sandow 5 generation facilities (see Note 9) resulted in the impairment of the SO₂ allowances associated with those facilities to the extent they are not projected to be used at other sites. The fair market values of the SO₂ allowances were estimated to be de minimis based on Level 3 fair value estimates (see Note 16). Accordingly we recorded a noncash impairment charge of $80 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions related to our existing environmental allowances and credits intangible asset in 2014. SO₂ emission allowances granted to us were recorded as intangible assets at fair value in connection with purchase accounting related to the Merger in 2007.

Estimated Amortization of Identifiable Intangible Assets

The estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as follows:

Year	Estimated Amortization Expense
2016	$	66
2017	$	55
2018	$	35
2019	$	22
2020	$	11

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6.    ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES

Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.

We file or have filed income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of our income tax returns for the years ending prior to January 1, 2010 are complete. Federal income tax returns are under examination for tax years 2010 to 2014. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2006.

In the fourth quarter of 2015, we and the IRS agreed to a revised estimate of interest owed with respect to prior tax years settled at audit and appeals. This agreement around interest computations had the effect of lowering our expected payable to the IRS related to these tax years by approximately $15 million.

In June 2015, we signed a final agreed Revenue Agent Report (RAR) with the IRS and associated documentation for the 2008 and 2009 tax years. The Bankruptcy Court approved our signing of the RAR in July 2015. As a result of receiving, agreeing to and signing the final RAR, we reduced the liability for uncertain tax positions by $23 million, resulting in a $20 million reclassification to the accumulated deferred income tax liability and the recording of a $3 million income tax benefit recorded in the Competitive Electric segment results. Total cash payment to be assessed by the IRS for tax years 2008 and 2009, but not paid during the pendency of the Chapter 11 Cases, is approximately $15 million, plus any interest that may be assessed.

In 2014, the IRS filed a claim with the Bankruptcy Court for open tax years through 2013 that was consistent with the settlement we reached with IRS Appeals for tax years 2003-2006. Also in 2014, we signed a final agreed RAR with the IRS and associated documentation for the 2007 tax year. As a result of these events, we effectively settled the 2003-2007 open tax years and reduced the liability for uncertain tax positions related to such years by $174 million, resulting in a $139 million reclassification to the accumulated deferred income tax liability and the recording of a net $35 million income tax benefit reflecting the settlement of certain positions. These events also resulted in an increase in the payable to the IRS of $50 million (including $18 million of interest), and a payable to Oncor of $64 million. The total income tax benefit of $35 million reflected a $31 million income tax benefit recorded in Corporate and Other activities and a $4 million income tax benefit reported in the Competitive Electric segment results.

In recording the 2014 impacts, the Company identified approximately $90 million of income tax expense related to 2013 which was recorded in December 2014. The impact of recording this expense was not material to the financial statements in 2013 or 2014.

In 2013, EFH Corp. and the IRS agreed on terms to resolve disputed adjustments related to the IRS audit for the years 2003 through 2006, which was concluded in June 2011. Also in 2013, we received approval from the Joint Committee on Taxation of the IRS appeals settlement of all issues arising from the 1997 through 2002 IRS audit, which includes all tax issues related to EFH Corp.'s discontinued Europe operations. The IRS proposed a significant number of adjustments to the originally filed returns for such years related to one significant accounting method issue and other less significant issues. As a result of these events, we reduced the liability for uncertain tax positions by $1.598 billion, including $188 million in interest accruals. Other effects included the recording of a $13 million noncurrent federal income tax liability, an $8 million current federal income tax liability related to an expected interest payment owed as a result of the settlement of all issues arising from the 1997 through 2002 IRS audit, a $15 million current state income tax liability and a $33 million federal income tax receivable from Oncor under the Federal and State Income Tax Allocation Agreement (see Note 7).

The settlements in 2013 resulted in the elimination of a substantial majority of the net operating loss carryforwards and alternative minimum tax credit carryforwards generated through 2013.

In total, the settlements in 2013 resulted in an increase of $1.193 billion in the accumulated deferred income tax liability and an income tax benefit of $305 million. Of the total income tax benefit, $122 million (after-tax) was attributable to the release of accrued interest. The $305 million tax benefit reflected a $226 million income tax benefit reported in Corporate and Other activities and a $79 million income tax benefit reported in the Competitive Electric segment results.

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In September 2013, the US Treasury and the IRS issued final tangible property regulations that relate to repair and maintenance costs. As a result of our analysis of these regulations, in the fourth quarter 2013 we reduced the liability for uncertain tax positions by $159 million and reclassified that amount to the accumulated deferred income tax liability and recorded a $6 million income tax benefit representing a reversal of accrued interest.

We classify interest and penalties related to uncertain tax positions as current income tax expense. Amounts recorded related to interest and penalties totaled benefits of $3 million and $3 million in 2015 and 2014, respectively, and a benefit of $132 million in 2013, reflecting a reversal of interest previously accrued as a result of the IRS settlements discussed above (all amounts after tax). Ongoing accruals of interest after the IRS settlements were not material in 2015, 2014 and 2013.

Noncurrent liabilities included a total of $4 million and $9 million in accrued interest at December 31, 2015 and 2014, respectively. The federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes.

The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheets, during the years ended December 31, 2015, 2014 and 2013:

	Year Ended December 31,
	2015			2014			2013
Balance at January 1, excluding interest and penalties	$	65		$	231		$	1,788
Additions based on tax positions related to prior years	—			61			655
Reductions based on tax positions related to prior years	(11		)	(205		)	(1,817		)
Additions based on tax positions related to the current year	—			—			16
Reductions based on tax positions related to the current year	—			—			(4		)
Settlements with taxing authorities	(18		)	(22		)	(407		)
Balance at December 31, excluding interest and penalties	$	36		$	65		$	231

Of the balance at December 31, 2015, $2 million represents tax positions for which the uncertainty relates to the timing of recognition in tax returns. The disallowance of such positions would not affect the effective tax rate, but could accelerate the payment of cash to the taxing authority to an earlier period.

With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should we sustain such positions on income tax returns previously filed, tax liabilities recorded would be reduced by $35 million, and accrued interest would be reversed resulting in a $2 million after-tax benefit, resulting in increased net income and a favorable impact on the effective tax rate.

With respect to the items discussed above, we reasonably expect the total amount of liabilities recorded related to uncertain tax positions will significantly decrease in the next twelve months due to the anticipated resolution of claims outstanding with the Texas Comptroller of Public Accounts and the IRS. We expect an approximately $2 million reclassification to the accumulated deferred income tax liability from the uncertain tax position liability during the next 12 months.

7. INCOME TAXES

EFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. EFH Corp. is the corporate member of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH is classified as a disregarded entity for US federal income tax purposes. Prior to April 2013, EFCH was a corporate member of the EFH Corp. consolidated group. Oncor is a partnership for US federal income tax purposes and is not a corporate member of the EFH Corp. consolidated group. Pursuant to applicable US Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.

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EFH Corp. and certain of its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) are parties to a Federal and State Income Tax Allocation Agreement, which provides, among other things, that any corporate member or disregarded entity in the EFH Corp. group is required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. The Plan of Reorganization provides that upon the effective date of the plan the Debtors will reject this agreement. Under the terms of the Settlement Agreement, no further cash payments among the Debtors will be made in respect of federal income taxes. However, solely for accounting purposes, the EFH Corp. group continues to allocate federal income taxes among the entities that are parties to the Federal and State Income Tax Allocation Agreement. The Settlement Agreement did not alter the allocation and payment for state income taxes, which will continue to be settled.

EFH Corp., Oncor Holdings, Oncor and Oncor's minority investor are parties to a separate Federal and State Income Tax Allocation Agreement, which governs the computation of federal income tax liability among such parties, and similarly provides, among other things, that each of Oncor Holdings and Oncor will pay EFH Corp. its share of an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. The Settlement Agreement had no impact on the tax sharing agreement among EFH, Oncor Holdings and Oncor.

The components of our income tax benefit are as follows:

	Year Ended December 31,
	2015			2014			2013
Current:
US Federal	$	(203	)	$	(126	)	$	(283	)
State	17			25			40
Total current	(186		)	(101		)	(243		)
Deferred:
US Federal	(1,414		)	(2,507		)	(1,027		)
State	(70		)	(11		)	(1		)
Total deferred	(1,484		)	(2,518		)	(1,028		)
Total	$	(1,670	)	$	(2,619	)	$	(1,271	)

Reconciliation of income taxes computed at the US federal statutory rate to income tax benefit recorded is as follows:

	Year Ended December 31,
	2015			2014			2013
Loss before income taxes and equity in earnings of unconsolidated subsidiaries	$	(7,346	)	$	(9,374	)	$	(3,931	)
Income taxes at the US federal statutory rate of 35%	$	(2,571	)	$	(3,281	)	$	(1,376	)
Nondeductible goodwill impairment	770			560			350
Impairment of joint venture assets attributable to noncontrolling interests (Note 9)	—			—			37
IRS audit and appeals settlements (Note 6)	(1		)	7			(305		)
Texas margin tax, net of federal benefit	—			11			10
Interest accrued for uncertain tax positions, net of tax	(2		)	—			(16		)
Nondeductible interest expense	23			22			23
Lignite depletion allowance	(8		)	(14		)	(12		)
Nondeductible debt restructuring costs	136			78			6
Other	(17		)	(2		)	12
Income tax benefit	$	(1,670	)	$	(2,619	)	$	(1,271	)
Effective tax rate	22.7		%	27.9		%	32.3		%

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Deferred Income Tax Balances

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2015 and 2014 are as follows:

	December 31,
	2015			2014
	Total Noncurrent (a)			Total		Current		Noncurrent
Deferred Income Tax Assets
Alternative minimum tax credit carryforwards	$	99		$	124	$	—	$	124
Employee benefit obligations	143			143		8		135
Net operating loss (NOL) carryforwards	966			1,022		—		1,022
Unfavorable purchase and sales contracts	193			202		—		202
Commodity contracts and interest rate swaps	129			6		—		6
Debt extinguishment gains	1,120			879		—		879
Accrued interest	—			—		—		—
Other	113			85		2		83
Total	2,763			2,461		10		2,451
Deferred Income Tax Liabilities
Property, plant and equipment	1,506			2,422		—		2,422
Commodity contracts and interest rate swaps	—			44		44		—
Identifiable intangible assets	312			355		—		355
Debt fair value discounts	—			342		—		342
Debt extinguishment gains	—			101		101		—
Accrued interest	336			45		—		45
Other	—			—		—		—
Total	2,154			3,309		145		3,164
Net Accumulated Deferred Income Tax (Asset) Liability	$	(609	)	$	848	$	135	$	713

____________

(a) Reflects adoption of ASU 2015-17, Balance Sheet Classification of Deferred Taxes. See Note 1.

At December 31, 2015 we had $2.760 billion in net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2034. As discussed in Note 6, audit settlements reached in 2013 resulted in the elimination of substantially all NOL carryforwards generated through 2013 and available AMT credits. The NOL carryforwards can be used to offset future taxable income. After analyzing our forecasted tax position at December 31, 2015 we currently expect to utilize all of our NOL carryforwards prior to their expiration dates. During 2014 and 2015, our deferred tax liabilities related to property, plant and equipment were significantly reduced due to impairment charges on certain long-lived assets recorded in those periods. See Note 9 for a discussion of impairment charges. Additionally, our deferred tax liabilities related to debt fair value discounts were eliminated due to the write-off of unamortized deferred debt issuance and extension costs, premiums and discounts previously classified as LSTC (see Note 13).

At December 31, 2015 we had $99 million in alternative minimum tax (AMT) credit carryforwards available which may, in certain limited circumstances, be used to offset future tax payments. The AMT credit carryforwards have no expiration date, but may be limited in a change of control.

The income tax effects of the components included in accumulated other comprehensive income at December 31, 2015 and 2014 totaled a net deferred tax asset of $68 million and $71 million, respectively.

See Note 6 for discussion regarding accounting for uncertain tax positions, including the effects of the resolution of IRS audit matters.

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8. OTHER INCOME AND DEDUCTIONS

	Year Ended December 31,
	2015		2014		2013
Other income:
Office space rental income (a)	$	11	$	11	$	11
Sale of land (b)	5		2		1
Mineral rights royalty income (b)	4		4		5
All other	15		14		9
Total other income	$	35	$	31	$	26
Other deductions:
Impairment of favorable purchase contracts (Note 5) (b)	$	8	$	183	$	—
Impairment of emission allowances (Note 5) (b)	55		80		—
Impairment of mining development costs (Note 5) (b)	19		—		—
Impairment of remaining equipment from cancelled generation development program (b)	—		—		27
All other	13		13		26
Total other deductions	$	95	$	276	$	53

____________

(a) Reported in Corporate and Other.

(b) Reported in Competitive Electric segment.

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9. IMPAIRMENT OF LONG-LIVED ASSETS

Impairment of Lignite/Coal Fueled Generation and Mining Assets

We evaluated our generation assets for impairment during 2015 as a result of impairment indicators related to the continued decline in forecasted wholesale electricity prices in ERCOT. Our evaluations concluded that impairments existed, and the carrying values at our Big Brown, Martin Lake, Monticello, Sandow 4 and Sandow 5 generation facilities and related mining facilities were reduced in total by $2.541 billion.

We evaluated our generation assets for impairment during 2014 as a result of several impairment indicators, including lower forecasted wholesale electricity prices in ERCOT, changes to operating assumptions for certain generation assets as detailed in our updated annual financial and operating plan and potential effects of new and/or proposed environmental regulations. Our evaluation concluded that impairments existed, and the carrying values for our Martin Lake, Monticello and Sandow 5 generation facilities and related mining facilities were reduced in total by $4.640 billion.

Our fair value measurement for these assets was determined based on an income approach that utilized probability-weighted estimates of discounted future cash flows, which were Level 3 fair value measurements (see Note 16). Key inputs into the fair value measurement for these assets included current forecasted wholesale electricity prices in ERCOT, forecasted fuel prices, capital and operating expenditure forecasts and discount rates.

In 2014, we wrote off previously incurred and deferred costs totaling $30 million for mining projects not expected to be completed due to economic forecasts and regulatory uncertainty. These charges have been recorded in impairment of long-lived assets in the Competitive Electric segment's results.

Additional material impairments may occur in the future with respect to these assets or other of our generation facilities if forward wholesale electricity prices continue to decline or forecasted costs of producing electricity at our generation facilities increase, including increased costs of compliance with new and/or proposed environmental regulations.

Impairment of Nuclear Generation Development Joint Venture Assets in 2013

In 2009, subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company LLC (CPNPC), to develop two new nuclear generation units at our existing Comanche Peak nuclear plant site. CPNPC was consolidated as a VIE. In the fourth quarter 2014, MHI withdrew from the joint venture, and the TCEH subsidiary now owns 100% of CPNPC.

In the fourth quarter of 2013, MHI notified us and the NRC of its plans to reduce its support of review activities related to the NRC's Design Certification of MHI's US-APWR technology. As a result, Luminant notified the NRC of its intent to suspend (but not withdraw) all reviews associated with the combined operating license application by March 31, 2014. MHI's decision and the expected amendment of the joint venture agreement triggered an analysis of the recoverability of the joint venture's assets. Because of the significant uncertainty regarding the development of the nuclear generation units, considering the wholesale electricity price environment in ERCOT and risks related to financing and cost escalation, in the fourth quarter 2013 essentially all the joint venture's assets were impaired resulting in a charge of $140 million. The charge is reported as other deductions and included in the Competitive Electric segment's results. MHI's allocated portion of the impairment charge totaled $107 million and is reported in net loss attributable to noncontrolling interests in the statements of consolidated income (loss). A deferred income tax benefit was recorded for our $33 million allocated portion of the impairment charge and is included in income tax benefit in the statements of consolidated income (loss).

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10. INTEREST EXPENSE AND RELATED CHARGES

	Year Ended December 31,
	2015			2014			2013
Interest paid/accrued on debtor-in-possession financing	$	295		$	162		$	—
Adequate protection amounts paid/accrued (a)	1,232			827			—
Interest paid/accrued on pre-petition debt (b)	244			1,158			3,376
Interest expense on pre-petition toggle notes payable in additional principal (Note 13)	—			65			176
Noncash realized net loss on termination of interest rate swaps (offset in unrealized net gain) (c)	—			1,237			—
Unrealized mark-to-market net gain on interest rate swaps	—			(1,303		)	(1,058		)
Amortization of debt issuance, amendment and extension costs and discounts	—			66			208
Capitalized interest	(11		)	(17		)	(25		)
Other	—			6			27
Total interest expense and related charges	$	1,760		$	2,201		$	2,704

____________

(a) Post-petition period only.

(b) For the year ended December 31, 2015, amounts include $235 million in post-petition interest related to the EFIH Second Lien Notes (see Note 13). Includes amounts related to interest rate swaps totaling $194 million and $625 million for the years ended December 31, 2014 and 2013, respectively. Of the $194 million for the year ended December 31, 2014, $127 million is included in the liability arising from the termination of TCEH interest rate swaps discussed in Note 17.

(c) Includes $1.225 billion related to terminated TCEH interest rate swaps and $12 million related to other interest rate swaps.

Interest expense for the year ended December 31, 2015 reflects interest paid and accrued on debtor-in-possession financing (see Note 12), adequate protection amounts paid and accrued, as approved by the Bankruptcy Court in June 2014 for the benefit of secured creditors of (a) $22.616 billion principal amount of outstanding borrowings from the TCEH Senior Secured Facilities, (b) $1.750 billion principal amount of outstanding TCEH Senior Secured Notes and (c) the $1.243 billion net liability related to the TCEH first-lien interest rate swaps and natural gas hedging positions terminated shortly after the Bankruptcy Filing (see Note 17), in exchange for their consent to the senior secured, super-priority liens contained in the TCEH DIP Facility and any diminution in value of their interests in the pre-petition collateral from the Petition Date, and interest paid on EFIH's pre-petition 11.00% Second Lien Notes due 2021 and 11.75% Second Lien Notes due 2022 as approved by the Bankruptcy Court in March 2015 (see Note 13). The interest rate applicable to the adequate protection amounts paid/accrued at December 31, 2015 is 4.69% (one-month LIBOR plus 4.50%). In connection with the completion of the Plan of Reorganization, the amount of adequate protection payments may be adjusted to reflect the valuation of the TCEH Debtors determined in connection with confirmation of the Plan of Reorganization by the Bankruptcy Court.

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The Bankruptcy Code generally restricts payment of interest on pre-petition debt, subject to certain exceptions. However, the Bankruptcy Court ordered the payment of adequate protection amounts as discussed above and post-petition interest payments on EFIH First Lien Notes in connection with the settlement in June 2014 as discussed in Note 12. Additionally, the Bankruptcy Court approved post-petition interest payments on the EFIH Second Lien Notes in March 2015 as discussed in Note 13. Additional interest payments may also be made upon approval by the Bankruptcy Court (see Note 14). Other than these amounts ordered or approved by the Bankruptcy Court, effective April 29, 2014, we discontinued recording interest expense on outstanding pre-petition debt classified as liabilities subject to compromise (LSTC). The table below shows contractual interest amounts, which are amounts due under the contractual terms of the outstanding debt, including debt subject to compromise during the Chapter 11 Cases. Interest expense reported in the statements of consolidated income (loss) for the year ended December 31, 2015 and the post-petition period ended December 31, 2014 does not include $1.270 billion and $919 million, respectively, in contractual interest on pre-petition debt classified as LSTC, which has been stayed by the Bankruptcy Court effective on the Petition Date. For the year ended December 31, 2015 and the post-petition period ended December 31, 2014, adequate protection paid/accrued presented below excludes $60 million and $40 million, respectively, related to interest paid/accrued on the TCEH first-lien interest rate and commodity hedge claims (see Note 17), as such amounts are not included in contractual interest amounts below.

	Year Ended December 31, 2015
Entity:	Contractual Interest on Debt Classified as LSTC			Adequate Protection Paid/Accrued		Approved Interest Paid/Accrued (a)		Contractual Interest on Debt Classified as LSTC Not Paid/Accrued
EFH Corp.	$	125		$	—	$	—	$	125
EFIH	415			—		50		365
EFCH	7			—		—		7
TCEH	2,069			1,172		—		897
Eliminations (b)	(124		)	—		—		(124		)
Total	$	2,492		$	1,172	$	50	$	1,270

	Post-Petition Period Ended December 31, 2014
Entity:	Contractual Interest on Debt Classified as LSTC			Adequate Protection Paid/Accrued		Ordered Interest Paid/Accrued (a)		Contractual Interest on Debt Classified as LSTC Not Paid/Accrued
EFH Corp.	$	84		$	—	$	—	$	84
EFIH	363			—		54		309
EFCH	4			—		—		4
TCEH	1,392			787		—		605
Eliminations (b)	(83		)	—		—		(83		)
Total	$	1,760		$	787	$	54	$	919

___________

(a) For the year ended December 31, 2015 represents portion of interest related to the EFIH Second Lien Notes that was repaid based on the approval of the Bankruptcy Court; however, excludes $185 million of post-petition interest paid in 2015 that contractually related to 2014 and default interest (see Note 13). For the post-petition period ended December 31, 2014, represents interest on EFIH First Lien Notes exchanged and settled in June 2014 (see Note 12).

(b) Represents contractual interest on affiliate debt held by EFH Corp. and EFIH that is classified as LSTC.

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11. REORGANIZATION ITEMS

Expenses and income directly associated with the Chapter 11 Cases are reported separately in the statements of consolidated income (loss) as reorganization items as required by ASC 852, Reorganizations. Reorganization items also include adjustments to reflect the carrying value of liabilities subject to compromise (LSTC) at their estimated allowed claim amounts, as such adjustments are determined. The following table presents reorganization items incurred in the year ended December 31, 2015 and the post-petition period ended December 31, 2014 as reported in the statements of consolidated income (loss):

	Twelve Months Ended December 31, 2015			Post-Petition Period Ended December 31, 2014
Expenses related to legal advisory and representation services	$	310		$	127
Expenses related to other professional consulting and advisory services	128			95
Contract claims adjustments	52			20
Noncash adjustment for estimated allowed claims related to debt (Note 13)	926			—
Sponsor management agreement settlement (Notes 2 and 19)	(86		)	—
Contract assumption adjustments	(14		)	—
Noncash liability adjustment arising from termination of interest rate swaps (Note 13)	—			278
Fees associated with repayment of EFIH Second Lien Notes (Note 13)	28			—
Loss on exchange and settlement of EFIH First Lien Notes	—			108
Fees associated with completion and extension of the TCEH and EFIH DIP Facilities (Note 12)	9			187
Other	2			—
Total reorganization items	$	1,355		$	815

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12. DEBTOR-IN-POSSESSION BORROWING FACILITIES AND LONG-TERM DEBT NOT SUBJECT TO COMPROMISE

TCEH DIP Facility — The Bankruptcy Court approved the TCEH DIP Facility in June 2014. The TCEH DIP Facility currently provides for up to $3.375 billion in senior secured, super-priority financing consisting of a revolving credit facility of up to $1.95 billion and a term loan facility of up to $1.425 billion. The TCEH DIP Facility is a Senior Secured, Super-Priority Credit Agreement by and among the TCEH Debtors, the lenders that are party thereto from time to time and an administrative and collateral agent.

The TCEH DIP Facility and related available capacity at December 31, 2015 are presented below. Borrowings are reported in the consolidated balance sheets as borrowings under debtor-in-possession credit facilities. In October 2015, the TCEH Debtors paid an $8 million extension fee and extended the maturity date of the TCEH DIP Facility to the earlier of (a) November 2016 or (b) the effective date of any reorganization plan of TCEH. The terms of the facility were otherwise unchanged by the extension. In September 2015, the TCEH Debtors extended their use of cash collateral to the earlier of (a) the effective date of a plan of reorganization or (b) 60 days following termination of the Debtors' Plan Support Agreement, provided that the TCEH Debtors do not otherwise cause an event of default under the cash collateral order. The TCEH DIP Facility must be repaid in full prior to the TCEH Debtors emergence from the Chapter 11 Cases.

	December 31, 2015
TCEH DIP Facility	Facility Limit		Available Cash Borrowing Capacity		Available Letter of Credit Capacity
TCEH DIP Revolving Credit Facility (a)	$	1,950	$	1,950	$	—
TCEH DIP Term Loan Facility (b)	1,425		—		281
Total TCEH DIP Facility	$	3,375	$	1,950	$	281

___________

(a) Facility used for general corporate purposes. No amounts were borrowed at December 31, 2015. Pursuant to an order of the Bankruptcy Court, the TCEH Debtors may not have more than $1.650 billion of TCEH DIP Revolving Credit Facility cash borrowings outstanding without written consent of the TCEH committee of unsecured creditors and the ad hoc group of TCEH unsecured noteholders or further order of the Bankruptcy Court.

(b) Facility used for general corporate purposes, including but not limited to, $800 million for issuing letters of credit.

At both December 31, 2015 and 2014, all $1.425 billion of the TCEH DIP Term Loan Facility has been borrowed. Of this borrowing, $800 million represents amounts that support issuances of letters of credit and have been funded to a collateral account. Of the collateral account amount at December 31, 2015, $281 million is reported as cash and cash equivalents and $519 million is reported as restricted cash, which represents the amount of outstanding letters of credit. As discussed in Note 3, we intend to utilize a portion of the remaining available cash borrowing capacity under the TCEH DIP Revolving Credit Facility and cash on hand to fund the acquisition of La Frontera Holdings, LLC.

Amounts borrowed under the TCEH DIP Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 3%. At both December 31, 2015 and 2014, the interest rate on outstanding borrowings was 3.75%. The TCEH DIP Facility also provides for certain additional fees payable to the agents and lenders, as well as availability fees payable with respect to any unused portions of the available TCEH DIP Facility.

The TCEH Debtors' obligations under the TCEH DIP Facility are secured by a lien covering substantially all of the TCEH Debtors' assets, rights and properties, subject to certain exceptions set forth in the TCEH DIP Facility. The TCEH DIP Facility provides that all obligations thereunder constitute administrative expenses in the Chapter 11 Cases, with administrative priority and senior secured status under the Bankruptcy Code and, subject to certain exceptions set forth in the TCEH DIP Facility, have priority over any and all administrative expense claims, unsecured claims and costs and expenses in the Chapter 11 Cases. EFCH is a parent guarantor to the agreement governing the TCEH DIP Facility along with substantially all of TCEH’s subsidiaries, including all subsidiaries that are Debtors in the Chapter 11 Cases.

The TCEH DIP Facility also permits certain hedging agreements to be secured on a pari passu basis with the TCEH DIP Facility in the event those hedging agreements meet certain criteria set forth in the TCEH DIP Facility.

107

In June 2014, the RCT agreed to accept a collateral bond from TCEH of up to $1.1 billion, as a substitute for its self-bond, to secure mining land reclamation obligations. The collateral bond is a $1.1 billion carve-out from the super-priority liens under the TCEH DIP Facility that will enable the RCT to be paid before the TCEH DIP Facility lenders. As a result, in July 2014, TCEH terminated the $1.1 billion RCT Delayed Draw Letter of Credit commitment included in the original DIP facility.

The TCEH DIP Facility provides for affirmative and negative covenants applicable to the TCEH Debtors, including affirmative covenants requiring the TCEH Debtors to provide financial information, budgets and other information to the agents under the TCEH DIP Facility, and negative covenants restricting the TCEH Debtors' ability to incur additional indebtedness, grant liens, dispose of assets, make investments, pay dividends or take certain other actions, in each case except as permitted in the TCEH DIP Facility. The TCEH Debtors' ability to borrow under the TCEH DIP Facility is subject to the satisfaction of certain customary conditions precedent set forth therein.

The TCEH DIP Facility provides for certain customary events of default, including events of default resulting from non-payment of principal, interest or other amounts when due, material breaches of representations and warranties, material breaches of covenants in the TCEH DIP Facility or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against the TCEH Debtors. The agreement governing the TCEH DIP Facility includes a covenant that requires the Consolidated Superpriority Secured Net Debt to Consolidated EBITDA ratio not exceed 3.50 to 1.00. Consolidated Superpriority Secured Net Debt consists of outstanding term loans and revolving credit exposure under the TCEH DIP Facility less unrestricted cash. Upon the existence of an event of default, the TCEH DIP Facility provides that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

EFIH DIP Facility, EFIH First Lien Notes Settlement and EFIH Second Lien Notes Repayment — The Bankruptcy Court approved the EFIH DIP Facility in June 2014. The EFIH DIP Facility provides for a $5.4 billion first-lien debtor-in-possession financing facility. Since inception, the facility has been utilized as follows:

• In June 2014, $1.836 billion of loans issued under the facility were issued as an exchange to holders of $1.673 billion principal amount of EFIH First Lien Notes plus accrued and unpaid interest totaling $78 million. Holders of substantially all of the principal amount exchanged received as payment in full a principal amount of loans under the DIP facility equal to 105% of the principal amount of the notes held plus 101% of the accrued and unpaid interest at the non-default rate on such principal;

• In June 2014, $2.438 billion of cash borrowings were used to repay all remaining $2.312 billion principal amount of EFIH First Lien Notes (plus accrued and unpaid interest totaling $128 million), and

• In March 2015, $750 million of cash borrowings were used to repay $445 million principal amount of EFIH Second Lien Notes (including accrued and unpaid pre-petition interest of $55 million and post-petition interest of $235 million) and certain fees (see Note 13).

The exchange and settlement of the EFIH First Lien Notes in 2014 resulted in a loss of $108 million, reported in reorganization items, which represents the excess of the principal amounts of debt issued, cash repayments and deferred financing costs associated with the exchanged and settled debt over the carrying value of the exchanged and settled debt and related accrued interest.

As of December 31, 2015, remaining cash on hand from borrowings under the EFIH DIP Facility, net of fees, totaled approximately $354 million, which was held as cash and cash equivalents. In the December 31, 2015 consolidated balance sheet, the borrowings under the EFIH DIP Facility are reported as current liabilities since the maturity date of the facility is June 2016. In January 2016, the EFIH Debtors paid a $13.5 million extension fee to extend the maturity date of the EFIH DIP Facility to December 2016. The terms of the EFIH DIP Facility were otherwise unchanged. The EFIH DIP Facility must be repaid in full prior to the EFIH Debtors emergence from the Chapter 11 Cases.

The principal amounts outstanding under the EFIH DIP Facility bear interest based on applicable LIBOR rates, subject to a 1% floor, plus 3.25%. At both December 31, 2015 and 2014, outstanding borrowings under the EFIH DIP Facility totaled $5.4 billion at an annual interest rate of 4.25%. The EFIH DIP Facility is a non-amortizing loan that may, subject to certain limitations, be voluntarily prepaid by the EFIH Debtors, in whole or in part, without any premium or penalty.

The EFIH DIP Facility will mature on the earlier of (a) the effective date of any reorganization plan, (b) upon the event of the sale of substantially all of EFIH's assets or (c) December 2016.

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EFIH's obligations under the EFIH DIP Facility are secured by a first lien covering substantially all of EFIH's assets, rights and properties, subject to certain exceptions set forth in the EFIH DIP Facility. The EFIH DIP Facility provides that all obligations thereunder constitute administrative expenses in the Chapter 11 Cases, with administrative priority and senior secured status under the Bankruptcy Code and, subject to certain exceptions set forth in the EFIH DIP Facility, will have priority over any and all administrative expense claims, unsecured claims and costs and expenses in the Chapter 11 Cases.

The EFIH DIP Facility provides for affirmative and negative covenants applicable to EFIH and EFIH Finance, including affirmative covenants requiring EFIH and EFIH Finance to provide financial information, budgets and other information to the agents under the EFIH DIP Facility, and negative covenants restricting EFIH's and EFIH Finance's ability to incur additional indebtedness, grant liens, dispose of assets, pay dividends or take certain other actions, in each case except as permitted in the EFIH DIP Facility. The EFIH DIP Facility also includes a minimum liquidity covenant pursuant to which EFIH cannot allow the amount of its unrestricted cash (as defined in the EFIH DIP Facility) to be less than $150 million. As of December 31, 2015, EFIH was in compliance with this minimum liquidity covenant. The Oncor Ring-Fenced Entities are not restricted subsidiaries for purposes of the EFIH DIP Facility.

The EFIH DIP Facility provides for certain customary events of default, including events of default resulting from non-payment of principal, interest or other amounts when due, material breaches of representations and warranties, material breaches of covenants in the EFIH DIP Facility or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against EFIH. Upon the existence of an event of default, the EFIH DIP Facility provides that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

The EFIH DIP Facility permits, subject to certain terms, conditions and limitations set forth in the EFIH DIP Facility, EFIH to incur incremental junior lien subordinated debt in an aggregate amount not to exceed $3 billion.

Long-Term Debt Not Subject to Compromise — Amounts presented in the table below represent pre-petition liabilities that are not subject to compromise due to the debt being fully collateralized or specific orders from the Bankruptcy Court approving repayment of the debt.

	December 31,
	2015			2014
EFH Corp. (parent entity)
8.82% Non-Debtor Building Financing due semiannually through February 11, 2022	$	35		$	40
Unamortized fair value premium (a)	6			7
Total EFH Corp.	41			47
EFCH
9.58% Fixed Notes due in annual installments through December 4, 2019 (b)	13			21
8.254% Fixed Notes due in quarterly installments through December 31, 2021 (b)	24			29
Unamortized fair value discount (a)	(2		)	(3		)
Total EFCH	35			47
TCEH
7.48% Fixed Secured Facility Bonds with amortizing payments through January 2017 (c)	13			25
7.46% Fixed Secured Facility Bonds with amortizing payments through January 2015 (c)	—			4
Capital lease obligations	5			44
Other	2			2
Unamortized discount	(1		)	(2		)
Total TCEH	19			73
Total EFH Corp. consolidated	95			167
Less amounts due currently	(35		)	(39		)
Total long-term debt not subject to compromise	$	60		$	128

____________

(a) Amount represents unamortized fair value adjustments recorded under purchase accounting.

(b) Approved by the Bankruptcy Court for repayment.

(c) Debt issued by trust and secured by assets held by the trust.

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13. LIABILITIES SUBJECT TO COMPROMISE

The amounts classified as liabilities subject to compromise (LSTC) reflect the company's estimate of pre-petition liabilities and other expected allowed claims to be addressed in the Chapter 11 Cases and may be subject to future adjustment as the Chapter 11 Cases proceed. Prior to December 2015, debt amounts include related unamortized deferred financing costs and discounts/premiums. Amounts classified to LSTC do not include pre-petition liabilities that are fully collateralized by letters of credit or cash deposits. The following table presents LSTC as reported in the consolidated balance sheets at December 31, 2015 and 2014:

	December 31,
	2015		2014
Notes, loans and other debt per the following table	$	35,560	$	35,124
Accrued interest on notes, loans and other debt	745		804
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements (Note 17)	1,243		1,235
Trade accounts payable and other expected allowed claims	238		269
Total liabilities subject to compromise	$	37,786	$	37,432

Pre-Petition Notes, Loans and Other Debt Reported as Liabilities Subject to Compromise

Amounts presented below represent principal amounts of pre-petition notes, loans and other debt reported as liabilities subject to compromise.

	December 31,
	2015		2014
EFH Corp. (parent entity)
9.75% Fixed Senior Notes due October 15, 2019	$	2	$	2
10% Fixed Senior Notes due January 15, 2020	3		3
10.875% Fixed Senior Notes due November 1, 2017	33		33
11.25% / 12.00% Senior Toggle Notes due November 1, 2017	27		27
5.55% Fixed Series P Senior Notes due November 15, 2014 (a)	89		90
6.50% Fixed Series Q Senior Notes due November 15, 2024 (a)	198		201
6.55% Fixed Series R Senior Notes due November 15, 2034 (a)	288		291
Unamortized fair value discount (b)	—		(118		)
Total EFH Corp.	640		529
EFIH
11% Fixed Senior Secured Second Lien Notes due October 1, 2021	322		406
11.75% Fixed Senior Secured Second Lien Notes due March 1, 2022	1,389		1,750
11.25% / 12.25% Senior Toggle Notes due December 1, 2018	1,530		1,566
9.75% Fixed Senior Notes due October 15, 2019	2		2
Unamortized premium (b)	—		243
Unamortized discount (b)	—		(121		)
Total EFIH	3,243		3,846
EFCH
Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037	1		1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037	8		8
Unamortized fair value discount (b)	—		(1		)
Total EFCH	9		8
TCEH
Senior Secured Facilities:
TCEH Floating Rate Term Loan Facilities due October 10, 2014	3,809		3,809
TCEH Floating Rate Letter of Credit Facility due October 10, 2014	42		42
TCEH Floating Rate Revolving Credit Facility due October 10, 2016	$	2,054	$	2,054

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	December 31,
	2015		2014
TCEH Floating Rate Term Loan Facilities due October 10, 2017 (a)	15,691		15,691
TCEH Floating Rate Letter of Credit Facility due October 10, 2017	1,020		1,020
11.5% Fixed Senior Secured Notes due October 1, 2020	1,750		1,750
15% Fixed Senior Secured Second Lien Notes due April 1, 2021	336		336
15% Fixed Senior Secured Second Lien Notes due April 1, 2021, Series B	1,235		1,235
10.25% Fixed Senior Notes due November 1, 2015 (a)	1,833		1,833
10.25% Fixed Senior Notes due November 1, 2015, Series B (a)	1,292		1,292
10.50% / 11.25% Senior Toggle Notes due November 1, 2016	1,749		1,749
Pollution Control Revenue Bonds:
Brazos River Authority:
5.40% Fixed Series 1994A due May 1, 2029	39		39
7.70% Fixed Series 1999A due April 1, 2033	111		111
7.70% Fixed Series 1999C due March 1, 2032	50		50
8.25% Fixed Series 2001A due October 1, 2030	71		71
8.25% Fixed Series 2001D-1 due May 1, 2033	171		171
6.30% Fixed Series 2003B due July 1, 2032	39		39
6.75% Fixed Series 2003C due October 1, 2038	52		52
5.40% Fixed Series 2003D due October 1, 2029	31		31
5.00% Fixed Series 2006 due March 1, 2041	100		100
Sabine River Authority of Texas:
6.45% Fixed Series 2000A due June 1, 2021	51		51
5.20% Fixed Series 2001C due May 1, 2028	70		70
5.80% Fixed Series 2003A due July 1, 2022	12		12
6.15% Fixed Series 2003B due August 1, 2022	45		45
Trinity River Authority of Texas:
6.25% Fixed Series 2000A due May 1, 2028	14		14
Unamortized fair value discount related to pollution control revenue bonds (b)	—		(103		)
Other:
Other	1		1
Unamortized discount (b)	—		(91		)
Total TCEH	31,668		31,474
Deferred debt issuance and extension costs (b)	—		(733		)
Total EFH Corp. consolidated notes, loans and other debt	$	35,560	$	35,124

___________

(a) Excludes the following principal amounts of debt held by EFIH or EFH Corp. (parent entity). The amounts of TCEH debt held by EFIH or EFH Corp. (parent entity) were eliminated as a result of the Settlement Agreement approved by the Bankruptcy Court in December 2015. See Note 2 for discussion of the Settlement Agreement.

.

	December 31,
	2014
EFH Corp. 5.55% Fixed Series P Senior Notes due November 15, 2014	281
EFH Corp. 6.50% Fixed Series Q Senior Notes due November 15, 2024	545
EFH Corp. 6.55% Fixed Series R Senior Notes due November 15, 2034	456
TCEH Floating Rate Term Loan Facilities due October 10, 2017	19
TCEH 10.25% Fixed Senior Notes due November 1, 2015	213
TCEH 10.25% Fixed Senior Notes due November 1, 2015, Series B	150
Total	$	1,664

(b) Due to the Settlement Agreement our pre-petition notes, loans and other debt reported as liabilities subject to compromise were updated to reflect our expected allowed claim amounts, resulting in the write-off to reorganization items of unamortized deferred debt issuance and extension costs, premiums and discounts classified as LSTC (see Note 11).

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Repayment of EFIH Notes

In March 2015, with the approval of the Bankruptcy Court, EFIH used some of its cash to repay (Repayment) $735 million, including interest at contractual rates, in amounts outstanding under EFIH's pre-petition 11.00% Fixed Senior Secured Second Lien Notes due October 1, 2021 (11.00% Notes) and 11.75% Fixed Senior Secured Second Lien Notes due March 1, 2022 (11.75% Notes) and $15 million in certain fees and expenses of the trustee for such notes. The Repayment resulted in an $84 million reduction in the principal amount of the 11.00% Notes, a $361 million reduction in the principal amount of the 11.75% Notes and the payment of $235 million and $55 million of accrued and unpaid post-petition and pre-petition interest, respectively, at contractual rates. The Repayment required the requisite consent of the lenders under EFIH's DIP Facility. EFIH received such consent from approximately 97% of the lenders under the EFIH DIP Facility in consideration of an aggregate consent fee equal to approximately $13 million. As a result of the Repayment, as of December 31, 2015, the principal amount outstanding on the 11.00% Notes and 11.75% Notes are $322 million and $1.389 billion, respectively.

Charging Lien Advances

In December 2015, the Bankruptcy Court approved certain charging lien advances related to pre-petition debt of both EFH Corp. and EFIH. Pursuant to those charging lien advances, the Debtors paid approximately $36 million to reduce EFIH Toggle Notes and accrued approximately $7 million to reduce EFH Corp. 5.55% Series P Notes due 2014, 6.50% Series Q Notes due 2024 and 6.55% Series R Notes due 2034.

TCEH Letter of Credit Facility Activity

Borrowings under the TCEH Letter of Credit Facility have been recorded by TCEH as restricted cash that supports issuances of letters of credit. At December 31, 2015, the restricted cash related to the pre-petition TCEH Letter of Credit Facility totaled $507 million, and there were no outstanding letters of credit related to the pre-petition TCEH Letter of Credit Facility. Due to the default under the pre-petition TCEH Senior Secured Facilities, the letter of credit capacity is no longer available. In the first quarter of 2014, TCEH issued a $157 million letter of credit to a subsidiary of EFH Corp. to secure its current and future amounts payable to the subsidiary arising from recurring transactions in the normal course of business, and in 2014, the subsidiary drew on the letter of credit in the amount of $150 million to settle amounts due from TCEH. The remaining $7 million under the letter of credit expired in July 2014. For the years ended December 31, 2015 and 2014, $45 million and $245 million, respectively, of letters of credit were drawn upon by counterparties to settle amounts due from TCEH. Included in the year ended December 31, 2015 amount was $20 million drawn by certain executive officers to satisfy payments related to long-term incentive awards, and included in the year ended December 31, 2014 amount was $204 million related to pollution control revenue bonds that were tendered as noted below.

Debt Related Activity in 2014

Repayments of debt in the year ended December 31, 2014 totaled $241 million and consisted of $233 million of payments of principal at scheduled maturity or mandatory tender and remarketing dates (including $204 million of pollution control revenue bond and $11 million of fixed secured facility bond payments) and $8 million of contractual payments under capital leases.

Information Regarding Significant Pre-Petition Debt

TCEH elected not to make interest payments due in April 2014 totaling $123 million on certain debt obligations.

112

The TCEH pre-petition debt described below is junior in right of priority and payment to the TCEH DIP Facility, and the EFIH pre-petition debt (including EFIH's guarantee of the EFH Corp. debt) described below is junior in right of priority and payment to the EFIH DIP Facility.

TCEH Senior Secured Facilities —Borrowings under the TCEH Senior Secured Facilities total $22.616 billion and consist of:

• $3.809 billion of TCEH Term Loan Facilities with interest at LIBOR plus 3.50%;

• $15.691 billion of TCEH Term Loan Facilities with interest at LIBOR plus 4.50%;

• $42 million of cash borrowed under the TCEH Letter of Credit Facility with interest at LIBOR plus 3.50%;

• $1.020 billion of cash borrowed under the TCEH Letter of Credit Facility with interest at LIBOR plus 4.50%, and

• Amounts borrowed under the TCEH Revolving Credit Facility, which represent the entire amount of commitments under the facility totaling $2.054 billion.

The TCEH Senior Secured Facilities are fully and unconditionally guaranteed jointly and severally on a senior secured basis by EFCH, and subject to certain exceptions, each existing and future direct or indirect wholly owned US subsidiary of TCEH. The TCEH Senior Secured Facilities, the TCEH Senior Secured Notes and the TCEH first lien hedges (or any termination amounts related thereto), discussed below, are secured on a first priority basis by (i) substantially all of the current and future assets of TCEH and TCEH's subsidiaries who are guarantors of such facilities and (ii) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

TCEH 11.5% Senior Secured Notes —The principal amount of the TCEH 11.5% Senior Secured Notes totals $1.750 billion, with interest payable at a fixed rate of 11.5% per annum. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The notes are secured, on a first-priority basis, by security interests in all of the assets of TCEH, and the guarantees are secured on a first-priority basis by all of the assets and equity interests held by the Guarantors, in each case, to the extent such assets and equity interests secure obligations under the TCEH Senior Secured Facilities (the TCEH Collateral), subject to certain exceptions and permitted liens.

The notes are (i) senior obligations and rank equally in right of payment with all senior indebtedness of TCEH, (ii) senior in right of payment to all existing or future unsecured and second-priority secured debt of TCEH to the extent of the value of the TCEH Collateral and (iii) senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

The guarantees of the TCEH Senior Secured Notes by the Guarantors are effectively senior to any unsecured and second-priority debt of the Guarantors to the extent of the value of the TCEH Collateral. The guarantees are effectively subordinated to all debt of the Guarantors secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt.

TCEH 15% Senior Secured Second Lien Notes(including Series B) — The principal amount of the TCEH 15% Senior Secured Second Lien Notes totals $1.571 billion with interest at a fixed rate of 15% per annum. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities. The notes are secured, on a second-priority basis, by security interests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to the extent such assets and security interests secure obligations under the TCEH Senior Secured Facilities on a first-priority basis, subject to certain exceptions (including the elimination of the pledge of equity interests of any Subsidiary Guarantor to the extent that separate financial statements would be required to be filed with the SEC for such Subsidiary Guarantor under Rule 3-16 of Regulation S-X) and permitted liens. The guarantee from EFCH is not secured.

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The notes are senior obligations of the issuer and rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH Senior Secured Facilities, the TCEH Senior Secured Notes and TCEH's commodity and interest rate hedges that are secured by a first-priority lien on the TCEH Collateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent of the value of the TCEH Collateral, and to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

The guarantees of the TCEH Senior Secured Second Lien Notes by the Subsidiary Guarantors are effectively senior to any unsecured debt of the Subsidiary Guarantors to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral). These guarantees are effectively subordinated to all debt of the Subsidiary Guarantors secured by the TCEH Collateral on a first-priority basis or that is secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt. EFCH's guarantee ranks equally with its unsecured debt (including debt it guarantees on an unsecured basis) and is effectively subordinated to any of its secured debt to the extent of the value of the collateral securing that debt.

TCEH 10.25% Senior Notes (including Series B) and 10.50%/11.25% Senior Toggle Notes (collectively, the TCEH Senior Notes)— The principal amount of the TCEH Senior Notes totals $4.874 billion, and the notes are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH's direct parent, EFCH, and by each subsidiary that guarantees the TCEH Senior Secured Facilities. The TCEH 10.25% Notes bore interest at a fixed rate of 10.25% per annum. The TCEH Toggle Notes bore interest at a fixed rate of 10.50% per annum.

EFIH 6.875% Senior Secured First Lien Notes — There were no principal amounts of the EFIH 6.875% Notes outstanding at December 31, 2015 as the notes were exchanged or settled in June 2014 as discussed in Note 12. The notes bore interest at a fixed rate of 6.875% per annum. The EFIH 6.875% Notes were secured on a first-priority basis by EFIH's pledge of its 100% ownership of the membership interests in Oncor Holdings (the EFIH Collateral) on an equal and ratable basis with the EFIH 10% Notes (discussed below).

EFIH 10% Senior Secured First Lien Notes — There were no principal amounts of the EFIH 10% Notes outstanding at December 31, 2015 as the notes were exchanged or settled in June 2014 as discussed in Note 12. The notes bore interest at a fixed rate of 10% per annum. The notes were secured by the EFIH Collateral on an equal and ratable basis with the EFIH 6.875% Notes.

EFIH 11% Senior Secured Second Lien Notes — The principal amount of the EFIH 11% Notes totals $322 million with interest at a fixed rate of 11% per annum. The EFIH 11% Notes are secured on a second-priority basis by the EFIH Collateral on an equal and ratable basis with the EFIH 11.75% Notes. See discussion above related to the repayment of a portion of these notes in March 2015.

The EFIH 11% Notes are senior obligations of EFIH and EFIH Finance and rank equally in right of payment with all senior indebtedness of EFIH and are effectively senior in right of payment to all existing or future unsecured debt of EFIH to the extent of the value of the EFIH Collateral. The notes have substantially the same terms as the EFIH 11.75% Notes discussed below, and the holders of the EFIH 11% Notes will generally vote as a single class with the holders of the EFIH 11.75% Notes.

EFIH 11.75% Senior Secured Second Lien Notes —The principal amount of the EFIH 11.75% Notes totals $1.389 billion with interest at a fixed rate of 11.75% per annum. The EFIH 11.75% Notes are secured on a second-priority basis by the EFIH Collateral on an equal and ratable basis with the EFIH 11% Notes. The EFIH 11.75% Notes have substantially the same covenants as the EFIH 11% Notes, and the holders of the EFIH 11.75% Notes will generally vote as a single class with the holders of the EFIH 11% Notes. See discussion above related to the repayment of a portion of these notes in March 2015.

The EFIH 11.75% Notes were issued in private placements and are not registered under the Securities Act. EFIH had agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH 11.75% Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable notes for the EFIH 11.75% Notes. Because the exchange offer was not completed, the annual interest rate on the EFIH 11.75% Notes increased by 25 basis points (to 12.00%) in February 2013 and by an additional 25 basis points (to 12.25%) in May 2013.

114

EFIH 11.25%/12.25% Senior Toggle Notes — The principal amount of the EFIH Toggle Notes totals $1.530 billion with interest at a fixed rate of 11.25% per annum for cash interest and 12.25% per annum for PIK Interest. The terms of the Toggle Notes include an election by EFIH, for any interest period until June 1, 2016, to pay interest on the Toggle Notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFIH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. EFIH made its pre-petition interest payments on the EFIH Toggle Notes by using the PIK feature of those notes.

The EFIH Toggle Notes were issued in private placements and are not registered under the Securities Act. EFIH had agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH Toggle Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable notes for the EFIH Toggle Notes. Because the exchange offer was not completed, the annual interest rate on the EFIH Toggle Notes increased by 25 basis points (to 11.50%) in December 2013 and by an additional 25 basis points (to 11.75%) in March 2014.

EFH Corp. 10.875% Senior Notes and 11.25%/12.00% Senior Toggle Notes — The collective principal amount of these notes totals $60 million. The notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by EFCH and EFIH. The notes bore interest at a fixed rate for the 10.875% Notes of 10.875% per annum and at a fixed rate for the Toggle Notes of 11.25% per annum.

Material Cross Default/Acceleration Provisions — Certain of our pre-petition financing arrangements contain provisions that result in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenants that could or does result in an acceleration of payments due. Such provisions are referred to as "cross default" or "cross acceleration" provisions. The Bankruptcy Filing triggered defaults on our pre-petition debt obligations, but pursuant to the Bankruptcy Code, the creditors are stayed from taking any actions against the Debtors as a result of such defaults.

Intercreditor Agreement — TCEH has entered into an intercreditor agreement with Citibank, N.A. and five secured commodity hedge counterparties (the Secured Commodity Hedge Counterparties). The intercreditor agreement takes into account, among other things, the possibility that TCEH could have issued notes and/or loans secured by collateral (other than the collateral that secures the TCEH Senior Secured Facilities) that ranks on parity with, or junior to, TCEH's existing first lien obligations under the TCEH Senior Secured Facilities. The Intercreditor Agreement provides that the lien granted to the Secured Commodity Hedge Counterparties ranks pari passu with the lien granted with respect to the collateral of the secured parties under the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties are entitled to share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral in an amount provided in the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties have voting rights with respect to any amendment or waiver of any provision of the Intercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties' lien on such collateral relative to the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to the Secured Commodity Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the lien granted to the secured parties under the TCEH Senior Secured Facilities.

Second Lien Intercreditor Agreement — TCEH has also entered into a second lien intercreditor agreement (the Second Lien Intercreditor Agreement) with Citibank, N.A., as senior collateral agent, and The Bank of New York Mellon Trust Company, N.A., as initial second priority representative. The Second Lien Intercreditor Agreement provides that liens on the collateral that secure the obligations under the TCEH Senior Secured Facilities, the obligations of the Secured Commodity Hedge Counterparties and any other obligations which are permitted to be secured on a pari passu basis therewith (collectively, the First Lien Obligations) rank prior to the liens on such collateral securing the obligations under the TCEH Senior Secured Second Lien Notes, and any other obligations which are permitted to be secured on a pari passu basis (collectively, the Second Lien Obligations). The Second Lien Intercreditor Agreement provides that the holders of the First Lien Obligations are entitled to the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral until paid in full, and that the holders of the Second Lien Obligations are not entitled to receive any such proceeds until the First Lien Obligations have been paid in full. The Second Lien Intercreditor Agreement also provides that the holders of the First Lien Obligations control enforcement actions with respect to such collateral, and the holders of the Second Lien Obligations are not entitled to commence any such enforcement actions, with limited exceptions. The Second Lien Intercreditor Agreement also provides that releases of the liens on the collateral by the holders of the First Lien Obligations automatically require that the liens on such collateral by the holders of the Second Lien Obligations be automatically released, and that amendments, waivers or consents with respect to any of the collateral documents in connection with the First Lien Obligations apply automatically to any comparable provision of the collateral documents in connection with the Second Lien Obligations.

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EFIH Collateral Trust Agreement — EFIH entered into a Collateral Trust Agreement, among EFIH, Delaware Trust Company, as First Lien Successor Trustee, the other Secured Debt Representatives named therein and the Collateral Trustee. The Collateral Trust Agreement governing the pledge of collateral generally provides that the holders of a majority of the debt secured by a first priority lien on the collateral, including the notes and other future debt incurred by EFH or EFIH secured by the collateral equally and ratably, have, subject to certain limited exceptions, the exclusive right to manage, perform and enforce the terms of the security documents securing the rights of secured debt holders in the collateral, and to exercise and enforce all privileges, rights and remedies thereunder.

14. COMMITMENTS AND CONTINGENCIES

Contractual Commitments

At December 31, 2015, we had contractual commitments under energy-related contracts, leases and other agreements, some of which remain subject to potential rejection in the Chapter 11 Cases, as follows:

	Coal purchase  and transportation agreements		Pipeline transportation and storage reservation fees		Nuclear Fuel Contracts		Other Contracts
2016	$	307	$	13	$	62	$	130
2017	—		1		46		42
2018	—		1		72		14
2019	—		1		35		12
2020	—		1		37		14
Thereafter	—		7		96		36
Total	$	307	$	24	$	348	$	248

Expenditures under our coal purchase and coal transportation agreements totaled $218 million, $348 million and $353 million for the years ended December 31, 2015, 2014 and 2013, respectively.

At December 31, 2015, future minimum lease payments under both capital leases and operating leases are as follows:

	Capital Leases		Operating Leases (a)
2016	$	3	$	26
2017	2		32
2018	—		30
2019	—		28
2020	—		26
Thereafter	—		139
Total future minimum lease payments	5		$	281
Less amounts representing interest	—
Present value of future minimum lease payments	5
Less current portion	3
Long-term capital lease obligation	$	2

___________

(a) Includes operating leases with initial or remaining noncancellable lease terms in excess of one year.

Rent reported as operating costs, fuel costs and SG&A expenses totaled $84 million, $84 million and $90 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Guarantees

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

See Notes 12 and 13 for discussion of guarantees and security for certain of our post-petition and pre-petition debt.

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Letters of Credit

At December 31, 2015, TCEH had outstanding letters of credit under the TCEH DIP Facility totaling $519 million as follows:

• $230 million to support commodity risk management and trading margin requirements in the normal course of business, including over-the-counter and exchange-traded hedging transactions and collateral postings with ERCOT;

• $72 million to support executory contracts and insurance agreements;

• $55 million to support TCEH's REP financial requirements with the PUCT, and

• $162 million for other credit support requirements, including $131 million to support our purchase and sale agreement with La Frontera Holdings, LLC.

The automatic stay under the Bankruptcy Code does not apply to letters of credit issued under the pre-petition credit facility and third parties may draw if the terms of a particular letter of credit so provide. See Note 13 for discussion of letter of credit draws in 2015 and 2014.

Litigation

Aurelius Derivative Claim — Aurelius Capital Master, Ltd. and ACP Master, Ltd. (Aurelius) filed a lawsuit in March 2013, amended in May 2013, in the US District Court for the Northern District of Texas (Dallas Division) against EFCH as a nominal defendant and each of the current directors and a former director of EFCH. In the lawsuit, Aurelius, as a creditor under the TCEH Senior Secured Facilities and certain TCEH secured bonds, both of which are guaranteed by EFCH, filed a derivative claim against EFCH and its directors. Aurelius alleged that the directors of EFCH breached their fiduciary duties to EFCH and its creditors, including Aurelius, by permitting TCEH to make certain loans "without collecting fair and reasonably equivalent value." The lawsuit sought recovery for the benefit of EFCH. In January 2014, the district court granted EFCH's and the directors' motion to dismiss and in February 2014 dismissed the lawsuit. Aurelius has appealed the district court's judgment to the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court). The appeal was automatically stayed as a result of the Bankruptcy Filing. We cannot predict the outcome of this proceeding, including the financial effects, if any.

Make-whole Claims — In May 2014, the indenture trustee for the EFIH 10% First Lien Notes initiated litigation in the Bankruptcy Court seeking, among other things, a declaratory judgment that EFIH is obligated to pay a make-whole premium in connection with the cash repayment of the EFIH First Lien Notes discussed in Note 12 and that such make-whole premium is an allowed secured claim, or in the alternative, an allowed secured or unsecured claim for breach of contract (EFIH First Lien Make-whole Claims). The indenture trustee has alleged that the EFIH First Lien Make-whole Claims are valued at approximately $432 million plus reimbursement of expenses. In separate rulings in March and July 2015, the Bankruptcy Court found that no make-whole premium is due with respect to the EFIH 10% First Lien Notes. In July 2015, the indenture trustee appealed the Bankruptcy Court's ruling to the United States District Court for the District of Delaware and in February 2016 that court affirmed the Bankruptcy Court's rulings. In February 2016, the Indenture Trustee appealed the District Court's ruling to the Third Circuit Court of Appeals. The EFIH Debtors intend to vigorously defend against this appeal. We cannot predict the outcome of this appeal.

In June 2014, the indenture trustee for the EFIH Second Lien Notes initiated litigation in the Bankruptcy Court seeking similar relief with respect to the EFIH Second Lien Notes, including among other things, that EFIH is obligated to pay a make-whole premium in connection with any repayment of the EFIH Second Lien Notes and that such make-whole premium would be an allowed secured claim, or in the alternative, an allowed secured or unsecured claim for breach of contract (the EFIH Second Lien Make-whole Claims). If, as of December 31, 2015, the EFIH Second Lien Make-whole Claims were allowed, the amount of such claims would have been approximately $401 million plus reimbursement of expenses. In October 2015, the Bankruptcy Court issued a ruling and order in favor of the EFIH Debtors. The order and ruling found that no make-whole premium is due with respect to the EFIH Second Lien Notes. In November 2015, the indenture trustee appealed the Bankruptcy Court's ruling to the United States District Court for the District of Delaware. Briefing is complete, but oral argument has not yet been scheduled. The EFIH Debtors intend to vigorously defend against this appeal. We cannot predict the outcome of this appeal.

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In December 2014, the EFIH Debtors initiated litigation against the indenture trustee for the EFIH PIK Notes seeking, among other things, a declaratory judgment that EFIH is not obligated to pay a redemption or make-whole premium in connection with the cash repayment of the EFIH PIK Notes and that any post-petition interest owing on these notes is to be paid at the statutory Federal Judgment Rate of interest. In June 2015, the Bankruptcy Court issued an opinion and entered an order dismissing the EFIH Debtors' adversary proceeding. However, in its opinion, the Bankruptcy Court noted that as an alternative the EFIH Debtors may file a claim objection to the EFIH PIK noteholders' claims made in the Chapter 11 Cases. In July 2015, the EFIH Debtors filed a claim objection with the Bankruptcy Court regarding the EFIH PIK noteholders' claims for a redemption premium and post-petition interest at the contract rate under the EFIH PIK Notes. In October 2015, the Bankruptcy Court issued opinions in favor of the EFIH Debtors. One opinion found that no make-whole premium is due with respect to the EFIH PIK Notes. The second opinion found that the EFIH PIK noteholders' allowed claim does not, as a matter of law, include post-petition interest whether at the contract rate or the Federal Judgment Rate. This opinion did find, however, that, in connection with the confirmation of a Plan of Reorganization, the Bankruptcy Court could, at its discretion, grant post-petition interest as part of the EFIH PIK noteholders' allowed claim under general principals of equity and that such grant could be at the contract rate, the Federal Judgment Rate or any other amount that the Bankruptcy Court determines to be equitable. In November 2015, a majority of the EFIH PIK Noteholders settled their claims contingent on the Plan of Reorganization becoming effective. These settling noteholders have appealed both of the Bankruptcy Court's rulings to the United States District Court for the District of Delaware. Those appeals have been stayed, and if the Plan of Reorganization becomes effective, those appeals will likely be moot. If the Plan of Reorganization does not become effective, those appeals may be revived. Some EFIH PIK Noteholders have not settled their claims. They have appealed the Bankruptcy Court's ruling on post-petition interest to the United States District Court for the District of Delaware. That appeal has also been stayed. The non-settling EFIH PIK Noteholders have also sought to be awarded post-petition interest through an equitable proceeding suggested by the Bankruptcy Court’s second opinion. No briefing schedule has been set for that equitable proceeding. The EFIH Debtors intend to vigorously defend against the award of post-petition interest at a rate higher than the Federal Judgment Rate. We cannot predict the outcome of either of these appeals or any equitable proceeding seeking the award of post-petition interest.

In October 2015, EFH Corp. filed a claim objection with the Bankruptcy Court with respect to the EFH Corp. Series P, Q and R Senior Notes (collectively, the EFH Legacy Notes) noteholders' claims for, among other things, make-whole premiums and post-petition interest. If, as of December 31, 2015, a make-whole claim and a post-petition interest claim were allowed, such claims would be $208 million and $66 million, respectively. In October 2015, the indenture trustee for the EFH Legacy Notes filed a response to this claim objection. No argument date has been set by the Bankruptcy Court regarding the EFH Legacy Notes claim objection. In November 2015, these claims were settled contingent on the Plan of Reorganization becoming effective. If the Plan of Reorganization does not become effective, the claims related to the EFH Legacy Notes may be revived. In that case, EFH Corp. would vigorously pursue its claim objection. We cannot predict the outcome of this proceeding.

In October 2015, EFH Corp. filed a claim objection with the Bankruptcy Court with respect to the EFH Corp. 10.875% Senior Notes and 11.25%/12% Senior Toggle Notes (collectively, the EFH LBO Notes) noteholders' claims for, among other things, optional redemption payment and post-petition interest. If, as of December 31, 2015, a redemption claim and a post-petition interest claim were allowed, such claims would be zero and $13 million, respectively. The indenture trustee for the EFH LBO Notes has not yet filed a response to this claim objection. No argument date has been set by the Bankruptcy Court regarding the EFH LBO Notes claim objection. In November 2015, these claims were settled contingent on the Plan of Reorganization becoming effective. If the Plan of Reorganization does not become effective, these claims may be revived. In that case, EFH Corp. would vigorously pursue is claim objection. We cannot predict the outcome of this proceeding.

In addition, creditors may make additional claims in the Chapter 11 Cases for make-whole or redemption premiums in connection with repayments or settlement of other pre-petition debt. These claims could be material. There can be no assurance regarding the outcome of any of the litigation regarding the validity or, if deemed valid, the amount of these make-whole or redemption claims.

Potential Inter/Intra Debtor Claims— In August 2014, the Bankruptcy Court entered an order in the Chapter 11 Cases establishing discovery procedures governing, among other things, certain prepetition transactions among the various Debtors' estates. In February 2015, the ad hoc group of TCEH unsecured creditors; the official committee representing unsecured interests at EFCH and its direct subsidiary, TCEH; and the official committee representing unsecured interests at EFH and EFIH filed motions with the Bankruptcy Court seeking standing to prosecute derivative claims on behalf of TCEH relating to certain of these prepetition transactions. These claims were released effective when the Bankruptcy Court approved the Settlement Agreement.

The Settlement Agreement was approved in December 2015 and is expected to remain effective even if the Plan of Reorganization does not become effective.

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Adversary Complaint against Texas Transmission — In October 2015, as contemplated by the Merger and Purchase Agreement, EFH Corp. filed with the Bankruptcy Court an adversary complaint against Texas Transmission seeking a judgment from the Bankruptcy Court ordering Texas Transmission to comply with its obligation under the Investor Rights Agreement in connection with the transactions contemplated by the Merger and Purchase Agreement, including (a) in connection with the closing of the merger, selling its interests in Oncor to the Investor Group at the same price that the Investor Group has agreed to purchase EFH Corp equity under the Merger and Purchase Agreement and (b) cooperating with Oncor and EFH Corp. in implementing the IPO Conversion Plan contemplated by the Merger and Purchase Agreement in order to effectuate the REIT. In December 2015, the Bankruptcy Court denied Texas Transmission's motion to dismiss EFH Corp.'s adversary complaint. The Bankruptcy Court has scheduled a trial in March 2016 for this claim. We intend to vigorously pursue this claim, but we cannot predict the ultimate outcome of this proceeding.

Litigation Related to EPA Reviews — In June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of the Clean Air Act (CAA). The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. In April 2013, we received an additional information request from the EPA under Section 114 related to the Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to the Sandow 4 generation facility.

In July 2012, the EPA sent us a notice of violation alleging noncompliance with the CAA's New Source Review Standards and the air permits at our Martin Lake and Big Brown generation facilities. In July 2013, the EPA sent us a second notice of violation alleging noncompliance with the CAA's New Source Review Standards at our Martin Lake and Big Brown generation facilities, which the EPA said "superseded" its July 2012 notice. In August 2013, the US Department of Justice, acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant Generation Company LLC and Big Brown Power Company LLC in federal district court in Dallas, alleging violations of the CAA at our Big Brown and Martin Lake generation facilities. In August 2015, the district court issued its ruling on our motion to dismiss and granted the motion as to seven of the nine claims asserted by the EPA in the lawsuit. Two claims remain before the district court, and those are currently scheduled for trial in October 2017. We believe that we have complied with all requirements of the CAA and intend to vigorously defend against the remaining allegations. The lawsuit requests the maximum civil penalties available under the CAA to the government of up to $32,500 to $37,500 per day for each alleged violation, depending on the date of the alleged violation, and injunctive relief, including an order requiring the installation of best available control technology at the affected units. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. We cannot predict the outcome of these proceedings, including the financial effects, if any.

Greenhouse Gas Emissions —In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from new, modified and reconstructed units, and existing electricity generation plants. The rule for existing facilities would establish state-specific emissions rate goals to reduce nationwide CO₂ emissions related to affected electricity generation units by over 30% from 2012 emission levels by 2030. A number of parties, including Luminant, filed petitions for review in the D.C. Circuit Court for the rule for new, modified and reconstructed plants. In addition, a number of petitions for review of the rule for existing plants were filed in the D.C. Circuit Court by various parties and groups, including challenges from twenty-seven different states opposed to the rule as well as those from, among others, certain power generating companies, various business groups and some labor unions. Luminant also filed its own petition for review. In addition, several parties have filed motions to stay the implementation of the rule while the court reviews the legality of the rule for existing units. In January 2016, the D.C. Circuit Court denied the motion to stay and ordered an expedited briefing on the merits. Oral argument is scheduled for June 2016. In January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the US Supreme Court asking that the court stay the rule. In February 2016, the US Supreme Court stayed the rule pending the conclusion of legal challenges on the rule before the D.C. Circuit Court and until the US Supreme Court disposes of any subsequent petition for review. While we cannot predict the outcome of this rulemaking and legal proceedings on our results of operations, liquidity or financial condition, the impacts could be material.

In August 2015, the EPA proposed model rules and federal plan requirements for states to consider as they develop state plans to comply with the rules for GHG emissions. A federal plan would then be finalized for a state if a state fails to submit a state plan by the deadlines established in the CAA for existing plants or if the EPA disapproves a submitted state plan. We filed comments on the federal plan proposal in January 2016. The EPA is expected to finalize the model rule by the summer of 2016. While we cannot predict the outcome of this rulemaking and legal proceedings on our results of operations, liquidity or financial condition, the impacts could be material.

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Cross-State Air Pollution Rule (CSAPR)

In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions from our fossil fueled generation units. In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule. In June 2012, the EPA finalized the proposed rule (Second Revised Rule). As compared to the proposed revisions to the CSAPR issued by the EPA in October 2011, the Final Revisions and the Second Revised Rule finalize emissions budgets for our generation assets that are approximately 6% lower for SO₂, 3% higher for annual NO_x and 2% higher for seasonal NO_x.

The CSAPR became effective January 1, 2015. In July 2015, following a remand of the case from the US Supreme Court to consider further legal challenges, the D.C. Circuit Court unanimously ruled in favor of us and other petitioners, holding that the CSAPR emissions budgets over-controlled Texas and other states. The D.C. Circuit Court remanded those states' budgets to the EPA for prompt reconsideration. While we planned to participate in the EPA's reconsideration process to develop increased budgets that do not over-control Texas, the EPA instead responded to the remand by updating the budget for the 2008 ozone standard with a new rulemaking without explicitly addressing the issues of over-control of the 1997 standard. Comments on the EPA's proposal were submitted by Luminant in February 2016. While we cannot predict the outcome of future proceedings related to the CSAPR, including the EPA's reconsideration of the CSAPR emissions budgets for affected states, based upon our current operating plans we do not believe that the CSAPR will cause any material operational, financial or compliance issues.

State Implementation Plan (SIP)

In February 2013, in response to a petition for rulemaking filed by the Sierra Club, the EPA proposed a rule requiring certain states to replace SIP exemptions for excess emissions during malfunctions with an affirmative defense. Texas was not included in that original proposal since it already had an EPA-approved affirmative defense provision in its SIP. In 2014, as a result of a D.C. Circuit Court decision striking down an affirmative defense in another EPA rule, the EPA revised its 2013 proposal to extend the EPA's proposed findings of inadequacy to states that have affirmative defense provisions, including Texas. The EPA's revised proposal would require Texas to remove or replace its EPA-approved affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. In May 2015, the EPA finalized the proposal. In June 2015, we filed a petition for review in the Fifth Circuit Court challenging certain aspects of the EPA's final rule as they apply to the Texas SIP. The State of Texas and other parties have also filed similar petitions in the Fifth Circuit Court. In August 2015, the Fifth Circuit Court transferred the petitions that Luminant and other parties filed to the D.C. Circuit Court, and in October 2015 the petitions were consolidated with the pending petitions challenging the EPA's action in the D.C. Circuit Court. Briefing in the D.C. Circuit Court on the challenges is scheduled to be completed by October 2016. We cannot predict the timing or outcome of this proceeding.

In June 2014, the Sierra Club filed a petition in the D.C. Circuit Court seeking review of several EPA regulations containing affirmative defenses for malfunctions, including the MATS rule for power plants. In the petition, the Sierra Club contends this affirmative defense is no longer permissible in light of a D.C. Circuit Court decision regarding similar defenses applicable to the cement industry. Luminant filed a motion to intervene in this case. In July 2014, the D.C. Circuit Court ordered the case stayed pending the EPA's consideration of a petition for administrative reconsideration of the regulations at issue. In December 2014, the EPA signed a proposal to make technical corrections to the MATS rule. We filed comments on this proposal in April 2015. Except as set forth above, we cannot predict the timing or outcome of future proceedings related to this petition, the petition for administrative reconsideration that is pending before the EPA or the financial effects of these proceedings, if any.

Other Matters

We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.

Environmental Contingencies

See discussion above regarding the CSAPR that includes provisions which, among other things, place limits on SO₂ and NO_X emissions produced by electricity generation plants. We do not believe the CSAPR provisions and the MATS rule issued by the EPA in December 2011 will have any material impact on our business, results of operations, liquidity or financial condition.

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We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. We believe that we are in compliance with current environmental laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulations is not determinable and could materially affect our financial condition, results of operations and liquidity.

The costs to comply with environmental regulations could be significantly affected by the following external events or conditions:

• enactment of state or federal regulations regarding CO₂ and other greenhouse gas emissions;

• other changes to existing state or federal regulation regarding air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters, including revisions to clean air regulations developed by the EPA as a result of court rulings discussed above and MATS and Regional Haze, and

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

In February 2016, the EPA notified Texas of the EPA's preliminary intention to designate as nonattainment areas around our Big Brown, Monticello and Martin Lake plants based on modeling data submitted to the EPA by Sierra Club. We continue to believe that these models do not accurately predict actual SO₂ emissions measurements and that these designations should be determined by emissions data from air quality monitors. Should the EPA finalize these designations as intended in July 2016, Texas will begin the multi-year process to evaluate what potential emission controls or operational changes, if any, may be necessary to demonstrate attainment.

Labor Contracts

Certain personnel engaged in TCEH activities are represented by labor unions and covered by collective bargaining agreements. During 2015, all collective bargaining agreements covering bargaining unit personnel engaged in lignite mining operations, lignite/coal fueled generation operations, nuclear fueled generation operations and some of our natural gas powered generation operations were extended to March 2017. We do not expect any changes in collective bargaining agreements to have a material effect on our results of operations, liquidity or financial condition.

Nuclear Insurance

Nuclear insurance includes liability coverage, property damage, decontamination and premature decommissioning coverage and accidental outage and/or extra expense coverage. Nuclear insurance maintained meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. The company is self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Such losses could have a material effect on our financial condition and results of operations and liquidity.

With regard to liability coverage, the Act provides for financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $13.6 billion and requires nuclear generation plant operators to provide financial protection for this amount. The US Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $13.6 billion limit for a single incident mandated by the Act. As required, the company provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodily injury and property damage through a combination of private insurance and industry-wide retrospective payment plan known as the Secondary Financial Protection (SFP).

Under the SFP, in the event of an incident at any nuclear generation plant in the US, each operating licensed reactor in the US is subject to an assessment of up to $127.3 million and this amount is subject to increases for inflation every five years, with the next adjustment expected in September 2018. Assessments are currently limited to $19 million per operating licensed reactor per year per incident. The company's maximum potential assessment under the industry retrospective plan would be $254.6 million per incident but no more than $37.9 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $375 million per accident at any nuclear facility.

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With respect to nuclear decontamination and property damage insurance, the NRC requires that nuclear generation plant license-holders maintain at least $1.06 billion of such insurance and require the proceeds thereof to be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds can be used for plant repair or restoration or to provide for premature decommissioning. The company maintains nuclear decontamination and property damage insurance for Comanche Peak in the amount of $2.25 billion (subject to $5 million deductible per accident), above which the company is self-insured.

The company maintains Accidental Outage insurance to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at Comanche Peak are out of service for more than twelve weeks as a result of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-two weeks and $2.8 million for the next 110 weeks for each outage, respectively, after the initial twelve-week waiting period. The total maximum coverage is $490 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.

15. EQUITY

Equity Issuances and Repurchases

Changes in common stock shares outstanding for each of the last three years are reflected (in millions of shares) in the table below. Essentially all shares issued and purchased were as a result of stock-based compensation transactions for the benefit of certain officers, directors and employees.

	Year Ended December 31,
	2015	2014	2013
Shares outstanding at beginning of year	1,669.9	1,669.9	1,680.5
Shares issued (a)	—	—	1.7
Shares repurchased	—	—	(12.3	)
Shares outstanding at end of year	1,669.9	1,669.9	1,669.9

____________

(a) Includes share awards granted to directors and other nonemployees.

Dividend Restrictions

EFH Corp. has not declared or paid any dividends since the Merger. The agreement governing the TCEH DIP Facility generally restricts TCEH's ability to make distributions or loans to any of its parent companies or their subsidiaries unless such distributions or loans are expressly permitted under the agreement governing such facility. The agreement governing the EFIH DIP Facility generally restricts EFIH's ability to make distributions or loans to any of its parent companies or their subsidiaries unless such distributions or loans are expressly permitted under the agreement governing such facility.

Under applicable law, we are prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent. In addition, due to the Chapter 11 Cases, no dividends are eligible to be paid without the approval of the Bankruptcy Court.

Noncontrolling Interests

At December 31, 2015, ownership of Oncor's membership interests was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor's management and board of directors and 19.75% held by Texas Transmission. See Note 4 for discussion of the deconsolidation of Oncor effective January 1, 2010.

As discussed in Notes 4 and 9, we consolidated a joint venture formed in 2009 for the purpose of developing two new nuclear generation units, which resulted in a noncontrolling interests component of equity. Net loss attributable to noncontrolling interests of $107 million for the year ended December 31, 2013 reflected the noncontrolling interest share of the impairment of the assets of the nuclear generation development joint venture. Net loss attributable to the noncontrolling interests was immaterial for the years ended December 31, 2015 and 2014.

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Accumulated Other Comprehensive Income (Loss)

The following table presents the changes to accumulated other comprehensive income (loss) for the year ended December 31, 2015.

	Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 17)			Pension and Other Postretirement Employee Benefit Liabilities Adjustments (Note 18)			Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2014	$	(53	)	$	(77	)	$	(130	)
Other comprehensive loss before reclassifications (after tax)	—			5			5
Amounts reclassified from accumulated other comprehensive income (loss) and reported in:
Operating costs	—			(3		)	(3		)
Depreciation and amortization	2			—			2
Selling, general and administrative expenses	—			(4		)	(4		)
Income tax benefit (expense)	—			2			2
Equity in earnings of unconsolidated subsidiaries (net of tax)	1			1			2
Total amount reclassified from accumulated other comprehensive income (loss) during the period	3			(4		)	(1		)
Total change during the period	3			1			4
Balance at December 31, 2015	$	(50	)	$	(76	)	$	(126	)

The following table presents the changes to accumulated other comprehensive income (loss) for the year ended December 31, 2014. In conjunction with the remeasurement of the EFH Corp. OPEB liability during the period (see Note 18), we recognized an additional $17 million of other comprehensive loss.

	Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 17)			Pension and Other Postretirement Employee Benefit Liabilities Adjustments (Note 18)			Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2013	$	(56	)	$	(7	)	$	(63	)
Other comprehensive loss before reclassifications (after tax)	—			(66		)	(66		)
Amounts reclassified from accumulated other comprehensive income (loss) and reported in:
Operating costs	—			(4		)	(4		)
Depreciation and amortization	2			—			2
Selling, general and administrative expenses	—			(2		)	(2		)
Interest expense and related charges	—			—			—
Income tax benefit (expense)	(1		)	2			1
Equity in earnings of unconsolidated subsidiaries (net of tax)	2			—			2
Total amount reclassified from accumulated other comprehensive income (loss) during the period	3			(4		)	(1		)
Total change during the period	3			(70		)	(67		)
Balance at December 31, 2014	$	(53	)	$	(77	)	$	(130	)

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16. FAIR VALUE MEASUREMENTS

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

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

• Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange-traded commodity contracts. For example, some of our derivatives are NYMEX or ICE futures and swaps transacted through clearing brokers for which prices are actively quoted.

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

• Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives with values derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means. See further discussion below.

Our valuation policies and procedures are developed, maintained and validated by a centralized risk management group that reports to the Chief Financial Officer, who also functions as the Chief Risk Officer. Risk management functions include commodity price reporting and validation, valuation model validation, risk analytics, risk control, credit risk management and risk reporting.

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.

In utilizing broker quotes, we attempt to obtain multiple quotes from brokers (generally non-binding) that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other factors. In addition, for valuation of interest rate swaps, we used generally accepted interest rate swap valuation models utilizing month-end interest rate curves.

Probable loss from default by either us or our counterparties is considered in determining the fair value of derivative assets and liabilities. These non-performance risk adjustments take into consideration credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 17 for additional information regarding credit risk associated with our derivatives). We utilize published credit ratings, default rate factors and debt trading values in calculating these fair value measurement adjustments.

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Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including, but not limited to, commodity prices, volatility factors, discount rates and other market based factors. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing locations and credit/non-performance risk assumptions. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.

The significant unobservable inputs and valuation models are developed by employees trained and experienced in market operations and fair value measurements and validated by the company's risk management group, which also further analyzes any significant changes in Level 3 measurements. Significant changes in the unobservable inputs could result in significant upward or downward changes in the fair value measurement.

With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

Assets and liabilities measured at fair value on a recurring basis consisted of the following:

December 31, 2015
	Level 1		Level 2		Level 3 (a)		Total
Assets:
Commodity contracts	$	385	$	41	$	49	$	475
Nuclear decommissioning trust – equity securities (b)	380		219		—		599
Nuclear decommissioning trust – debt securities (b)	—		319		—		319
Total assets	$	765	$	579	$	49	$	1,393
Liabilities:
Commodity contracts	$	128	$	64	$	12	$	204
Total liabilities	$	128	$	64	$	12	$	204

December 31, 2014
	Level 1		Level 2		Level 3 (a)		Total
Assets:
Commodity contracts	$	402	$	46	$	49	$	497
Nuclear decommissioning trust – equity securities (b)	375		217		—		592
Nuclear decommissioning trust – debt securities (b)	—		301		—		301
Total assets	$	777	$	564	$	49	$	1,390
Liabilities:
Commodity contracts	$	278	$	25	$	14	$	317
Total liabilities	$	278	$	25	$	14	$	317

____________

(a) See table below for description of Level 3 assets and liabilities.

(b) The nuclear decommissioning trust investment is included in the other investments line in the consolidated balance sheets. See Note 21.

Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium and coal agreements and include financial instruments entered into for hedging purposes as well as physical contracts that have not been designated normal purchases or sales. See Note 17 for further discussion regarding derivative instruments, including the termination of certain natural gas hedging agreements shortly after the Bankruptcy Filing.

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Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facility. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at December 31, 2015 and 2014:

December 31, 2015
	Fair Value
Contract Type (a)	Assets		Liabilities			Total		Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	1	$	(1	)	$	—	Valuation Model	Illiquid pricing locations (c)	$15 to $35/MWh
									Hourly price curve shape (d)	$15 to $45/MWh
Electricity congestion revenue rights	39		(4		)	35		Market Approach (e)	Illiquid price differences between settlement points (f)	$0 to $10/MWh
Other (i)	9		(7		)	2
Total	$	49	$	(12	)	$	37

December 31, 2014
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	4	$	(5	)	$	(1	)	Valuation Model	Illiquid pricing locations (c)	$30 to $50/MWh
										Hourly price curve shape (d)	$20 to $70/MWh
Electricity congestion revenue rights	38		(4		)	34			Market Approach (e)	Illiquid price differences between settlement points (f)	$0 to $20/MWh
Coal purchases	—		(4		)	(4		)	Market Approach (e)	Illiquid price variances between mines (g)	$0 to $1/ton
										Illiquid price variances between heat content (h)	$0 to $1/ton
Other (i)	7		(1		)	6
Total	$	49	$	(14	)	$	35

____________

(a) Electricity purchase and sales contracts include hedging positions in the ERCOT regions, as well as power contracts, the valuations of which include unobservable inputs related to the hourly shaping of the price curve. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. Coal purchase contracts relate to western (Powder River Basin) coal.

(b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.

(c) Based on the historical range of forward average monthly ERCOT hub and load zone prices.

(d) Based on the historical range of forward average hourly ERCOT North Hub prices.

(e) While we use the market approach, there is either insufficient market data to consider the valuation liquid or the significance of credit reserves or non-performance risk adjustments results in a Level 3 designation.

(f) Based on the historical price differences between settlement points within the ERCOT hubs and load zones.

(g) Based on the historical range of price variances between mine locations.

(h) Based on historical ranges of forward average prices between different heat contents (potential energy in coal for a given mass).

(i) Other includes contracts for ancillary services, natural gas, power options, diesel options and coal options.

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There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December 31, 2015, 2014 and 2013. See the table of changes in fair values of Level 3 assets and liabilities below for discussion of transfers between Level 2 and Level 3 for the years ended December 31, 2015, 2014 and 2013.

The following table presents the changes in fair value of the Level 3 assets and liabilities for the years ended December 31, 2015, 2014 and 2013.

	Year Ended December 31,
	2015			2014			2013
Net asset (liability) balance at beginning of period	$	35		$	(973	)	$	29
Total unrealized valuation gains (losses)	27			(97		)	(48		)
Purchases, issuances and settlements (a):
Purchases	49			63			92
Issuances	(13		)	(5		)	(7		)
Settlements	(48		)	1,053			138
Transfers into Level 3 (b)	1			—			(1,181		)
Transfers out of Level 3 (b)	(14		)	(6		)	4
Net change (c)	2			1,008			(1,002		)
Net asset (liability) balance at end of period	$	37		$	35		$	(973	)
Unrealized valuation gains (losses) relating to instruments held at end of period	$	18		$	(5	)	$	435

____________

(a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received. Settlement amounts in 2014 reflect termination of the TCEH interest rate swaps and include the reversal of a nonperformance risk adjustment as discussed in Note 17.

(b) Includes transfers due to changes in the observability of significant inputs. Transfers in and out occur at the end of each quarter, which is when the assessments are performed. All Level 3 transfers during the years presented are in and out of Level 2. Transfers into Level 3 during 2013 reflect a nonperformance risk adjustment in the valuation of the TCEH interest rate swaps, which were secured by a first-lien interest in the same assets of TCEH (on a pari passu basis) with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes (see Note 13).

(c) Substantially all changes in values of commodity contracts are reported in the statements of consolidated income (loss) in net gain (loss) from commodity hedging and trading activities. Changes in values of interest rate swaps transferred into Level 3 in 2013 are reported in the statements of consolidated income (loss) in interest expense and related charges (see Note 10). Activity excludes changes in fair value in the month the positions settled as well as amounts related to positions entered into and settled in the same quarter.

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17. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price risk. Because certain of these instruments are deemed to be forward contracts under the Bankruptcy Code, they are not subject to the automatic stay, and counterparties may elect to terminate the agreements. Prior to the Petition Date, we had entered into interest rate swaps to manage our interest rate risk exposure. See Note 16 for a discussion of the fair value of derivatives.

Commodity Hedging and Trading Activity — TCEH has natural gas hedging positions designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity has generally moved with the price of natural gas. TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas through 2016 in order to hedge a portion of electricity price exposure related to expected lignite/coal and nuclear fueled generation. TCEH also enters into derivatives, including electricity, natural gas, fuel oil, uranium, emission and coal instruments, generally for short-term hedging purposes. Consistent with existing Bankruptcy Court orders, to a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets. Unrealized gains and losses arising from changes in the fair value of hedging and trading instruments as well as realized gains and losses upon settlement of the instruments are reported in the statements of consolidated income (loss) in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements have been used to reduce exposure to interest rate changes by converting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swaps were used to effectively reduce the hedged borrowing costs. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps were reported in the statements of consolidated income (loss) in interest expense and related charges. As of December 31, 2015 and 2014, we had no active interest rate swap derivatives.

Termination of Commodity Hedges and Interest Rate Swaps — Commodity hedges and interest rate swaps entered into prior to the Petition Date are deemed to be forward contracts under the Bankruptcy Code. The Bankruptcy Filing constituted an event of default under these arrangements, and in accordance with the contractual terms, counterparties terminated certain positions shortly after the Bankruptcy Filing. The positions terminated consisted almost entirely of natural gas hedging positions and interest rate swaps that were secured by a first-lien interest in the same assets of TCEH on a pari passu basis with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes.

Entities with a first-lien security interest included counterparties to both our natural gas hedging positions and interest rate swaps, which had entered into master agreements that provided for netting and setoff of amounts related to these positions. Additionally, certain counterparties to only our interest rate swaps hold the same first-lien security interest. The net liability recorded for the terminations totaled $1.116 billion, which represented a realized loss of $1.233 billion related to the interest rate swaps, net of a realized gain of $117 million related to the natural gas hedging positions. Additionally, net accounts payable amounts related to matured interest rate swaps of $127 million are also secured by the same first-lien secured interest. The total net liability of $1.243 billion is subject to the terms of settlement of TCEH's first-lien claims ultimately approved by the Bankruptcy Court and is reported in the consolidated balance sheets as a liability subject to compromise. Additionally, counterparties associated with the net liability are allowed, and have been receiving, adequate protection payments related to their claims as permitted by TCEH's cash collateral order approved by the Bankruptcy Court (see Note 10).

The derivative liability related to the TCEH interest rate swaps had included a nonperformance risk adjustment (resulting in a Level 3 valuation). This fair value adjustment reflected the counterparties' exposure to our credit risk. The amount of the adjustment was after consideration of derivative assets related to natural gas hedging positions with the same counterparties. The difference between the net liability arising upon the termination of the interest rate swaps and the natural gas hedging positions and the net derivative assets and liabilities recorded totaled $278 million, substantially all of which represented the nonperformance risk adjustment, and is reported as a noncash charge in reorganization items in the statements of consolidated income (loss) in accordance with ASC 852(see Note 11).

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Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of commodity and other derivative contractual assets and liabilities (with the column totals representing the net positions of the contracts) as reported in the consolidated balance sheets at December 31, 2015 and 2014 (noncurrent assets and liabilities are reported in other noncurrent assets and other noncurrent liabilities and deferred credits, respectively). All amounts relate to commodity contracts.

	December 31, 2015								December 31, 2014
	Derivative Assets		Derivative Liabilities			Total			Derivative Assets		Derivative Liabilities			Total
Current assets	$	465	$	—		$	465		$	492	$	—		$	492
Noncurrent assets	10		—			10			5		—			5
Current liabilities	—		(203		)	(203		)	—		(316		)	(316		)
Noncurrent liabilities	—		(1		)	(1		)	—		(1		)	(1		)
Net assets (liabilities)	$	475	$	(204	)	$	271		$	497	$	(317	)	$	180

At December 31, 2015 and 2014, there were no derivative positions accounted for as cash flow or fair value hedges.

The following table presents the pretax effect of derivatives on net income (gains (losses)), including realized and unrealized effects:

	Year Ended December 31,
Derivative (statements of consolidated income (loss) presentation)	2015		2014			2013
Commodity contracts (Net gain (loss) from commodity hedging and trading activities) (a)	$	380	$	17		$	(54	)
Interest rate swaps (Interest expense and related charges) (b)	—		(128		)	433
Interest rate swaps (Reorganization items) (Note 11)	—		(278		)	—
Net gain (loss)	$	380	$	(389	)	$	379

____________

(a) Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.

(b) Includes unrealized mark-to-market net gain (loss) as well as the net realized effect on interest paid/accrued, both reported in Interest Expense and Related Charges (see Note 10).

The pretax effect (all losses) on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges was immaterial in the years ended December 31, 2015, 2014 and 2013. There were no amounts recognized in OCI for the years ended December 31, 2015, 2014 or 2013.

There were no transactions designated as cash flow hedges during the years ended December 31, 2015, 2014 or 2013.

Accumulated other comprehensive income related to cash flow hedges (excluding Oncor's interest rate hedges) at December 31, 2015 and 2014 totaled $34 million and $36 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps previously accounted for as cash flow hedges. We expect that $2 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income at December 31, 2015 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

Balance Sheet Presentation of Derivatives

Consistent with elections under US GAAP to present amounts on a gross basis, we report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. We may enter into offsetting positions with the same counterparty, resulting in both assets and liabilities. Volatility in underlying commodity prices can result in significant changes in assets and liabilities presented from period to period.

Margin deposits that contractually offset these derivative instruments are reported separately in the consolidated balance sheets. Margin deposits received from counterparties are either used for working capital or other corporate purposes or are deposited in a separate restricted cash account. At December 31, 2015 and 2014, essentially all margin deposits held were unrestricted.

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We maintain standardized master netting agreements with certain counterparties that allow for the netting of positive and negative exposures. Generally, we utilize the International Swaps and Derivatives Association (ISDA) standardized contract for financial transactions, the Edison Electric Institute standardized contract for physical power transactions and the North American Energy Standards Board (NAESB) standardized contract for physical natural gas transactions. These contain credit enhancements that allow for the right to offset assets and liabilities and collateral received in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.

The following tables reconcile our derivative assets and liabilities as presented in the consolidated balance sheets to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:

December 31, 2015
	Amounts Presented in Balance Sheet			Offsetting Instruments (a)			Financial Collateral (Received) Pledged (b)			Net Amounts
Derivative assets:
Commodity contracts	$	475		$	(145	)	$	(147	)	$	183
Derivative liabilities:
Commodity contracts	(204		)	145			6			(53		)
Net amounts	$	271		$	—		$	(141	)	$	130

December 31, 2014
	Amounts Presented in Balance Sheet			Offsetting Instruments (a)			Financial Collateral (Received) Pledged (b)			Net Amounts
Derivative assets:
Commodity contracts	$	497		$	(298	)	$	(16	)	$	183
Derivative liabilities:
Commodity contracts	(317		)	298			2			(17		)
Net amounts	$	180		$	—		$	(14	)	$	166

____________

(a) Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.

(b) Financial collateral consists entirely of cash margin deposits.

Derivative Volumes — The following table presents the gross notional amounts of derivative volumes at December 31, 2015 and 2014:

	December 31,
	2015	2014
Derivative type	Notional Volume		Unit of Measure
Natural gas (a)	1,489	1,687	Million MMBtu
Electricity	58,022	22,820	GWh
Congestion Revenue Rights (b)	106,260	89,484	GWh
Coal	10	10	Million US tons
Fuel oil	35	36	Million gallons
Uranium	75	150	Thousand pounds

____________

(a) Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions.

(b) Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT.

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Credit Risk-Related Contingent Features of Derivatives

The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies; however, due to the Chapter 11 Cases, substantially all of such collateral posting requirements have already been effective.

At December 31, 2015 and 2014, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully collateralized totaled $58 million and $17 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with counterparties totaling $31 million and $5 million at December 31, 2015 and 2014, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross-default provisions, the remaining liquidity requirements would be immaterial at both December 31, 2015 and 2014.

In addition, certain derivative agreements include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. At December 31, 2015 and 2014, the fair value of derivative liabilities subject to such cross-default provisions were immaterial.

As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $59 million and $18 million at December 31, 2015 and 2014, respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets subject to related liens.

Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.

Concentrations of Credit Risk Related to Derivatives

We have concentrations of credit risk with the counterparties to our derivative contracts. At December 31, 2015, total credit risk exposure to all counterparties related to derivative contracts totaled $527 million (including associated accounts receivable). The net exposure to those counterparties totaled $199 million at December 31, 2015 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $110 million. At December 31, 2015, the credit risk exposure to the banking and financial sector represented 78% of the total credit risk exposure and 56% of the net exposure.

Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.

We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.

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

EFH Corp. is the plan sponsor of the EFH Retirement Plan (the Retirement Plan), which had provided benefits to eligible employees of its subsidiaries, including Oncor. After amendments in 2012, employees in the Retirement Plan now consist entirely of active and retired collective bargaining unit employees in our competitive business. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is our policy to fund the Retirement Plan assets only to the extent deductible under existing federal tax regulations.

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

EFH Corp. offers other postretirement employee benefits (OPEB) in the form of health care and life insurance to eligible employees of its subsidiaries and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service. In 2011, we changed the OPEB plan whereby, effective January 1, 2013, Medicare-eligible retirees from the competitive business are subject to a cap on increases in subsidies received under the plan to offset medical costs.

In accordance with an agreement between Oncor and EFH Corp., Oncor ceased participation in EFH Corp.'s OPEB Plan effective July 2014 and established its own OPEB plan for Oncor's eligible existing and future retirees and their dependents, as well as split service participants as discussed immediately below under Regulatory Recovery of Pension and OPEB Costs and in Note 19. The separation resulted in the transfer of a significant portion of the liability associated with our plan to the new Oncor plan, which resulted in a reduction of our OPEB liability of approximately $758 million and a corresponding reduction of an equal amount in the receivable from unconsolidated subsidiary.

Regulatory Recovery of Pension and OPEB Costs

PURA provides for the recovery by Oncor, in its regulated revenue rates, of pension and OPEB costs applicable to services of Oncor's active and retired employees, as well as services of other EFH Corp. active and retired employees prior to the deregulation and disaggregation of our electric utility business effective January 1, 2002. Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs reflected in Oncor's approved (by the PUCT) revenue rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings, including amounts related to pre-2002 service of EFH Corp. employees. Regulatory assets and liabilities are ultimately subject to PUCT approval. Oncor is contractually obligated to EFH Corp. to fund pension obligations for which the costs are recoverable in its rates.

At December 31, 2015 and 2014, Oncor had recorded regulatory assets totaling $1.182 billion and $1.166 billion, respectively, related to both EFH Corp. and Oncor pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.

Pension and OPEB Costs

	Year Ended December 31,
	2015			2014			2013
Pension costs	$	18		$	13		$	26
OPEB costs	3			27			39
Total benefit costs	21			40			65
Less amounts expensed by Oncor (and not consolidated)	(2		)	(13		)	(25		)
Less amounts deferred principally as a regulatory asset or property by Oncor	(8		)	(15		)	(25		)
Net amounts recognized as expense by EFH Corp. and consolidated subsidiaries	$	11		$	12		$	15

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Market-Related Value of Assets Held in Postretirement Benefit Trusts

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

Detailed Information Regarding Pension Benefits

The following information is based on December 31, 2015, 2014 and 2013 measurement dates:

	Year Ended December 31,
	2015			2014			2013
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate	4.19		%	5.07		%	4.30		%
Expected return on plan assets	5.38		%	6.17		%	5.40		%
Rate of compensation increase	3.50		%	3.50		%	3.50		%
Components of Net Pension Cost:
Service cost	$	7		$	7		$	8
Interest cost	14			14			12
Expected return on assets	(12		)	(12		)	(7		)
Amortization of net actuarial loss	9			4			8
Effect of pension plan actions	—			—			5
Net periodic pension cost	$	18		$	13		$	26
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net loss	$	1		$	15		$	5
Amortization of net loss	(1		)	—			—
Effect of pension plan actions	—			—			(4		)
Total loss (income) recognized in other comprehensive income	$	—		$	15		$	1
Total recognized in net periodic benefit cost and other comprehensive income	$	18		$	28		$	27
Assumptions Used to Determine Benefit Obligations:
Discount rate	5.64		%	4.19		%	5.07		%
Rate of compensation increase	3.50		%	3.50		%	3.50		%

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	Year Ended December 31,
	2015			2014
Change in Pension Obligation:
Projected benefit obligation at beginning of year	$	331		$	272
Service cost	7			7
Interest cost	14			14
Actuarial (gain) loss	(19		)	45
Benefits paid	(11		)	(7		)
Projected benefit obligation at end of year	$	322		$	331
Accumulated benefit obligation at end of year	$	303		$	307
Change in Plan Assets:
Fair value of assets at beginning of year	$	230		$	126
Actual return on assets	(8		)	26
Employer contributions	68			85
Benefits paid	(11		)	(7		)
Fair value of assets at end of year	$	279		$	230
Funded Status:
Projected pension benefit obligation	$	(322	)	$	(331	)
Fair value of assets	279			230
Funded status at end of year (a)	$	(43	)	$	(101	)
Amounts Recognized in the Balance Sheet Consist of:
Other current liabilities	(1		)	(1		)
Liabilities subject to compromise	(20		)	(23		)
Other noncurrent liabilities	(22		)	(77		)
Net liability recognized	$	(43	)	$	(101	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net loss	$	17		$	17
Amounts Recognized by Oncor as Regulatory Assets Consist of:
Net loss	$	49		$	56
Net amount recognized	$	49		$	56

___________

(a) Amounts in 2015 and 2014 include zero and $47 million, respectively, for which Oncor is contractually responsible and which are expected to be recovered in Oncor's rates. See Note 19.

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

	December 31,
	2015		2014
Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations	$	322	$	331
Accumulated benefit obligation	$	303	$	307
Plan assets	$	279	$	230

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Pension Plan Investment Strategy and Asset Allocations

Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, US Treasuries and agency securities and money market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets.

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

Asset Category:	Target Allocation Ranges
Fixed income	74	%	-	86%
US equities	8	%	-	14%
International equities	6	%	-	12%

Expected Long-Term Rate of Return on Assets Assumption

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

Retirement Plan
Asset Class:	Expected Long-Term Rate of Return
US equity securities	6.6	%
International equity securities	7.5	%
Fixed income securities	4.5	%
Weighted average	5.6	%

Fair Value Measurement of Pension Plan Assets

At December 31, 2015 and 2014, pension plan assets measured at fair value on a recurring basis consisted of the following:

	December 31, (a)
Asset Category:	2015		2014
Interest-bearing cash	$	64	$	21
Equity securities:
US	26		25
International	20		20
Fixed income securities:
Corporate bonds (b)	116		127
US Treasuries	40		19
Other (c)	13		18
Total assets	$	279	$	230

___________

(a) All amounts are based on Level 2 valuations. See Note 16.

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

(c) Other consists primarily of municipal bonds.

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Detailed Information Regarding Postretirement Benefits Other Than Pensions

The following OPEB information is based on December 31, 2015, 2014 and 2013 measurement dates (includes amounts related to Oncor):

	Year Ended December 31,
	2015			2014			2013
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate (EFH Corp. Plan)	3.81		%	4.98		%	4.10		%
Discount rate (Oncor Plan)	4.23		%	4.98		%	N/A
Expected return on plan assets (a)	N/A			7.05		%	6.70		%
Components of Net Postretirement Benefit Cost:
Service cost	$	4		$	8		$	11
Interest cost	6			28			41
Expected return on assets	—			(6		)	(12		)
Amortization of prior service cost/(credit)	(11		)	(21		)	(31		)
Amortization of net actuarial loss	4			18			30
Net periodic OPEB cost	$	3		$	27		$	39
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net (gain) loss	$	(18	)	$	12		$	4
Amortization of net gain	(5		)	(5		)	(3		)
Amortization of prior service credit	11			11			11
Total loss recognized in other comprehensive income	$	(12	)	$	18		$	12
Total recognized in net periodic benefit cost and other comprehensive income	$	(9	)	$	45		$	51
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate (EFH Corp. Plan)	4.13		%	3.81		%	4.98		%
Discount rate (Oncor Plan)	4.60		%	4.23		%	N/A

___________

(a) At December 31, 2015 and 2014, the EFH OPEB plan had no plan assets as the existing assets were transferred to the Oncor OPEB plan as part of the separation discussed above.

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	Year Ended December 31,
	2015			2014
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year	$	139		$	1,049
Service cost	4			8
Interest cost	6			28
Participant contributions	3			10
Actuarial (gain) loss	(19		)	84
Benefits paid	(11		)	(40		)
Transfers to new plan sponsored by Oncor	—			(1,000		)
Benefit obligation at end of year	$	122		$	139
Change in Plan Assets:
Fair value of assets at beginning of year	$	—		$	179
Actual return on assets	—			11
Employer contributions	8			16
Participant contributions	3			10
Benefits paid	(11		)	(40		)
Transfers to new plan sponsored by Oncor	—			(176		)
Fair value of assets at end of year	$	—		$	—
Funded Status:
Benefit obligation	$	(122	)	$	(139	)
Funded status at end of year	$	(122	)	$	(139	)
Amounts Recognized on the Balance Sheet Consist of:
Other current liabilities	$	(8	)	$	(8	)
Other noncurrent liabilities	(114		)	(131		)
Net liability recognized	$	(122	)	$	(139	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Prior service credit	$	(31	)	$	(43	)
Net loss	18			41
Net amount recognized	$	(13	)	$	(2	)

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

	December 31,
	2015		2014
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year	6.00	%	8.00	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2024		2022
Assumed Health Care Cost Trend Rates-Medicare Eligible:
Health care cost trend rate assumed for next year	5.80	%	6.50	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2024		2022

	1-Percentage Point Increase			1-Percentage Point Decrease
Sensitivity Analysis of Assumed Health Care Cost Trend Rates:
Effect on accumulated postretirement obligation	$	(5	)	$	4
Effect on postretirement benefits cost	$	—		$	—

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Fair Value Measurement of OPEB Plan Assets

At December 31, 2015 and 2014, the EFH OPEB plan had no plan assets as the existing assets were transferred to the Oncor OPEB plan as part of the separation discussed above.

Significant Concentrations of Risk

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

Assumed Discount Rate

We selected the assumed discount rate using the Aon Hewitt AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2015 consisted of 434 corporate bonds with an average rating of AA using Moody's, Standard & Poor's Rating Services and Fitch Ratings, Ltd. ratings.

Amortization in 2016

We estimate amortization of the net actuarial loss and prior service cost for the defined benefit pension plan from accumulated other comprehensive income into net periodic benefit cost will be immaterial. We estimate amortization of the net actuarial loss and prior service credit for the OPEB plan from accumulated other comprehensive income into net periodic benefit cost will total $1 million and an $11 million credit, respectively.

Contributions in 2015 and 2016

In December 2015, a cash contribution totaling $67 million was made to the Retirement Plan assets, of which $51 million was contributed by Oncor and $16 million was contributed by TCEH, which resulted in the Retirement Plan being fully funded as calculated under the provisions of ERISA. As a result of the Bankruptcy Filing, participants in the Retirement Plan who choose to retire would not be eligible for the lump sum payout option under the Retirement Plan unless the Retirement Plan is fully funded. Pension plan funding in 2016 is expected to total $3 million. OPEB plan funding in 2015 totaled $8 million, and funding in 2016 is expected to total $8 million.

Future Benefit Payments

Estimated future benefit payments to beneficiaries, including amounts related to nonqualified plans, are as follows:

	2016		2017		2018		2019		2020		2021-25
Pension benefits	$	14	$	14	$	15	$	17	$	19	$	109
OPEB	$	8	$	8	$	8	$	8	$	9	$	44

Thrift Plan

Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 20% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% (75% for employees covered under the Traditional Retirement Plan Formula) of the first 6% of employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options. Our contributions to the Thrift Plan totaled $24 million, $24 million and $23 million for the years ended December 31, 2015, 2014 and 2013, respectively. In accordance with an agreement in 2014 between Oncor and EFH Corp., Oncor ceased participation in EFH Corp.'s Thrift Plan effective January 1, 2015 and established its own plan.

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19. RELATED PARTY TRANSACTIONS

The following represent our significant related-party transactions.

• On a quarterly basis, we accrue a management fee payable to the Sponsor Group under the terms of a management agreement. Related amounts expensed and reported as SG&A expense totaled $37 million, $40 million and $39 million for the years ended December 31, 2015, 2014 and 2013, respectively. No payments were made in the years ended December 31, 2015 and 2014, and amounts paid totaled $29 million in the year ended December 31, 2013. We had previously paid these fees on a quarterly basis, however, beginning with the quarterly management fee due December 31, 2013, the Sponsor Group, while reserving the right to receive the fees, directed EFH Corp. to suspend payments of the management fees for an indefinite period. Effective with the Petition Date, EFH Corp. suspended allocations of such fees to TCEH and EFIH. Fees accrued as of the Petition Date were reclassified to liabilities subject to compromise (LSTC), and fees accrued after the Petition Date were reported in other noncurrent liabilities and deferred credits. Pursuant to the Settlement Agreement approved by the Bankruptcy Court in December 2015, the management agreement has been terminated and the Sponsor Group has agreed to forego any and all claims under the management agreement in exchange for releases of alleged liabilities against the Debtors. As a result, we adjusted the expected allowed claim and recognized a gain for the Sponsor Group's management agreement claim of $86 million, which is reported in our statement of consolidated income (loss) in reorganization items.

• In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of each member of the Sponsor Group have from time to time engaged in commercial banking transactions with us and/or provided financial advisory services to us, in each case in the normal course of business.

• In January 2013, fees paid to Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners, for services related to debt exchanges totaled $2 million, described as follows: (i) Goldman acted as a dealer manager for the offers by EFIH and EFIH Finance to exchange new EFIH 10% Notes for EFH Corp. 9.75% Notes, EFH Corp. 10% Notes and EFIH 9.75% Notes (collectively, the Old Notes) and as a solicitation agent in the solicitation of consents by EFH Corp. and EFIH and EFIH Finance to amendments to the Old Notes and indentures governing the Old Notes and (ii) Goldman acted as a dealer manager for the offers by EFIH and EFIH Finance to exchange EFIH Toggle Notes for EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes.

Affiliates of GS Capital Partners were parties to certain commodity and interest rate hedging transactions with us in the normal course of business.

• Affiliates of the Sponsor Group have sold or acquired, and in the future may sell or acquire, debt or debt securities issued by us in open market transactions or through loan syndications.

• TCEH made loans to EFH Corp. in the form of demand notes (TCEH Demand Notes) that were pledged as collateral under the TCEH Senior Secured Facilities for (i) debt principal and interest payments and (ii) other general corporate purposes for EFH Corp. EFH Corp. settled the balance of the TCEH Demand Notes in January 2013 using $680 million of the proceeds from debt issued by EFIH in 2012.

• EFH Corp. and EFIH have purchased, or received in exchanges, certain debt securities of EFH Corp. and TCEH, which they have held. Principal and interest payments received by EFH Corp. and EFIH on these investments have been used, in part, to service their outstanding debt. In conjunction with the Settlement Agreement approved by the Bankruptcy Court in December 2015, EFH Corp. and EFIH waived their rights to the claims associated with the these debt securities, and we adjusted the expected allowed claim associated with such investments to zero. These investments, and the effects of the settlement, are eliminated in consolidation in these consolidated financial statements. Prior to the Settlement Agreement, EFIH held $1.282 billion principal amount of EFH Corp. debt and $79 million principal amount of TCEH debt, and EFH Corp. held $303 million principal amount of TCEH debt. In the first quarter 2013, EFIH distributed to EFH Corp. $6.360 billion principal amount of EFH Corp. debt previously received by EFIH in debt exchanges; EFH Corp. cancelled the debt instruments.

139

• TCEH's retail operations pay Oncor for services it provides, principally the delivery of electricity. Expenses recorded for these services, reported in fuel, purchased power costs and delivery fees, totaled approximately $1.0 billion for each of the years ended December 31, 2015, 2014 and 2013. The fees are based on rates regulated by the PUCT that apply to all REPs. The consolidated balance sheets at both December 31, 2015 and 2014 reflect amounts due currently to Oncor totaling $118 million (included in net payables due to unconsolidated subsidiary), largely related to these electricity delivery fees. Also see discussion below regarding receivables from Oncor under a Federal and State Income Tax Allocation Agreement.

• A subsidiary of EFH Corp. bills Oncor for financial and other administrative services and shared facilities at cost. Such amounts reduced reported SG&A expense by $19 million, $34 million and $32 million for the years ended December 31, 2015, 2014 and 2013, respectively.

• A subsidiary of EFH Corp. bills TCEH subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges totaled $205 million, $204 million and $241 million for the years ended December 31, 2015, 2014 and 2013, respectively.

• See Note 13 for discussion of a letter of credit issued by TCEH in 2014 to a subsidiary of EFH Corp. to secure its amounts payable to the subsidiary arising from recurring transactions in the normal course.

• During 2015, TCEH purchased $16 million in information technology assets from a subsidiary of EFH Corp. and cash settled $14 million of these assets in 2015 and $2 million in early 2016. In 2014, a subsidiary of EFH Corp. sold information technology assets to TCEH totaling $52 million. TCEH cash settled $45 million of these transactions and a subsidiary of EFH Corp. cash settled $7 million of this obligation by drawing on the letter of credit issued by TCEH. The assets are substantially for the use of TCEH and its subsidiaries.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility is funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to TCEH for contribution to the trust fund with the intent that the trust fund assets, reported in other investments in our consolidated balance sheets, will ultimately be sufficient to fund the future decommissioning liability, reported in noncurrent liabilities in our consolidated balance sheets. The delivery fee surcharges remitted to TCEH totaled $17 million for both the years ended December 31, 2015 and 2014 and $16 million for the year ended December 31, 2013. Income and expenses associated with the trust fund and the decommissioning liability incurred by TCEH are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates. At December 31, 2015 and 2014, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $409 million and $479 million, respectively, and is reported in noncurrent liabilities. In November 2015, the PUCT approved Luminant's updated nuclear decommissioning cost study and funding analysis.

140

• We file a consolidated federal income tax return that includes Oncor Holdings' results. Oncor is not a member of our consolidated tax group, but our consolidated federal income tax return includes our portion of Oncor's results due to our equity ownership in Oncor. We also file a consolidated Texas state margin tax return that includes all of Oncor Holdings' and Oncor's results. However, under a Federal and State Income Tax Allocation Agreement, Oncor Holdings' and Oncor's federal income tax and Texas margin tax expense and related balance sheet amounts, including our income taxes receivable from or payable to Oncor Holdings and Oncor, are recorded as if Oncor Holdings and Oncor file their own corporate income tax returns.

• At December 31, 2015, our net current amount payable to Oncor Holdings related to federal and state income taxes (reported in net payables due to unconsolidated subsidiary) totaled $87 million, $89 million of which related to Oncor. The $89 million net payable to Oncor included a $109 million federal income tax payable offset by a $20 million state margin tax receivable. Additionally, at December 31, 2015, we had a noncurrent tax payable to Oncor of $65 million recorded in other noncurrent liabilities and deferred credits and a noncurrent tax receivable from Oncor Holdings of $2 million recorded in other noncurrent assets. At December 31, 2014, our net current amount payable to Oncor Holdings related to federal and state income taxes totaled $120 million, all of which related to Oncor. The $120 million net payable to Oncor included a $144 million federal income tax payable offset by a $24 million state margin tax receivable. Additionally, at December 31, 2014 we had a noncurrent tax payable to Oncor of $64 million recorded in other noncurrent liabilities and deferred credits.

• For the year ended December 31, 2015, EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $26 million and $132 million, respectively. For the year ended December 31, 2014, EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $24 million and $237 million, respectively. For the year ended December 31, 2013, EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $34 million and $90 million, respectively. The 2013 net payment included $33 million from Oncor related to the 1997 through 2002 IRS appeals settlement and a $10 million refund paid to Oncor related to the filing of amended Texas franchise tax returns for 1997 through 2001.

• Pursuant to the Federal and State Income Tax Allocation Agreement between EFH Corp. and TCEH, in September 2013, TCEH made a federal income tax payment of $84 million to EFH Corp related to the 1997 through 2002 IRS appeals settlement. The Plan of Reorganization provides that the Debtors will reject this agreement at the effective time of the Plan of Reorganization. Under the Settlement Agreement, no further cash payments will be made in respect of federal income tax. See Note 7.

• Certain transmission and distribution utilities in Texas have requirements in place to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, as a result of TCEH's credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, at December 31, 2015 and 2014, TCEH had posted letters of credit and/or cash in the amount of $6 million and $9 million, respectively, for the benefit of Oncor.

• In December 2012, Oncor became the sponsor of a new pension plan (the Oncor Plan), the participants in which consist of all of Oncor's active employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Oncor had previously contractually agreed to assume responsibility for pension liabilities that are recoverable by Oncor under regulatory rate-setting provisions. As part of the pension plan actions, EFH Corp. fully funded the non-recoverable pension liabilities under the Oncor Plan. After the pension plan actions, participants remaining in the EFH Corp. pension plan consist of active employees under collective bargaining agreements (union employees). Oncor continues to be responsible for the recoverable portion of pension obligations to these union employees. Under ERISA, EFH Corp. and Oncor remain jointly and severally liable for the funding of the EFH Corp. and Oncor pension plans. We view the risk of the retained liability under ERISA related to the Oncor Plan to be not significant.

141

• In accordance with an agreement between EFH Corp. and Oncor, Oncor ceased participation in EFH Corp.'s OPEB plan effective July 1, 2014 and established its own OPEB plan for Oncor's eligible existing and future retirees and their dependents. Additionally, the Oncor plan participants include those former participants in the EFH Corp. OPEB plan whose employment included service with both Oncor (or a predecessor regulated electricity business) and our competitive businesses (split service participants). Under the agreement, we will retain the liability for split service participants' benefits related to their years of service with the competitive business. The methodology for OPEB cost allocations between EFH Corp. and Oncor has not changed, and the plan separation does not materially affect the net assets or cash flows of EFH Corp. As discussed in Note 18 and reflected in the amounts presented immediately below, our consolidated balance sheet at December 31, 2014 reflects a reduction in other noncurrent liabilities and deferred credits of $758 million and a reduction in our noncurrent receivable from unconsolidated subsidiary in the same amount as a result of the separation of EFH Corp. and Oncor OPEB plans.

• EFH Corp.'s consolidated balance sheets reflect unfunded pension liabilities related to plans that it sponsors, but also reflects a receivable from Oncor for that portion of the unfunded liabilities for which Oncor is contractually responsible, substantially all of which is expected to be recovered in Oncor's rates. At December 31, 2015 and 2014, the receivable amount totaled zero and $47 million, respectively. The amounts are classified as a noncurrent receivable from unconsolidated subsidiary. Net amounts of pension and OPEB expenses recognized in the years ended December 31, 2015 and 2014 are not material.

• Until June 30, 2014, Oncor employees participated in a health and welfare benefit program offered by EFH Corp. In connection with Oncor establishing its own health and welfare benefits program, Oncor agreed to pay us $1 million to reimburse us for our increased costs of providing benefits under the EFH Corp. program as a result of Oncor's withdrawal and to compensate us for the administrative work related to the transition. This amount was paid in June 2014.

• In the first quarter of 2014, a cash contribution totaling $84 million was made to the EFH Corp. retirement plan, of which $64 million was contributed by Oncor and $20 million was contributed by TCEH. In December 2015, an additional cash contribution totaling $67 million was made to the EFH Corp. retirement plan, of which $51 million was contributed by Oncor and $16 million was contributed by TCEH. These contributions resulted in the EFH Corp. retirement plan being fully funded as calculated under the provisions of ERISA. As a result of the Bankruptcy Filing, participants in the EFH Corp. retirement plan who choose to retire would not be eligible for the lump sum payout option under the retirement plan unless the EFH Corp. retirement plan was fully funded. The payments by TCEH were accounted for as an advance to EFH Corp. that will be settled as pension expenses are allocated to TCEH in the normal course.

• Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred, two or more rating agencies downgrade Oncor's credit rating below investment grade.

20. SEGMENT INFORMATION

Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity operations for residential and business customers, all largely in the ERCOT market. These activities are conducted by TCEH.

The Regulated Delivery segment consists largely of our investment in Oncor. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary. See Note 4 for discussion of the reporting of Oncor Holdings and, accordingly, the Regulated Delivery segment, as an equity method investment. See Note 19 for discussion of material transactions with Oncor, including payment to Oncor of electricity delivery fees, which are based on rates regulated by the PUCT.

Corporate and Other represents the remaining non-segment operations consisting primarily of discontinued businesses, general corporate expenses and interest and other expenses related to EFH Corp., EFIH and EFCH.

142

The business segment results reflect the application of ASC 852, Reorganizations. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. Our chief operating decision maker uses more than one measure to assess segment performance, including reported segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices or regulated rates. Certain shared services costs are allocated to the segments.

	Year Ended December 31,
	2015			2014			2013
Operating revenues (all Competitive Electric)	$	5,370		$	5,978		$	5,899
Depreciation and amortization
Competitive Electric	$	852		$	1,270		$	1,333
Corporate and Other	12			13			22
Consolidated	$	864		$	1,283		$	1,355
Equity in earnings of unconsolidated subsidiaries (net of tax) (all Regulated Delivery)	$	334		$	349		$	335
Interest income
Competitive Electric	$	1		$	—		$	6
Corporate and Other	—			51			148
Eliminations	—			(50		)	(153		)
Consolidated	$	1		$	1		$	1
Interest expense and related charges
Competitive Electric	$	1,289		$	1,799		$	2,062
Corporate and Other	471			452			795
Eliminations	—			(50		)	(153		)
Consolidated	$	1,760		$	2,201		$	2,704
Income tax benefit
Competitive Electric	$	879		$	2,339		$	794
Corporate and Other	791			280			477
Consolidated	$	1,670		$	2,619		$	1,271
Net income (loss) attributable to EFH Corp.
Competitive Electric	$	(4,678	)	$	(6,260	)	$	(2,309	)
Regulated Delivery	334			349			335
Corporate and Other	(998		)	(495		)	(244		)
Consolidated	$	(5,342	)	$	(6,406	)	$	(2,218	)
Investment in equity investees
Competitive Electric	$	5		$	8		$	9
Regulated Delivery	6,059			6,050			5,950
Consolidated	$	6,064		$	6,058		$	5,959
Total assets
Competitive Electric	$	15,690		$	21,347		$	28,828
Regulated Delivery	6,059			6,050			5,950
Corporate and Other	3,039			4,025			3,692
Eliminations	(1,458		)	(2,174		)	(2,024		)
Consolidated	$	23,330		$	29,248		$	36,446
Capital expenditures
Competitive Electric	$	337		$	336		$	472
Corporate and Other	7			50			29
Consolidated	$	344		$	386		$	501

143

21. SUPPLEMENTARY FINANCIAL INFORMATION

Restricted Cash

	December 31, 2015				December 31, 2014
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH's DIP Facility (Note 12)	$	519	$	—	$	—	$	350
Amounts related to TCEH's pre-petition Letter of Credit Facility (Note 13) (a)	—		507		—		551
Other	5		—		6		—
Total restricted cash	$	524	$	507	$	6	$	901

____________

(a) See Note 13 for discussion of letter of credit draws in 2014 and 2015.

Trade Accounts Receivable

	December 31,
	2015			2014
Wholesale and retail trade accounts receivable	$	542		$	604
Allowance for uncollectible accounts	(9		)	(15		)
Trade accounts receivable — net	$	533		$	589

Gross trade accounts receivable at December 31, 2015 and 2014 included unbilled revenues of $231 million and $239 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Year Ended December 31,
	2015			2014			2013
Allowance for uncollectible accounts receivable at beginning of period	$	15		$	14		$	9
Increase for bad debt expense	34			38			33
Decrease for account write-offs	(40		)	(37		)	(28		)
Allowance for uncollectible accounts receivable at end of period	$	9		$	15		$	14

Inventories by Major Category

	December 31,
	2015		2014
Materials and supplies	$	226	$	214
Fuel stock	170		215
Natural gas in storage	32		39
Total inventories	$	428	$	468

Other Investments

	December 31,
	2015		2014
Nuclear plant decommissioning trust	$	918	$	893
Assets related to employee benefit plans, including employee savings programs, net of distributions	26		61
Land	36		37
Miscellaneous other	4		4
Total other investments	$	984	$	995

144

Nuclear Decommissioning Trust — Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor's customers as a delivery fee surcharge over the life of the plant and deposited by TCEH in the trust fund. Income and expense associated with the trust fund and the decommissioning liability are offset by a corresponding change in a receivable/payable (currently a payable reported in noncurrent liabilities) that will ultimately be settled through changes in Oncor's delivery fees rates (see Note 19). The nuclear decommissioning trust fund is not a debtor under the Chapter 11 Cases. A summary of investments in the fund follows:

	December 31, 2015
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	310	$	11	$	(2	)	$	319
Equity securities (c)	291		315		(7		)	599
Total	$	601	$	326	$	(9	)	$	918

	December 31, 2014
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	288	$	13	$	—		$	301
Equity securities (c)	276		320		(4		)	592
Total	$	564	$	333	$	(4	)	$	893

____________

(a) Includes realized gains and losses on securities sold.

(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 3.68% and 4.35% at December 31, 2015 and 2014, respectively, and an average maturity of 8 years and 6 years at December 31, 2015 and 2014, respectively.

(c) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.

Debt securities held at December 31, 2015 mature as follows: $102 million in one to five years, $75 million in five to ten years and $142 million after ten years.

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.

	Year Ended December 31,
	2015			2014			2013
Realized gains	$	1		$	11		$	2
Realized losses	$	(1	)	$	(2	)	$	(4	)
Proceeds from sales of securities	$	401		$	314		$	175
Investments in securities	$	(418	)	$	(331	)	$	(191	)

145

Property, Plant and Equipment

	December 31,
	2015		2014
Competitive Electric:
Generation and mining (Note 9)	$	11,380	$	15,468
Nuclear fuel (net of accumulated amortization of $1.383 billion and $1.237 billion)	248		265
Other assets	54		45
Corporate and Other	193		220
Total	11,875		15,998
Less accumulated depreciation	2,768		4,065
Net of accumulated depreciation	9,107		11,933
Construction work in progress:
Competitive Electric	323		459
Corporate and Other	—		5
Total construction work in progress	323		464
Property, plant and equipment — net	$	9,430	$	12,397

Depreciation expense totaled $790 million, $1.181 billion and $1.258 billion for the years ended December 31, 2015, 2014 and 2013, respectively.

Assets related to capital leases included above totaled $1 million and $51 million at December 31, 2015 and 2014, respectively, net of accumulated depreciation.

In conjunction with the impairment charges taken in 2014 and 2015 (see Note 9), we reviewed the estimated useful life of the impaired generation facilities. The estimated remaining useful lives range from 17 to 54 years for the lignite/coal and nuclear fueled generation units. Those estimated lives are subject to change as market factors evolve, including changes in environmental regulation and wholesale electricity price forecasts.

146

Asset Retirement and Mining Reclamation Obligations

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of Oncor's delivery fees.

We have established an estimated $69 million asset retirement obligation related to the Disposal of Coal Combustion Residuals from Electric Utilities rule for our existing facilities.

The following table summarizes the changes to these obligations, reported in other current liabilities and other noncurrent liabilities and deferred credits in the consolidated balance sheets, for the years ended December 31, 2015 and 2014:

	Nuclear Plant Decommissioning		Mining Land Reclamation			Other			Total
Liability at January 1, 2014	$	390	$	98		$	36		$	524
Additions:
Accretion	23		22			3			48
Incremental reclamation costs (a)	—		127			—			127
Reductions:
Payments	—		(82		)	(3		)	(85		)
Liability at December 31, 2014	$	413	$	165		$	36		$	614
Additions:
Accretion	25		20			6			51
Adjustment for new cost estimate (b)	70		—			—			70
Incremental reclamation costs (c)	—		84			69			153
Reductions:
Payments	—		(54		)	(4		)	(58		)
Liability at December 31, 2015	508		215			107			830
Less amounts due currently	—		(66		)	—			(66		)
Noncurrent liability at December 31, 2015	$	508	$	149		$	107		$	764

____________

(a) The increase in the mining reclamation liability of $127 million during 2014 was primarily due to final remediation for certain mines occurring sooner than previously estimated and increases in remediation cost estimates at other mining locations.

(b) The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in the second quarter of 2015. Under applicable accounting standards, the liability is remeasured when significant changes in the amount or timing of cash flows occurs, and PUCT rules require a new cost estimate at least every five years. The increase in the liability was driven by increased security and fuel-handling costs.

(c) The adjustment for other asset retirement obligations resulted from the effect on our estimated retirement obligation related to coal combustion residual facilities at our lignite/coal fueled generation facilities that arose from the CCR rule discussed above.

147

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:

	December 31,
	2015		2014
Uncertain tax positions, including accrued interest (Note 6)	$	40	$	74
Retirement plan and other employee benefits (a)	169		243
Asset retirement and mining reclamation obligations	764		560
Unfavorable purchase and sales contracts	543		566
Nuclear decommissioning fund excess over asset retirement obligation (Note 19)	409		479
Other	108		156
Total other noncurrent liabilities and deferred credits	$	2,033	$	2,078

____________

(a) Includes zero and $47 million at December 31, 2015 and 2014, respectively, representing pension liabilities related to Oncor (see Note 19).

Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $23 million, $23 million and $25 million for the years ended December 31, 2015, 2014 and 2013, respectively. See Note 5 for intangible assets related to favorable purchase and sales contracts.

The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:

Year	Amount
2016	$	24
2017	$	24
2018	$	24
2019	$	24
2020	$	24

Fair Value of Debt

	December 31, 2015				December 31, 2014
Debt:	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Borrowings under debtor-in-possession credit facilities (Note 12)	$	6,825	$	6,804	$	6,825	$	6,830
Long-term debt not subject to compromise, excluding capital lease obligations (Note 12)	$	90	$	89	$	123	$	119

We determine fair value in accordance with accounting standards as discussed in Note 16, and at December 31, 2015, our debt fair value represents Level 2 valuations. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg. The fair value estimates of our pre-petition notes, loans and other debt reported as liabilities subject to compromise have been excluded from the table above. As a result of our ongoing Chapter 11 Cases, obtaining the fair value estimates of our pre-petition debt subject to compromise as of December 31, 2015 is impractical, and the fair values will ultimately be decided through the Chapter 11 Cases.

148

Supplemental Cash Flow Information

	Year Ended December 31,
	2015			2014			2013
Cash payments related to:
Interest paid (a)	$	1,826		$	1,632		$	3,388
Capitalized interest	(11		)	(17		)	(25		)
Interest paid (net of capitalized interest) (a)	$	1,815		$	1,615		$	3,363
Income taxes	$	53		$	55		$	65
Reorganization items (b)	$	419		$	146		$	—
Noncash investing and financing activities:
Construction expenditures (c)	$	76		$	113		$	46
Income tax adjustment related to AMT utilization (d)	$	3		$	—		$	—
Debt exchange and extension transactions (e)	$	—		$	(85	)	$	(326	)
Principal amount of toggle notes issued in lieu of cash interest	$	—		$	—		$	173
Debt assumed related to acquired combustion turbine trust interest	$	—		$	—		$	(45	)

____________

(a) Net of amounts received under interest rate swap agreements. For the years ended December 31, 2015 and 2014, this amount also includes amounts paid for adequate protection.

(b) Represents cash payments for legal and other consulting services.

(c) Represents end-of-period accruals.

(d) Represents a reduction to EFH Corp.'s investment in Oncor Holdings due to an income tax adjustment related to alternative minimum tax (AMT) utilization by Oncor.

(e) For the year ended December 31, 2014, represents $1.836 billion principal amount of loans issued under the EFIH DIP Facility in excess of $1.673 billion principal amount of EFIH First Lien Notes exchanged and $78 million of related accrued interest (see Note 12). For the year ended December 31, 2013, represents $340 million principal amount of term loans issued under the TCEH Term Loan Facilities in consideration of extension of maturity of the facilities, $1.302 billion principal amount of EFIH debt issued in exchange for $1.310 billion principal amount of EFH Corp. and EFIH debt and $89 million principal amount of EFIH debt issued in exchange for $95 million principal amount of EFH Corp. debt.

149

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

None.

Item 9A. CONTROLS AND PROCEDURES

The Company has established disclosure controls and procedures that are designed to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and, as such, is accumulated and communicated to the Company’s management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect at December 31, 2015. Based on the evaluation performed, our management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective.

ENERGY FUTURE HOLDINGS CORP.

MANAGEMENT'S ANNUAL REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

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

The management of Energy Future Holdings Corp. performed an evaluation as of December 31, 2015 of the effectiveness of the company's internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission's (COSO's) Internal Control - Integrated Framework (2013). Based on the review performed, management believes that as of December 31, 2015 Energy Future Holdings Corp.'s internal control over external financial reporting was effective.

The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statements of Energy Future Holdings Corp. has issued an attestation report on Energy Future Holdings Corp.'s internal control over financial reporting.

Remediation of Prior Material Weakness in Internal Control Over Financial Reporting

We previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014 a material weakness in our internal control over financial reporting related to accounting for deferred income taxes. During the year ended December 31, 2015, we implemented a plan of remediation to strengthen our overall internal control over accounting for deferred income taxes. The remediation plan included the following steps:

• enhancing the formality and rigor of review and documentation related to our deferred income tax reconciliation procedures,

• implementing additional oversight and monitoring controls over our deferred income tax review processes that are designed to operate at a level of precision to detect an error resulting from a related control failure before it results in a material misstatement of our financial statements, and

• increasing key resources in our tax department and further evaluating staffing levels to ensure the execution of timely and rigorous control procedures.

150

Management has implemented and tested new and refined interim period controls and annual controls related to accounting for deferred income taxes. After completing our testing of the design and operating effectiveness of these new controls, we concluded that we have remediated the previously identified material weakness as of December 31, 2015.

Changes to Internal Control over Financial Reporting

Except for the changes described above, there have been no additional changes in the Company’s internal control over financial reporting during the most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

/s/ JOHN F. YOUNG	/s/ PAUL M. KEGLEVIC
John F. Young, President and	Paul M. Keglevic, Executive Vice President,
Chief Executive Officer	Chief Financial Officer and Co-Chief Restructuring Officer

February 29, 2016

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energy Future Holdings Corp. (Debtor-in-Possession)

Dallas, Texas

We have audited the internal control over financial reporting of Energy Future Holdings Corp. and subsidiaries (Debtor-in-Possession) (“EFH Corp.”) as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. EFH Corp.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on EFH Corp.'s internal control over financial reporting based on our audit.

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

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

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

151

In our opinion, EFH Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2015 of EFH Corp. and our report dated February 29, 2016 expressed an unqualified opinion on those financial statements and financial statement schedule and included explanatory paragraphs regarding (1) EFH Corp.’s voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code and (2) substantial doubt about EFH Corp.’s ability to continue as a going concern, which is contingent upon its ability to comply with the financial and other covenants contained in the DIP Facilities, its ability to obtain new debtor in possession financing in the event the DIP Facilities were to expire during the pendency of the Chapter 11 Cases, its ability to complete a Chapter 11 plan of reorganization in a timely manner, including obtaining applicable regulatory approvals required for such plan, and its ability to obtain any exit financing needed to implement such plan, among other factors.

/s/ Deloitte & Touche LLP

Dallas, Texas

February 29, 2016

Item 9B. OTHER INFORMATION

None

152

PART III.

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors

The names of EFH Corp.'s directors and information about them, as furnished by the directors themselves, are set forth below:

Name	Age	Served As Director Since	Business Experience
Arcilia C. Acosta (1)(3)	50	2008	Arcilia C. Acosta has served as a Director of EFH Corp. since May 2008. Ms. Acosta is the founder, President and CEO of CARCON Industries & Construction, L.L.C. (CARCON) and its subsidiaries. She is also the founder, President and CEO of Southwestern Testing Laboratories, L.L.C. (STL). CARCON's principal business is commercial, institutional and transportation, design and build construction. STL's principal business is geotechnical engineering, construction materials testing and environmental consulting services. Ms. Acosta serves on the Board of Directors of EFCH, TCEH, the Dallas Citizens Council, and the U.T. Southwestern Board of Visitors. She also serves on the Board of Legacy Texas Financial Group, National Association, where she serves on the Audit Committee and Compensation Committee.
David Bonderman	73	2007	David Bonderman has served as a Director of EFH Corp. since October 2007. He is a founding partner of TPG Capital (TPG). Mr. Bonderman serves on the boards of the following companies: Kite Pharma, Inc., Caesars Entertainment Corporation (formerly Harrah's Entertainment), Pace Holdings Corp., and Ryanair Holdings plc, for which he serves as Chairman of the Board. During the past five years, Mr. Bonderman also served on the boards of General Motors Company, JSC VTB Bank, Armstrong World Industries, Inc., CoStar Group, Inc. and Univision Communications, Inc.
Donald L. Evans (2)(3)	69	2007	Donald L. Evans has served as a Director and Executive Chairman of EFH Corp. since March 2013. Previously, he served as Director and Non-Executive Chairman of EFH Corp. from October 2007 to March 2013. He is also a Senior Partner at Quintana Energy Partners, L.P. He was CEO of the Financial Services Forum from 2005 to 2007, after serving as the 34th secretary of the U.S. Department of Commerce. Before serving as Secretary of Commerce, Mr. Evans was the former CEO of Tom Brown, Inc., a large independent energy company. During the past five years, he served on the board of Genesis Energy, L. P. He also previously served as a member and chairman of the Board of Regents of the University of Texas System.
Thomas D. Ferguson	62	2008	Thomas D. Ferguson has served as a Director of EFH Corp. since December 2008. He is a Managing Director of Goldman, Sachs & Co., having joined the firm in 2002. Mr. Ferguson heads the asset management efforts for the merchant bank's U.S. real estate investment activities. Mr. Ferguson serves on the board of managers of EFIH, Oncor and Oncor Holdings. He formerly held board seats at Associated British Ports, the largest port company in the UK; Carrix, one of the largest private container terminal operators in the world; Red de Carreteras, a toll road concessionaire in Mexico; American Golf; Agriculture Company of America; Caribbean Fund 2005; and National Golf Properties.
Brandon A. Freiman	34	2012	Brandon A. Freiman has served as a Director of EFH Corp. since June 2012. He has been with KKR since 2007, where he is a partner. He currently sits on the boards of Veresen Midstream LP, Westbrick Energy LTD, Samson Resources Corporation, Torq Energy Logistics Ltd. and Bayonne Water JV. Prior to joining KKR, he was with Credit Suisse Securities in its energy investment banking group, where he was involved in a number of merger, acquisition, and other corporate advisory transactions.
Scott Lebovitz	40	2007	Scott Lebovitz has served as a Director of EFH Corp. since October 2007. He has been a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area since 2007 having joined Goldman, Sachs & Co. in 1997. Mr. Lebovitz serves on the boards of both public and private companies, including Associated Asphalt Partners, LLC, EdgeMarc Energy Holdings, LLC, EF Energy Holdings, LLC, EW Energy Holdings, LLC, EFCH and TCEH. During the past five years, Mr. Lebovitz also served on the boards of Cobalt International Energy, Inc. and CVR Energy, Inc.

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Name	Age	Served As Director Since	Business Experience
Michael MacDougall (2)	45	2007	Michael MacDougall has served as a Director of EFH Corp. since October 2007. He is a partner of TPG. Mr. MacDougall leads the firm's global energy and natural resources investing efforts. Prior to joining TPG in 2002, Mr. MacDougall was a vice president in the Principal Investment Area of the Merchant Banking Division of Goldman, Sachs & Co., where he focused on private equity and mezzanine investments. Mr. MacDougall is a director of both public and private companies, including Amber Holdings, Inc., Harvester Holdings, LLC and its wholly owned subsidiary, Petro Harvester Oil and Gas, LLC, Jonah Energy Holdings LLC, EFCH, and TCEH and is a director of the general partner of Valerus Compression Services, L.P. (doing business as Axip Energy Services, L.P.) During the past five years, he also served on the boards of Copano Energy, L.L.C., Graphic Packaging Holding Company, Kraton Performance Polymers Inc., Nexeo Solutions Holdings, LLC and Northern Tier Energy, LLC. Mr. MacDougall is also a member of the boards of directors of The Opportunity Network and the University of Texas Development Board and of the board of trustees of Baylor College of Medicine.
Kenneth Pontarelli (2)(3)	45	2007	Kenneth Pontarelli has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He transferred to the Principal Investment Area in 1999 and was promoted to Managing Director in 2004. Mr. Pontarelli also serves as a director of EFIH and Expro International Group Ltd. During the past five years, he also served on the boards of Cobalt International Energy, L.P., CVR Energy, Inc., Tervita Corporation, and Kinder Morgan, Inc.
William K. Reilly	76	2007	William K. Reilly has served as a Director of EFH Corp. since October 2007. He is a Senior Advisor to TPG and a founding partner of Aqua International Partners, an investment group that invests in companies that serve the water sector, having previously served as the sixth Administrator of the EPA. Mr. Reilly is a director of Royal Caribbean International. During the past five years, he also served on the boards of ConocoPhillips, E.I. DuPont de Nemours, and Eden Springs, Ltd. of Israel. Before serving as EPA Administrator, Mr. Reilly was President of World Wildlife Fund and President of The Conservation Foundation. He previously served as Executive Director of the Rockefeller Task Force on Land Use and Urban Growth, a senior staff member of the President's Council on Environmental Quality, Associate Director of the Urban Policy Center and the National Urban Coalition. He also served as Co-Chairman of the National Commission on Energy Policy. Mr. Reilly was appointed by the President to serve as Co-Chair of the National Commission on the Deepwater Horizon Oil Spill and Offshore Drilling, and also to the President’s Global Development Council. He currently serves on the board of Enviva Partners, LP.
Jonathan D. Smidt (2)	43	2007	Jonathan D. Smidt has served as a Director of EFH Corp. since October 2007. He has been with KKR since 2000, where he is a partner in Europe leading KKR’s investments in the industrial sector. Currently, he is a director of Laureate Education Inc., Samson Resources Corporation, Westbrick Energy LTD, EFCH and TCEH.
Billie I. Williamson (1)	63	2013	Billie I. Williamson has served as a Director of EFH Corp. since February 2013. Ms. Williamson has 33 years of experience auditing public companies. She served as a Senior Global Client Serving and Assurance Partner from 1998 to 2011 at Ernst & Young LLP (E&Y) and E&Y's Americas Inclusiveness Officer from 2007 to 2011 prior to her retirement in 2011. She was a member of E&Y's Americas Executive Board, which functions as its board of directors, and on the U.S. Executive Board of E&Y which handled all partnership matters. Ms. Williamson also previously held executive finance positions at AMX Corp. and Marriott International, Inc. She currently serves on the boards of Pentair PLC, Janus Capital Group Inc. and CSRA Inc., and she serves on the Audit Committees of Pentair PLC and Janus Capital Group and serves as the Audit Committee chairman of CSRA Inc. as well as also serving on CSRA’s Executive Committee. From March 2012 through October 2014, Ms. Williamson was on the Board of Directors of Annie's Inc. Annie's was sold to General Mills in October 2014. From January 2012 through May 2015, she was on the Board of Directors of Exelis, Inc. Exelis was sold to Harris Corp. in May 2015.

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Name	Age	Served As Director Since	Business Experience
John F. Young (2)	59	2008	John F. Young has served as a Director of EFH Corp. since July 2008. He was elected President and Chief Executive Officer of EFH Corp. in January 2008. He also has served as Chair, President and Chief Executive of EFIH and EFCH since July 2010, having previously served as President and Chief Executive of EFIH from July 2008 to July 2010 and EFCH from April 2008 to July 2010. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008 including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon Corporation, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation. Mr. Young is also a director of Baylor Scott & White Health Foundation Advisory Board, EFCH, EFIH, Nuclear Electric Insurance Limited, TCEH, and USAA.
Kneeland Youngblood (1)	60	2007	Kneeland Youngblood has served as a Director of EFH Corp. since October 2007. He is a founding partner of Pharos Capital Group, a private equity firm that focuses on providing growth and expansion capital to businesses in business services and health care services. During the last five years, Mr. Youngblood served on the boards of Burger King Holdings, Inc., Gap Inc. and Starwood Hotels and Resorts Worldwide, Inc. He is a director of EFIH, Oncor, Oncor Holdings and Mallinckrodt public limited company and a member of the Council on Foreign Relations. He is also a director of Pace Holdings Corporation, a special purpose acquisition company.

_______________

(1) Member of Audit Committee.

(2) Member of Executive Committee.

(3) Member of Organization and Compensation Committee

There is no family relationship between any of the above-named directors.

Director Qualifications

In October 2007, David Bonderman, Donald L. Evans, Scott Lebovitz, Michael MacDougall, Kenneth Pontarelli, William K. Reilly, Jonathan D. Smidt, and Kneeland Youngblood were elected to EFH Corp.'s board of directors (the Board). Arcilia C. Acosta, Thomas D. Ferguson and John F. Young joined the Board in 2008. Brandon A. Freiman joined the Board in 2012 and Billie I. Williamson joined the Board in 2013. Messrs. Bonderman, Ferguson, Freiman, Lebovitz, MacDougall, Pontarelli, and Smidt are collectively referred to as the "Sponsor Directors." Mses. Acosta and Williamson and Messrs. Evans, Reilly, Young, and Youngblood are collectively referred to as the "Non-Sponsor Directors."

Each of the Sponsor Directors was elected to the Board pursuant to the Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership, the holder of a majority of the outstanding capital stock of EFH Corp. Pursuant to this agreement, Messrs. Freiman and Smidt were appointed to the Board as a consequence of their relationships with Kohlberg Kravis Roberts & Co.; Messrs. Bonderman and MacDougall were appointed to the Board as a consequence of their relationships with TPG Capital, L.P., and Messrs. Ferguson, Lebovitz and Pontarelli were appointed to the Board as a consequence of their relationships with GS Capital Partners.

When considering whether the Board's directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board to satisfy its oversight responsibilities effectively in light of EFH Corp.'s business and structure, the Board focused primarily on the qualifications summarized in each of the Board member's biographical information set forth above. In addition, EFH Corp. believes that each of its directors possesses high ethical standards, acts with integrity, and exercises careful judgment. Each is committed to employing his/her skills and abilities in the long-term interests of EFH Corp and its stakeholders. Finally, our directors are knowledgeable and experienced in business, governmental, and civic endeavors, further qualifying them for service as members of the Board.

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The Sponsor Directors possess experience in owning and managing privately held enterprises and are familiar with corporate finance and strategic business planning activities of highly-leveraged companies such as EFH Corp. Some of the Sponsor Directors also have experience advising and overseeing the operations of large industrial, manufacturing or retail companies similar to our businesses. Finally, several of the Sponsor Directors possess substantial expertise in advising and managing companies in segments of the energy industry, including, among others, power generation, oil and gas, and energy infrastructure and transportation.

As a group and individually, the Non-Sponsor Directors possess extensive experience in governmental and civic endeavors and in the business community, in each case, in the markets where our businesses operate.

Mr. Young's employment agreement provides that he will serve as a member of the Board during the time he is employed by EFH Corp. Before joining EFH Corp. as President and Chief Executive Officer, he held various senior management positions at other companies in the energy industry over twenty years, including, most recently, his role as Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation.

Ms. Acosta manages the operations of a large commercial construction company in Texas and has significant experience within the local Hispanic business community, having served as the chair of the Greater Dallas Hispanic Chamber of Commerce and the Texas Association of Mexican American Chambers of Commerce. Mr. Evans has demonstrated ability and achievement in both the public and private sectors, serving as U.S. Secretary of Commerce during the Bush Administration, and both before and after his government service, acting as Chairman and Chief Executive Officer of a publicly-owned energy company, Tom Brown, Inc. Mr. Reilly possesses a distinguished record of public service and extensive policy-making experience as a former administrator of the EPA, lectures extensively on environmental issues facing companies operating in the energy industry and has served as Co-Chairman of the National Commission on Energy Policy. Ms. Williamson has considerable financial and accounting knowledge and experience, including increasingly senior level auditing experience culminating with service as Senior Assurance Partner at Ernst & Young LLP where she handled very large multi-national accounts. She also served as chief financial officer of AMX Corp. and as SVP Finance and Corporate Controller of Marriott International, Inc. Ms. Williamson currently serves as a member of the boards of directors of three other public companies and is a member of the audit committees of all three of these companies. Additionally, Ms. Williamson served on the boards of two other publicly held companies until the sale of those companies was completed. Ms. Williamson has been licensed as a Certified Public Accountant in the State of Texas since 1976. Her financial and accounting knowledge and experience qualify her to serve as EFH Corp.'s "audit committee financial expert." Mr. Youngblood has served on numerous boards for large public companies, has extensive experience managing and advising companies in his capacity as a partner in a private equity firm (not affiliated with the Sponsor Group), is highly knowledgeable of federal and state political matters, and has served on the board of directors of the United States Enrichment Corporation, a company that contracts with the US Department of Energy to produce enriched uranium for use in nuclear power plants.

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Executive Officers

The names and information regarding EFH Corp.'s executive officers are set forth below:

Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience (Preceding Five Years)
John F. Young	59	President and Chief Executive Officer of EFH Corp. and Chair, President and Chief Executive Officer of EFIH and EFCH	January 2008	John F. Young was elected President and Chief Executive Officer of EFH Corp. in January 2008. He also has served as Chair, President and Chief Executive of EFIH and EFCH since July 2010, having previously served as President and Chief Executive of EFIH from July 2008 to July 2010 and EFCH from April 2008 to July 2010. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008, including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon Corporation, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation.
James A. Burke	47	Executive Vice President of EFH Corp. and President and Chief Executive of TXU Energy	August 2005	James A. Burke was elected Executive Vice President of EFH Corp. in February 2013 and President and Chief Executive of TXU Energy in August 2005. Previously, Mr. Burke was Senior Vice President Consumer Markets of TXU Energy.
Stacey H. Doré	43	Executive Vice President, General Counsel and Co-Chief Restructuring Officer of EFH Corp., EFIH and EFCH	October 2013	Stacey H. Doré was elected Executive Vice President, General Counsel and Co-Chief Restructuring Officer of EFH Corp. and EFCH in October 2013 and EFIH in February 2014, having previously served as Senior Vice President, General Counsel and Co-Chief Restructuring Officer of EFIH from October 2013 to February 2014, Executive Vice President and General Counsel of EFH Corp. from February 2013 to October 2013 and EFCH from April 2013 to October 2013, and Senior Vice President and General Counsel of EFH Corp. from April 2012 to February 2013, and EFIH and EFCH from April 2012 to October 2013. Ms. Doré was Vice President and General Counsel of Luminant from November 2011 to March 2012, and Vice President and Associate General Counsel of EFH Corp. from July 2008 to November 2011. Prior to joining EFH Corp., she was an attorney at Vinson & Elkins LLP, where she engaged in a business litigation practice.
Paul M. Keglevic	62	Executive Vice President, Chief Financial Officer and Co-Chief Restructuring Officer of EFH Corp., EFIH and EFCH	October 2013	Paul M. Keglevic was elected Executive Vice President, Chief Financial Officer and Co-Chief Restructuring Officer of EFH Corp., EFIH and EFCH in October 2013 having previously served as Executive Vice President and Chief Financial Officer of EFH Corp., EFIH and EFCH from July 2008 to October 2013. Before joining EFH Corp., he was an audit partner at PricewaterhouseCoopers. Mr. Keglevic was PricewaterhouseCoopers' Utility Sector Leader from 2002 to 2008 and Clients and Sector Assurance Leader from 2007 to 2008.

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Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience (Preceding Five Years)
Carrie L. Kirby	48	Executive Vice President of EFH Corp.	February 2013	Carrie L. Kirby was elected Executive Vice President of EFH Corp. in February 2013 having previously served as Senior Vice President of EFH Corp. from April 2012 to February 2013 and oversees human resources. Previously she was Vice President of Human Resources of TXU Energy.
M. A. McFarland	46	Executive Vice President of EFH Corp. and President and Chief Executive of Luminant	July 2008	M. A. McFarland was elected President and Chief Executive of Luminant in December 2012 and Executive Vice President of EFH Corp. in July 2008. He previously served as Executive Vice President and Chief Commercial Officer of Luminant. Before joining Luminant, Mr. McFarland served as Senior Vice President of Mergers, Acquisitions and Divestitures and as a Vice President in the wholesale marketing and trading division power team at Exelon Corporation.

There is no family relationship between any of the above-named executive officers.

Audit Committee Financial Expert

The Board has determined that Billie I. Williamson is an "Audit Committee Financial Expert" as defined in Item 407(d)(5) of SEC Regulation S-K.

Code of Conduct

EFH Corp. maintains certain corporate governance documents on EFH Corp's website atwww.energyfutureholdings.com. EFH Corp.'s Code of Conduct can be accessed by selecting "Investor Relations" on the EFH Corp. website. EFH Corp.'s Code of Conduct applies to all of its employees, officers (including the Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer) and directors. Any amendments to the Code of Conduct and any grant of a waiver from a provision of the Code of Conduct requiring disclosure under applicable SEC rules will be posted on EFH Corp.'s website. Printed copies of the corporate governance documents that are posted on EFH Corp.'s website are also available to any investor upon request to the Secretary of EFH Corp. at 1601 Bryan Street, Dallas, Texas 75201-3411.

Procedures for Shareholders to Nominate Directors; Arrangement to Serve as Directors

The Amended and Restated Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC, the general partner of Texas Holdings, generally requires that the members of Texas Energy Future Capital Holdings LLC take all necessary action to ensure that the persons who serve as its managers also serve on the EFH Corp. Board. In addition, Mr. Young's employment agreement provides that he will be elected as a member of the Board during the time he is employed by EFH Corp.

Because of these requirements, together with Texas Holdings' controlling ownership of EFH Corp.'s outstanding common stock, there is no policy or procedure with respect to shareholder recommendations for nominees to the EFH Corp. Board.

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Item 11. EXECUTIVE COMPENSATION

Organization and Compensation Committee

During 2015, the Organization and Compensation Committee (the O&C Committee) of EFH Corp.'s Board of Directors (the Board) consisted of three directors: Arcilia C. Acosta, Donald L. Evans, and Kenneth Pontarelli. The primary responsibilities of the O&C Committee are to:

• determine and oversee the compensation program of EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities), including making recommendations to the Board with respect to the adoption, amendment or termination of compensation and benefits plans, arrangements, policies and practices;

• evaluate the performance of EFH Corp.'s President and Chief Executive Officer (the CEO), John F. Young, and the other executive officers of EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities) (collectively, the executive officers), including Paul M. Keglevic, Executive Vice President, Chief Financial Officer and Co-Chief Restructuring Officer of EFH Corp.; James A. Burke, President and Chief Executive of TXU Energy and Executive Vice President of EFH Corp.; Stacey H. Doré, Executive Vice President, General Counsel and Co-Chief Restructuring Officer of EFH Corp.; and M.A. McFarland, President and Chief Executive of Luminant and Executive Vice President of EFH Corp. (collectively, the Named Executive Officers); and

• approve executive compensation based on those evaluations.

Compensation Risk Assessment

Our management team initiates EFH Corp.'s internal risk review and assessment process for our compensation policies and practices by assessing, among other things: (1) the mix of cash and equity payouts at various compensation levels and, more recently, the necessity of adjusting such mix in light of our Bankruptcy Filing (as defined herein); (2) the performance time horizons used by our plans; (3) the use of multiple financial and operational performance metrics that are readily monitored and reviewed; (4) the incorporation of both operational and financial goals and individual performance modifiers; (5) the inclusion of maximum caps and other plan-based mitigants on the amount of our awards; and (6) multiple levels of review and approval of awards (including approval of our O&C Committee with respect to awards to executive officers and awards to other employees that exceed monetary thresholds). Following their assessment, our management team prepares a report, which is provided to EFH Corp.'s Audit Committee for review. The EFH Corp. Audit Committee reviews the report and provides it to the O&C Committee. EFH Corp.'s management and Audit Committee have determined that the risks arising from EFH Corp.'s compensation policies and practices are not reasonably likely to have a material adverse effect on EFH Corp.

Compensation Discussion and Analysis

Executive Summary

Effect of Bankruptcy Filing

On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities (the Debtors), filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court), which proceedings are referred to herein as our Chapter 11 Cases. The Bankruptcy Filing resulted primarily from the adverse effects on EFH Corp.'s competitive businesses of lower wholesale electricity prices in ERCOT driven by the sustained decline in natural gas prices since mid-2008, which challenged the profitability and operating cash flows of EFH Corp.'s competitive businesses and resulted in the inability to support their significant interest payments and debt maturities and to refinance and/or extend the maturities of their outstanding debt. In December 2015, the Bankruptcy Court confirmed the Sixth Amended and Restated Plan of Reorganization of the Debtors (the Plan of Reorganization). The effectiveness of the Plan of Reorganization is subject to a number of conditions that have not yet been satisfied.

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Throughout our Chapter 11 Cases, the Company has achieved strong operational performance due, we believe, to the strength and attributes of our management team and employees, whose continued contributions are critical throughout the pendency of our Chapter 11 Cases. The Debtors' operations are complex and include, among other things, electricity generation, mining operations, wholesale energy sales and purchases, commodity risk management, and retail electricity sales and marketing. In addition to effectively executing the Debtors’ business strategies and complex operations in a fiercely competitive industry, we believe our employees have driven, and will continue to drive, the success of the Debtors' restructuring and have served, and will continue to serve, a crucial role in maximizing the value of the Debtors' estates. The O&C Committee continues to evaluate and adjust, as appropriate, the elements of our compensation programs to maintain the alignment of our incentive programs and our organizational focus during the Chapter 11 Cases.

During the pendency of our Chapter 11 Cases, our Named Executive Officers are considered "insiders" under the Bankruptcy Code. As a result, any payments made by the Debtorsto our Named Executive Officers require approval by the Bankruptcy Court. As further described herein, in December 2014 and December 2015, the Bankruptcy Court approved the incentive compensation programs proposed by the O&C Committee for our Named Executive Officers and other insiders for 2015 and 2016, respectively.

Compensation Philosophy

We have a pay-for-performance compensation philosophy, which places an emphasis on pay-at-risk; a significant portion of an executive officer's compensation is comprised of variable compensation. Our compensation program is intended to attract and motivate top-talent executive officers as leaders and compensate executive officers appropriately for their contribution to the attainment of our financial, operational and strategic objectives. In addition, we believe it is important to retain our top tier talent and strongly align their interests with our stakeholders by emphasizing incentive based compensation. Given the competitive nature of the unregulated market in ERCOT, the evolving regulatory environment, and our current restructuring efforts, we believe maintaining continuity and engagement of such talent is critical to our continued success, and we are sensitive to the challenges related to long-term incentive compensation in light of the Chapter 11 Cases.

To achieve the goals of our compensation philosophy, we believe that:

• the overall compensation program should emphasize variable compensation elements that have a direct link to overall corporate performance and stakeholder value;

• the overall compensation program should place an increased emphasis on pay-at-risk with increased responsibility;

• the overall compensation program should attract, motivate and engage top-talent executive officers to serve in key roles; and

• an executive officer's individual compensation level should be based upon an evaluation of the financial and operational performance of that executive officer's business unit or area of responsibility as well as the executive officer's individual performance.

We believe our compensation philosophy supports our businesses by:

• aligning performance measures with our business objectives to drive the financial and operational performance of EFH Corp. and its business units;

• rewarding business unit and individual performance by providing compensation levels consistent with the relevant employee's level of contribution, degree of accountability and functional areas of responsibility; and

• attracting and retaining the best performers.

Elements of Compensation

The material elements of our executive compensation program are:

• a competitive base salary;

• the opportunity to earn an annual performance-based cash bonus based on the achievement of specific corporate, business unit and individual performance goals; and

• additional incentive awards in the form of cash awards.

In addition, executive officers generally have the opportunity to participate in certain of our broad-based employee benefit plans, including our Thrift (401(k)) Plan and health and welfare plans, and to receive certain perquisites.

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Compensation of the CEO

In determining the compensation of the CEO, the O&C Committee annually follows a thorough and detailed process. At the end of each year, the O&C Committee reviews a self-assessment prepared by the CEO regarding his performance and the performance of our businesses and meets (with and without the CEO) to evaluate and discuss his performance and the performance of our businesses.

While the O&C Committee tries to ensure that a substantial portion of the CEO's compensation is directly linked to his performance and the performance of our businesses, the O&C Committee also seeks to set his compensation in a manner that is competitive with compensation for similarly performing executive officers with similar responsibilities in companies we consider our peers.

Compensation of Other Executive Officers

In determining the compensation of each of our executive officers (other than the CEO), the O&C Committee seeks the input of the CEO. At the end of each year, the CEO reviews a self-assessment prepared by each executive officer and assesses the executive officer's performance against business unit (or area of responsibility) and individual goals and objectives. The O&C Committee and the CEO then review the CEO's assessments and, in that context, the O&C Committee approves the compensation for each executive officer.

Assessment of Compensation Elements

We design the majority of our executive officers' compensation to be linked directly to corporate and business unit (or area of responsibility) performance. For example, each executive officer's annual performance-based cash bonus is primarily based on the achievement of certain corporate and business unit financial and operational targets (such as management EBITDA, as discussed herein, cost management, generation output, customer satisfaction, etc.). In addition, each executive officer's additional cash incentive award is based on achievement of certain operational and financial performance metrics. We also try to ensure that our executive compensation program is competitive with our peer companies in order to effectively motivate and retain our executive officers.

The following is a detailed discussion of the principal compensation elements provided to our executive officers. Additional detail about each of the elements can be found in the compensation tables, including the footnotes and the narrative discussion following certain of the tables.

Executive Compensation Evaluation and Adjustment

In October 2012, the O&C Committee engaged Towers Watson & Co., now known as Willis Towers Watson (Towers Watson), an independent compensation consultant to review our compensation practices and to confirm whether such practices continue to be aligned with our compensation philosophy. Since being engaged, Towers Watson has annually delivered reports to the O&C Committee, which, in 2015, included market data for a peer group composed of the following companies:

Ameren Corp.	American Electric Power Co. Inc.	Calpine Corp.
Dominion Resources Inc.	Duke Energy Corp.	Edison International
Entergy Corp.	Exelon Corp.	FirstEnergy Corp.
NextEra Energy, Inc.	NRG Energy, Inc.	PPL Corp.
Public Service Enterprise Group Inc.	Southern Co.	Xcel Energy Inc.

The O&C Committee does not target any particular level of total compensation or individual component of compensation against the peer group; rather the O&C Committee considers the range of total compensation provided by our peers, together with our position as a privately-owned company that is a debtor under Chapter 11 of the Bankruptcy Code, in determining the appropriate mix and level of total compensation for our executives.

Base Salary

We believe base salary should consider the scope and complexity of an executive officer's position and the level of responsibility required to perform his or her job. We also believe that a competitive level of base salary is required to attract, motivate and retain qualified talent.

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We want to ensure our cash compensation is competitive and sufficient to incent executive officers to remain with us, recognizing our high performance expectations across a broad set of operational, financial, customer service and community-oriented goals and objectives, as well as the additional demands placed upon our management team resulting from our Chapter 11 Cases.

The O&C Committee regularly reviews base salaries and periodically uses independent compensation consultants to ensure the base salaries are market-competitive. The O&C Committee may also review an executive officer's base salary from time to time during a year, including if the executive officer is given a promotion or if his or her responsibilities are significantly modified.

The base salaries of our Named Executive Officers have not changed since January 1, 2015.

Annual Performance-Based Cash Bonus - Executive Officer Annual Incentive Plan

The Executive Officer Annual Incentive Plan (EAIP) provides an annual performance-based cash bonus for the successful attainment of certain financial and operational performance targets that are established annually at each of the corporate and business unit levels by the O&C Committee. Under the terms of the EAIP, performance against these targets, which are set at challenging levels to incentivize exceptional performance (while at the same time balancing the needs for safety and investment in our business), drives bonus funding. As a general matter, target level performance is based on EFH Corp.'s board-approved financial and operational plan (the Financial Plan) for the upcoming year. The O&C Committee sets high expectations for our executive officers and therefore annually selects a target performance level that constitutes above average performance for the business, which the O&C Committee expects the business to achieve during the upcoming year. Threshold and superior levels are for performance levels that are below or above Financial Plan-based expectations, respectively. Based on the level of attainment of these performance targets, an aggregate EAIP funding percentage amount for all participants is determined. In addition, since our Bankruptcy Filing, the Bankruptcy Court has approved these performance levels as part of approving the compensation programs for insiders.

Our financial performance targets typically include "management" EBITDA, a non-GAAP financial measure. When the O&C Committee reviews management EBITDA for purposes of determining our performance against the applicable management EBITDA target, it includes our net income (loss) before interest, taxes, depreciation and amortization plus transaction and restructuring costs, together with such adjustments as the O&C Committee shall determine appropriate in its discretion after good faith consultation with our CEO and Chief Financial Officer, including adjustments consistent with those included in the comparable definitions in our TCEH DIP Facility (to the extent considered appropriate for executive compensation purposes). Our management EBITDA targets are also adjusted for acquisitions, divestitures, major capital investment initiatives and other operational considerations, to the extent that they were material and not contemplated in our annual Financial Plan. The management EBITDA targets are intended to measure achievement of the Financial Plan and the adjustments to management EBITDA described above primarily represent elements of our performance that are either beyond the control of management or were not predictable at the time the annual Financial Plan was approved. Given our Named Executive Officer's business unit responsibilities, our management EBITDA calculations for Mr. Young include Oncor, while management EBITDA calculations for the remaining Named Executive Officers exclude Oncor. Under the terms of the EAIP, the O&C Committee has broad authority to make these or any other adjustments to EBITDA that it deems appropriate in connection with its evaluation and compensation of our executive officers. Management EBITDA is an internal measure used only for performance management purposes, and EFH Corp. does not intend for management EBITDA to be an alternative to any measure of financial performance presented in accordance with GAAP. Management EBITDA is calculated similarly to TCEH Consolidated EBITDA, which is disclosed elsewhere in this Form 10-K and defined in the glossary to this Form 10-K, and reflects substantially all the computational elements of TCEH Consolidated EBITDA.

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Financial and Operational Performance Targets for our Named Executive Officers

The following table provides a summary of the weight given to the various business unit scorecards, which constitute the performance targets under the EAIP, for each of our Named Executive Officers.

	Weight
Name	EFH Corp. Management EBITDA(2)		Named Executive Officer EFH Business Services Scorecard Multiplier		Named Executive Officer Luminant Scorecard Multiplier		Named Executive Officer TXU Energy Scorecard Multiplier		Total		Payout
John F. Young(1)	50	%	50	%					100	%	129	%
Paul M. Keglevic	50	%	50	%					100	%	137	%
James A. Burke	25	%					75	%	100	%	153	%
Stacey H. Doré	50	%	50	%					100	%	137	%
M.A. McFarland	25	%			75	%			100	%	127	%

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(1) Mr. Young is measured on EFH Corp. Management EBITDA (including Oncor) while the remaining Named Executive Officers are measured on EFH Corp. Management EBITDA (excluding Oncor).

(2) The targeted EFH Corp. Management EBITDA (including Oncor) for the fiscal year ended December 31, 2015 was $3.334 billion. The targeted EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2015 was $1.503 billion. The actual EFH Corp. Management EBITDA (including Oncor) for the fiscal year ended December 31, 2015 was $3.358 billion, which was above target. The actual EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2015 was $1.538 billion, which was above target.

The following table provides a summary of the performance targets included in the EFH Business Services Scorecard Multiplier for our Named Executive Officers.

Named Executive Officer EFH Business Services Scorecard Metrics	Weight		Performance(1)		Payout
EFH Corp. Management EBITDA (excluding Oncor)(2)	20.0	%	122	%	24	%
Luminant Scorecard Multiplier(3)	20.0	%	128	%	26	%
TXU Energy Scorecard Multiplier(3)	20.0	%	163	%	33	%
EFH Corp. (excluding Oncor) Total Spend	20.0	%	200	%	40	%
EFH Business Services Costs	20.0	%	145	%	29	%
Total	100.0	%			152	%

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(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated on a linear basis between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

(2) The targeted EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2015 was $1.503 billion. The actual EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2015 was $1.538 billion, which was above target.

(3) The performance targets included in the Luminant Scorecard Multiplier and the TXU Energy Scorecard Multiplier are summarized below.

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The following table provides a summary of the performance targets included in the Luminant Scorecard Multiplier for our Named Executive Officers.

Named Executive Officer Luminant Scorecard Metrics	Weight		Performance(1)		Payout
Luminant Management EBITDA	37.5	%	91	%	34	%
Luminant Available Generation - Lignite/Coal (June-Sept. 15)	10.0	%	100	%	10	%
Luminant Available Generation - Lignite/Coal (Jan.-May, Sept. 16-Dec.)	10.0	%	110	%	11	%
Luminant Available Generation – Nuclear	7.5	%	67	%	5	%
Luminant Operating Costs/SG&A	15.0	%	200	%	30	%
Luminant Capital Expenditures	10.0	%	200	%	20	%
Luminant Fossil Fuel Costs	10.0	%	180	%	18	%
Total	100.0	%			128	%

____________

(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated on a linear basis between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

The following table provides a summary of the performance targets included in the TXU Energy Scorecard Multiplier for our Named Executive Officers.

Named Executive Officer TXU Energy Scorecard Metrics	Weight		Performance(1)		Payout
TXU Energy Management EBITDA	40.0	%	200	%	80	%
TXU Energy Total Costs	20.0	%	85	%	17	%
Contribution Margin	15.0	%	200	%	30	%
Residential Customer Count	10.0	%	190	%	19	%
Customer Satisfaction	3.0	%	133	%	4	%
Average Days Sales Outstanding	3.0	%	67	%	2	%
TXU Energy Energizing Event Success	3.0	%	133	%	4	%
TXU Energy Customer Satisfaction (Complaints)	3.0	%	133	%	4	%
TXU Energy System Availability (Downtime)	3.0	%	100	%	3	%
Total	100.0	%			163	%

____________

(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated on a linear basis between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

Individual Performance Modifier

After approving the actual performance against the applicable targets under the EAIP, the O&C Committee and/or the CEO reviews the performance of each of our executive officers on an individual and comparative basis. Based on this review, which includes an analysis of both objective and subjective criteria, as determined by the O&C Committee in its sole discretion, including the CEO's recommendations (with respect to all executive officers other than himself), the O&C Committee approves an individual performance modifier for each executive officer. Under the terms of the EAIP, the individual performance modifier can range from an outstanding rating (150%) to an unacceptable rating (0%). To calculate an executive officer’s final annual cash incentive bonus, the executive officer’s corporate/business unit payout percentages are multiplied by the executive officer’s target incentive level, which is computed as a percentage of annualized base salary, and then by the executive officer’s individual performance modifier.

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Actual Awards

The following table provides a summary of the 2015 performance-based cash bonus for each Named Executive Officer under the EAIP.

Name	Target (% of salary)	Target Award ($ Value)	Actual Award ($)
John F. Young (1)	125%	1,687,500	3,166,501
Paul M. Keglevic (2)	85%	667,250	1,323,267
James A. Burke (3)	85%	595,000	1,190,000
Stacey H. Doré(4)	85%	552,500	1,095,699
M.A. McFarland (5)	85%	595,000	1,091,292

____________

(1) Mr. Young's incentive award is based on the successful achievement of the financial performance targets for EFH Corp. (including Oncor) and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier. In 2015, Mr. Young maintained our workforce's focus on "Job One" (the provision of excellent operations) across the Company and successfully managed communications with our employees, regulators and constituents as we continued through the Chapter 11 Cases. Given these and other significant achievements, the O&C Committee approved an individual performance modifier that increased Mr. Young's incentive award.

(2) Mr. Keglevic's incentive award is based on the successful achievement of the financial performance targets for EFH Corp. (excluding Oncor) and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier. In 2015, Mr. Keglevic, as Co-Chief Restructuring Officer and Chief Financial Officer, successfully oversaw and led a team on behalf of our Company that negotiated our Plan of Reorganization as well as the transactions that form a part of such plan. Additionally, Mr. Keglevic served as our lead witness for many of the proceedings in our Chapter 11 Cases, including with respect to our Plan of Reorganization, all while continuing to drive strong economic performance from the Company. Given these and other significant achievements, the O&C Committee approved an individual performance modifier that increased Mr. Keglevic's incentive award.

(3) Mr. Burke's incentive award is based on the successful achievement of a financial performance target for EFH Corp. (excluding Oncor) and the financial and operational performance targets for TXU Energy and an individual performance modifier. In 2015, under Mr. Burke's leadership, TXU Energy maintained its strong customer experience performance despite the Chapter 11 Cases, successfully managed margins, improved market-leading customer service, lowered residential customer attrition, grew our business segment, and was named as one of the top 100 places to work by The Dallas Morning News. In addition to his duties as the Chief Executive of TXU Energy, Mr. Burke led a cross-functional and enterprise-wide (excluding Oncor) team focused on contract and vendor management across the enterprise (excluding Oncor) during our Chapter 11 Cases. Given these and other significant achievements, the O&C Committee approved an individual performance modifier that increased Mr. Burke's incentive award.

(4) Ms. Doré's incentive award is based on the successful achievement of the financial performance targets for EFH Corp. (excluding Oncor) and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier. In 2015, as Co-Chief Restructuring Officer and General Counsel, Ms. Doré oversaw the handling of all legal matters arising in connection with our Chapter 11 Cases and, together with Mr. Keglevic, led a team on behalf of the Company that negotiated our Plan of Reorganization as well as the transactions that form a part of such plan. Ms. Doré also led a team that achieved significant positive litigation outcomes for Luminant during 2015. Given these and other significant achievements, the O&C Committee approved an individual performance modifier that increased Ms. Doré's incentive award.

(5) Mr. McFarland's incentive award is based on the successful achievement of the financial performance targets for EFH Corp. (excluding Oncor) and the financial and operational performance targets for Luminant and an individual performance modifier. In 2015, Mr. McFarland spearheaded Luminant's organizational response to continued low power prices while maintaining operational excellence and top decile performance from our generation fleet and was the lead executive responsible for the acquisition of the 2,988 MW La Frontera CCGT portfolio. Given these and other significant achievements, the O&C Committee approved an individual performance modifier that increased Mr. McFarland's incentive award.

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Supplemental Incentive Awards

We have historically offered incentive based awards as part of our overall compensation because we believe such awards incentivize and reward our Named Executive Officers for superior performance and drive performance for the enterprise as a whole. Beginning in 2012, the O&C Committee engaged Towers Watson to develop an incentive based program that is market-based and consistent with competitive practices for our peers in the power industry and our peers that are, or have been, debtors under Chapter 11 of the Bankruptcy Code.

Annual Supplemental Awards

In 2015, the O&C Committee introduced annual supplemental awards (the Annual Supplemental Awards) for certain of our executive officers, and such awards are based upon the achievement of semi-annual and cumulative annual performance goals established by the O&C Committee for each of 2015 and 2016. The Annual Supplemental Awards provide each of our Named Executive Officers the opportunity to earn up to $500,000 ($1,350,000 for Mr. Young) in each semi-annual period in 2015 and 2016 if performance goals are achieved (and he or she is employed by EFH Corp. or an affiliate on the last day of such period). The sum of each Named Executive Officer's awards under the Additional Incentive Awards for each of 2015 and 2016 will not exceed $1,000,000 ($2,700,000 for Mr. Young). The actual amount paid under the awards is based upon semi-annual and year-to-date performance of our businesses in 2015 and 2016 as compared to the baseline and threshold semi-annual and year-to-date performance goals for such businesses established annually by the O&C Committee.

To the extent earned, the Annual Supplemental Awards for 2015 and 2016 will be distributed in accordance with their terms and will terminate on the earlier of December 31, 2016 or the date on which the Named Executive Officer receives a grant under a long-term equity incentive plan established in connection with our emergence from the Chapter 11 Cases. In the event of such Named Executive Officer's termination without cause, resignation for good reason or termination due to death or disability or upon a change of control, such Annual Supplemental Award will vest and become payable, to the extent earned, on a pro-rated basis, for such applicable performance period. Please refer to the "Grants of Plan-Based Awards - 2015" table, including the footnotes thereto, for a more detailed description of the Annual Supplemental Awards for each Named Executive Officer.

Long-Term Equity Incentives

Given the Bankruptcy Filing, our equity-based compensation has de minimis monetary value and we have adjusted our compensation practices to take into account the minimal incentive value related to our equity. We believe such adjustments further align the compensation of our executive officers, including our Named Executive Officers, with the interests of all of our stakeholders, which will evolve during our restructuring, by emphasizing short term, measurable goals in recognition of the dynamic nature of the Chapter 11 Cases. Under the Plan of Reorganization and upon its effective date, all EFH Corp. common stock (and prior granted restricted stock units) will be cancelled without any distribution or payment.

Other Elements of Compensation

General

Our executive officers generally have the opportunity to participate in certain of our broad-based employee compensation plans, including our Thrift (401(k)) Plan, and health and welfare plans. Please refer to the footnotes to the Summary Compensation Table and Note 18 to the Financial Statements for a more detailed description of our Thrift Plan, and the narrative that follows the "Pension Benefits - 2015" table for a more detailed description of our Supplemental Retirement Plan.

Perquisites

We provide our executives with certain perquisites on a limited basis. The perquisites are generally intended to enhance our executive officers' ability to conduct company business. These benefits include financial planning, preventive health maintenance, and reimbursement for certain club memberships and certain spousal travel expenses. Expenditures for the perquisites described below are disclosed by individual in footnote 5 to the Summary Compensation Table. The following is a summary of perquisites offered to our Named Executive Officers that are not available to all employees:

Executive Financial Planning: We pay for our executive officers to receive financial planning services. This service is intended to support them in managing their financial affairs, which we consider especially important given the high level of time commitment and performance expectation required of our executive officers. Furthermore, we believe that such service helps ensure greater accuracy and compliance with individual tax regulations by our executive officers.

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Health Services: We pay for our executive officers to receive annual physical health exams and we purchased an annual membership for Messrs. Young and Keglevic to participate in a comprehensive health plan that provides anytime personal and private physician access and health care. The health of our executive officers is important given the vital leadership role they play in directing and operating the company. Our executive officers are important assets of EFH Corp., and these benefits are designed to help ensure their health and long-term ability to serve our stakeholders.

Club Memberships: We reimburse certain of our executives for the cost of golf and social club memberships, provided that the club membership provides for a business-use opportunity, such as client networking and entertainment. The club membership reimbursements are provided to assist the executives in cultivating business relationships.

Spouse Travel Expenses: From time to time, we pay for an executive officer's spouse to travel with the executive officer when taking a business trip.

Payments Contingent Upon a Change of Control of EFH Corp.

We have entered into employment agreements with each of our Named Executive Officers. Each of the employment agreements provides that certain payments and benefits will be paid upon the expiration or termination of the agreement under various circumstances, including termination without cause, resignation for good reason and termination of employment within a fixed period of time following a change in control of EFH Corp. We believe these provisions are important in order to attract, motivate and retain the caliber of executive officers that our business requires and provide incentive for our executive officers to fully consider potential changes that are in our and our stakeholders' best interest, even if such changes could result in the executive officers' termination of employment. Under the terms of the Plan of Reorganization, the effectiveness of the Plan of Reorganization is considered a change in control for purposes of the employment agreements and these employment agreements will be assumed by Reorganized TCEH. For a description of the applicable provisions in the employment agreements of our Named Executive Officers see "Potential Payments upon Termination or Change in Control."

Other

Under the terms of Mr. Young's employment agreement, we have purchased a 10-year term life insurance policy (to be paid to a beneficiary of his choice) in an insured amount equal to $10,000,000. In addition, under the terms of Mr. Young's employment agreement, on December 31, 2014, Mr. Young became entitled to a Company-purchased single premium annuity contract, with a net value of $3,000,000. Each of these benefits was originally included as a part of Mr. Young's compensation package to set his compensation in a manner that is competitive with compensation for chief executive officers in companies we consider our peers.

Accounting and Tax Considerations

Accounting Considerations

Because our common stock is not registered or publicly traded, the O&C Committee does not generally consider the effect of accounting principles when making executive compensation decisions.

Income Tax Considerations

Section 162(m) of the Code limits the tax deductibility by a publicly-held company of compensation in excess of $1 million paid to the CEO or any other of its three most highly compensated executive officers other than the principal financial officer. Because EFH Corp. is a privately-held company, Section 162(m) will not limit the tax deductibility of any executive compensation for 2015, and the O&C Committee does not take it into account when making executive compensation decisions.

Say on Pay Vote

Because EFH Corp. is a privately-held company, we are not required to hold say-on-pay votes concerning the compensation of our Named Executive Officers.

167

Organization and Compensation Committee Report

The O&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth in this Form 10-K. Based on this review and discussions, the committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K.

Organization and Compensation Committee

Donald L. Evans, Chair

Arcilia C. Acosta

Kenneth Pontarelli

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Summary Compensation Table—2015

The following table provides information for the fiscal years ended December 31, 2015, 2014 and 2013 regarding the aggregate compensation paid to our Named Executive Officers.

Name and Principal Position	Year	Salary ($)	Bonus ($)(1)	Stock Awards ($)(2)	Non-Equity Incentive Plan Compen-sation ($)(3)	Change in Pension Value and Non-qualified Deferred Compensation ($)(4)	All Other Compen-sation ($)(5)	Total ($)
John F. Young President & CEO of EFH Corp.	2015 2014 2013	1,350,000 1,350,000 1,350,000	— — —	— — 420,000	5,866,501 5,736,327 5,511,375	— — —	65,840 72,993 73,152	7,282,341 7,159,320 7,354,527
Paul M. Keglevic       EVP, Chief Financial Officer & Co-CRO of EFH Corp.	2015 2014 2013	785,000 735,000 735,000	— — 375,000	— — 140,000	2,323,267 2,147,578 2,049,580	— — —	50,876 57,901 54,037	3,159,143 2,940,479 3,353,617
James A. Burke EVP-EFH Corp. &President & Chief Executive of TXU Energy	2015 2014 2013	700,000 675,000 675,000	— — —	— — 140,000	2,190,000 1,994,415 2,116,518	— 44,090 6,227	29,709 28,965 29,203	2,919,709 2,742,470 2,966,948
M.A. McFarland EVP-EFH Corp. & President & Chief Executive of Luminant	2015 2014 2013	700,000 675,000 675,000	— — —	— — 140,000	2,091,292 1,983,766 2,028,160	— — —	37,492 46,157 46,367	2,828,784 2,704,923 2,889,527
Stacey H. Doré EVP, General Counsel, & Co-CRO of EFH Corp.	2015 2014 2013	650,000 600,000 600,000	— — 350,000	— — 70,000	2,095,699 1,970,132 1,788,533	— — —	40,250 131,235 32,654	2,785,949 2,701,367 2,841,187

___________

(1) The amounts reported in this column represent discretionary cash bonuses that the relevant executive officer earned for the fiscal year listed.

(2) The amounts reported as "Stock Awards" represent the grant date fair value (as computed in accordance with FASB ASC Topic 718) of certain restricted stock units that were granted to our Named Executive Officers. Although these restricted stock units vested in September 2014, these awards have not been settled. Under the Plan of Reorganization and upon its effective date, all outstanding restricted stock units, including those reported in this column, will be cancelled and released without any distribution or payment to the Named Executive Officers.

(3) The amounts for 2015 reported as "Non-Equity Incentive Plan Compensation" were earned by the executive officers in 2015 under the EAIP and the Annual Supplemental Awards. The amounts reported for 2015 for each Named Executive Officer are as follows: (a) for Mr. Young, $3,166,501 for the EAIP and $2,700,000 for the Annual Supplemental Award; (b) for Mr. Keglevic $1,323,267 for the EAIP and $1,000,000 for the Annual Supplemental Award; (c) for Mr. Burke $1,190,000 for the EAIP and $1,000,000 for the Annual Supplemental Award; (d) for Mr. McFarland $1,091,292 for the EAIP and $1,000,000 for the Annual Supplemental Award; and (e) for Ms. Doré $1,095,699 for the EAIP and $1,000,000 for the Annual Supplemental Award.

(4) The amount for Mr. Burke in 2015 reported under "Change in Pension Value and Nonqualified Deferred Compensation Earnings" was zero because by rule, the Change in Pension Value cannot be less than zero. The actuarial value of his balance in the EFH Supplemental Retirement Plan decreased by $28,000 year over year. For a more detailed description of the Supplemental Retirement Plan, please refer to the narrative that follows the table entitled "Pension Benefits - 2015."

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(5) The amounts for 2015 reported as "All Other Compensation" are attributable to the Named Executive Officer's receipt of compensation as described in the following table:

	All Other Compensation ($)(a)
Name	Matching Contribution to Thrift Plan(b)	Cost of Letter of Credit(c)	Premium Payments on Life Insurance Policy	Personal Physical Care(d)	Financial Planning(e)	Country Club Dues(f)	Executive Physical(g)	Spousal Travel(h)	Security Services	Total
John F. Young	15,900	1,884	17,185	9,350	11,375	9,730	—	—	416	65,840
Paul M. Keglevic	15,900	698	—	15,000	—	10,289	—	8,989	—	50,876
James A. Burke	15,900	698	—	—	9,975	—	2,718	418	—	29,709
Mark A. McFarland	15,900	698	—	—	1,960	16,235	2,699	—	—	37,492
Stacey H. Doré	15,900	302	—	—	9,975	10,684	3,389	—	—	40,250

___________

(a) For purposes of preparing this table, all perquisites are valued on the basis of the actual cost to EFH Corp.

(b) Our Thrift Plan allows participating employees to contribute a portion of their regular salary or wages to the plan. Under the EFH Thrift Plan, EFH Corp. matches a portion of an employee's contributions. This matching contribution is 100% of each Named Executive Officer's contribution up to 6% of the named Executive Officer's salary up to the annual IRS compensation limit. All matching contributions are invested in Thrift Plan investments as directed by the participant.

(c) In connection with the grant of certain prior year long-term incentive awards, and in consideration of the retention incentive that such award provided to our Named Executive Officers, the O&C Committee had previously approved the provision of irrevocable standby letters of credit to each Named Executive Officer. Our Named Executive Officers were entitled to draw under these letters of credit to receive payment of compensation earned by them under these awards. In March 2015, each Named Executive Officer drew down on his or her letter of credit. The letters of credit expired in April 2015.

(d) The amounts received by Mr. Young and Mr. Keglevic include the annual fee to participate in a comprehensive health plan that provides anytime personal and private physician access and health care and includes the cost of an annual physical. For a discussion of the Personal Physical Care received by certain of our Named Executive Officers, please see "Compensation Discussion and Analysis - Other Elements of Compensation - Perquisites - Health Services."

(e) For a discussion of the Financial Planning received by certain of our Named Executive Officers, please see "Compensation Discussion and Analysis - Other Elements of Compensation - Perquisites - Executive Financial Planning."

(f) The amounts received by Mr. McFarland for the costs of a country club membership include a pro-rated portion of the initiation fee.

(g) The amounts received by Mr. Burke, Mr. McFarland and Ms. Doré include expenses related to medical examinations.

(h) The amounts received by Mr. Keglevic and Mr. Burke include taxable spousal travel expenses.

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Grants of Plan-Based Awards – 2015

The following table sets forth information regarding grants of compensatory awards to our Named Executive Officers for the fiscal year ended December 31, 2015.

		Estimated Possible Payouts Under Non-Equity Incentive Plan Awards
Name	Approval Date	Threshold ($)	Target ($)	Maximum ($)
John F. Young	10/29/14(1)	—	1,687,500	3,375,000
	11/20/14(2)	1,350,000	2,700,000
Paul M. Keglevic	10/29/14(1)	—	667,250	1,334,500
	11/20/14(2)	500,000	1,000,000
James A. Burke	10/29/14(1)	—	595,000	1,190,000
	11/20/14(2)	500,000	1,000,000
Stacey H. Doré	10/29/14(1)	—	552,500	1,105,000
	11/20/14(2)	500,000	1,000,000
M.A. McFarland	10/29/14(1)	—	595,000	1,190,000
	11/20/14(2)	500,000	1,000,000

___________

(1) Represents the target and maximum amounts available under the EAIP for 2015 for each Named Executive Officer. Each payment is reported in the Summary Compensation Table in the year earned under the heading "Non-Equity Incentive Plan Compensation," and is described above under the section entitled "Annual Performance-Based Cash Bonus - Executive Officer Annual Incentive Plan".

(2) Represents the threshold and target amounts available under the Annual Supplemental Award for 2015 for each Named Executive Officer. Each payment is reported in the Summary Compensation Table in the year earned under the heading "Non-Equity Incentive Plan Compensation," and is described above under the section entitled "Supplemental Incentive Awards."

For a discussion of certain material terms of the employment agreements with the Named Executive Officers, please see "Assessment of Compensation Elements" and "Potential Payments upon Termination or Change in Control."

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Pension Benefits – 2015

The table set forth below illustrates the present value on December 31, 2015 of Mr. Burke's benefits payable under the Supplemental Retirement Plan, based on his years of service and remuneration through December 31, 2015:

Name	Plan Name	Number of Years Credited Service (#)	PV of Accumulated Benefit ($)	Payments During Last Fiscal Year ($)
James A. Burke	Supplemental Retirement Plan	6.9167	219,662	—

The Supplemental Retirement Plan provides for the payment of retirement benefits, which would have otherwise been limited by the Code or the definition of earnings under our former retirement plan, which was terminated through a series of transactions in 2012 for those employees who were not members of a collective bargaining unit. The benefits under the Supplemental Retirement Plan were frozen in September 2012 in connection with the termination of our former retirement plan. Participation in EFH Corp.'s Supplemental Retirement Plan was limited to employees of all of its businesses other than Oncor, who were employed by EFH Corp. (or its participating subsidiaries) on or before October 1, 2007. As a result, Mr. Burke is the only Named Executive Officer that participated in the Supplemental Retirement Plan. In connection with the freezing of benefits under the Supplemental Retirement Plan in 2012, additional contributions under the Supplemental Retirement Plan ceased; however, if the transactions contemplated by the Plan of Reorganization are consummated, the amounts existing under the Supplemental Retirement Plan will be paid out in accordance with the terms of the Plan of Reorganization.

Benefits accrued under the Supplemental Retirement Plan after December 31, 2004, are subject to Section 409A of the Code. Accordingly, certain provisions of the Supplemental Retirement Plan have been modified in order to comply with the requirements of Section 409A and related guidance.

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Nonqualified Deferred Compensation – 2015

The following table sets forth information regarding certain plans of EFH Corp. that provide for the deferral of the Named Executive Officers' compensation on a basis that is not tax-qualified for the fiscal year ended December 31, 2015:

Name	Aggregate Earnings/Losses in Last FY ($)(1)		Aggregate Withdrawals/ Distributions ($)(2)		Aggregate Balance at Last FYE ($)(3)
John F. Young	532		(5,400,000	)	280,027
Paul M. Keglevic	—		(2,000,000	)
James A. Burke	(5,701	)	(2,000,000	)	170,094
Stacey H. Doré	—		(1,466,667	)
M.A. McFarland	—		(2,000,000	)

___________

(1) The amounts reported as "Aggregate Earnings/Losses in Last FY" include earnings and losses on deferrals previously made under the EFH Corp. Salary Deferral Program. Deferrals are credited with earnings or losses based on the performance of investment alternatives under the Salary Deferral Program selected by each participant. At the end of the applicable maturity period, the trustee for the Salary Deferral Program distributes the deferred compensation and the applicable earnings in cash as a lump sum or in annual installments at the participant's election made at the time of deferral. Since 2010, the Named Executive Officers have not been eligible to defer additional compensation in the Salary Deferral Program. As of December 31, 2015, Messrs. Young and Burke had balances in the Salary Deferral Program.

(2) The amounts reported as "Aggregate Withdrawals/Distributions" for Messrs. Young, Keglevic, Burke and McFarland and Ms. Doré represent amounts paid in 2015 for long-term cash incentive awards that had been earned in 2013 and 2014 and reported in previous years on the Summary Compensation Table for each executive.

(3) The amounts reported for Messrs. Young and Burke include any amounts deferred under the Salary Deferral Plan, plus any earnings or losses thereon. If the transactions contemplated by the Plan of Reorganization are consummated, all amounts due under the Salary Deferral Plan will be distributed according to the terms of the Plan of Reorganization. For Mr. Burke, this also includes the fair market value of 443,474 deferred shares of EFH Corp. that he is entitled to receive on the earlier to occur of the termination of employment or a change of control of EFH Corp. However, given the Bankruptcy Filing and the terms of the Plan of Reorganization, we deem our common stock to have de minimis value. Under the Plan of Reorganization and upon its effective date, all EFH Corp. stock will be cancelled and released without any distribution or payment.

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Potential Payments upon Termination or Change in Control

The tables and narrative below provide information for payments to each of the Named Executive Officers (or, as applicable, enhancements to payments or benefits) in the event of his or her termination, including if such termination is voluntary, for cause, as a result of death, as a result of disability, without cause or for good reason or in connection with a change in control.

The information in the tables below is presented assuming termination of employment as of December 31, 2015.

Employment Arrangements with Contingent Payments

As of December 31, 2015, each ofMessrs. Young, Keglevic, Burke and McFarland and Ms. Doré had employment agreements with change in control and severance provisions. Under the Plan of Reorganization, upon the effectiveness of such plan, each of these employment agreements will be assumed by Reorganized TCEH.

With respect to each Named Executive Officer's employment agreement, a change in control is generally defined as (i) a transaction that results in a sale of substantially all of our assets or capital stock to another person who is not an affiliate of any member of the Sponsor Group and such person having more seats on our Board than the Sponsor Group, (ii) a transaction that results in a person not in the Sponsor Group owning more than 50% of our common stock and such person having more seats on our Board than the Sponsor Group or (iii) a transaction that results in the Sponsor Group owning less than 20% of our common stock and the Sponsor Group not being able to appoint a majority of the directors to our Board. Under the terms of the Plan of Reorganization, the effectiveness of the Plan of Reorganization will be considered a “change in control” under the employment agreements of the Named Executive Officers.

Each Named Executive Officer's employment agreement includes customary non-compete and non-solicitation provisions that generally restrict the Named Executive Officer's ability to compete with us or solicit our customers or employees for his or her own personal benefit during the term of the employment agreement and 24 months (with respect to Mr. Young) or 18 months (with respect to Messrs. Keglevic, Burke and McFarland and Ms. Doré) after the employment agreement expires or is terminated.

Each of our Named Executive Officers has been granted an Annual Supplemental Award, as more fully described above in "Supplemental Incentive Awards." In the event of such Named Executive Officer's termination without cause, resignation for good reason, termination due to death or disability, or termination upon a change in control, the Annual Supplemental Award becomes payable, to the extent earned, on a pro-rated basis.

The following tables describe payments to which each Named Executive Officer is entitled under his or her employment agreement; however, some of the payments may not have been permitted to be paid at December 31, 2015 due to the Bankruptcy Filing.

Excise Tax Gross-Ups

Pursuant to their employment agreements, if any of our Named Executive Officers is subject to the imposition of the excise tax imposed by Section 4999 of the Code, related to the executive's employment, but the imposition of such tax could be avoided by approval of our shareholders as described in Section 280G(b)(5)(B) of the Code, then such executive may cause EFH Corp. to seek such approval, in which case EFH Corp. will use its reasonable best efforts to cause such approval to be obtained and such executive will cooperate and execute such waivers as may be necessary so that such approval avoids imposition of any excise tax under Section 4999. If such executive fails to cause EFH Corp. to seek such approval or fails to cooperate and execute the waivers necessary in the approval process, such executive shall not be entitled to any gross-up payment for any resulting tax under Section 4999. Because we believe the shareholder approval exception to such excise tax will apply, the tables below do not reflect any amounts for such gross-up payments. Because we believe no such excise tax will apply under the terms of the Plan of Reorganization and because the shareholder approval exception to such excise tax would apply if relevant, the tables below do not reflect any amounts for such gross-up payments.

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1. Mr. Young

Potential Payments to Mr. Young upon Termination as of December 31, 2015 (per employment agreement in effect as of December 31, 2015)

Benefit	Voluntary ($)	For Cause ($)	Death ($)	Disability ($)	Without Cause Or For Good Reason ($)	Without Cause Or For Good Reason In Connection With Change in Control ($)
Cash Severance	—	—	—	—	5,737,500	9,112,500
Supplemental Retirement Benefit	3,000,000	3,000,000	3,000,000	3,000,000	3,000,000	3,000,000
EAIP(1)	2,183,794	2,183,794	2,183,794	2,183,794	—	—
Annual Supplemental Award	1,437,480	1,437,480	1,437,480	1,437,480	1,437,480	1,437,480
Health & Welfare:
- Medical/COBRA	—	—	—	—	37,633	37,633
- Dental/COBRA	—	—	—	—	2,638	2,638
Totals	6,621,274	6,621,274	6,621,274	6,621,274	10,215,251	13,590,251

____________

(1) Calculated as target award multiplied by company performance

Mr. Young has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Young's voluntary resignation without good reason or termination for cause:

a. accrued but unpaid base salary and unused vacation earned through the date of termination;

b. accrued but unpaid annual bonus earned under the EAIP for the previously completed year;

c. accrued but unpaid portion of the Annual Supplemental Award for the immediately preceding performance period;

d. value of supplemental retirement benefit for Mr. Young;

e. unreimbursed business expenses; and

f. payment of employee benefits to which Mr. Young may be entitled (collectively (a) - (f), the Accrued Rights).

2. In the event of Mr. Young's death or disability:

a. the Accrued Rights; and

b. a prorated annual bonus earned under the EAIP for the year of termination.

3. In the event of Mr. Young's termination without cause or resignation for good reason:

a. the Accrued Rights;

b. a lump sum payment equal to (i) three times his annualized base salary and (ii) a prorated annual bonus earned under the EAIP for the year of termination; and

c. certain continuing health care and company benefits.

4. In the event of Mr. Young's termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. the Accrued Rights;

b. a lump sum payment equal to three times the sum of (i) his annualized base salary and (ii) his annual bonus target under the EAIP; and

c. certain continuing health care and company benefits.

175

2. Mr. Keglevic

Potential Payments to Mr. Keglevic upon Termination as of December 31, 2015 (per employment agreement in effect as of December 31, 2015)

Benefit	Voluntary ($)	For Cause ($)	Death ($)	Disability ($)	Without Cause Or For Good Reason ($)	Without Cause Or For Good Reason In Connection With Change in Control ($)
Cash Severance	—	—	—	—	2,237,250	2,904,500
EAIP(1)	912,598	912,598	912,598	912,598	—	—
Annual Supplemental Award	538,000	538,000	538,000	538,000	538,000	538,000
Health & Welfare
- Dental/COBRA	—	—	—	—	2,110	2,110
Totals	1,450,598	1,450,598	1,450,598	1,450,598	2,777,360	3,444,610

____________

(1) Calculated as target award multiplied by company performance

Mr. Keglevic has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Keglevic's voluntary resignation without good reason or termination for cause:

a. accrued but unpaid base salary and unused vacation earned through the date of termination;

b. accrued but unpaid annual bonus earned under the EAIP for the previously completed year;

c. accrued but unpaid portion of the Annual Supplemental Award for the immediately preceding performance period;

d. unreimbursed business expenses; and

e. payment of employee benefits to which Mr. Keglevic may be entitled (collectively (a) - (e), the Accrued Rights).

2. In the event of Mr. Keglevic's death or disability:

a. the Accrued Rights; and

b. a prorated annual bonus earned under the EAIP for the year of termination.

3. In the event of Mr. Keglevic's termination without cause or resignation for good reason:

a. the Accrued Rights;

b. a lump sum payment equal to (i) two times his annualized base salary and (ii) a prorated annual bonus earned under the EAIP for the year of termination; and

c. certain continuing health care and company benefits.

4. In the event of Mr. Keglevic's termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. the Accrued Rights;

b. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target under the EAIP; and

c. certain continuing health care and company benefits.

176

3. Mr. Burke

Potential Payments to Mr. Burke upon Termination as of December 31, 2015 (per employment agreement, in effect as of December 31, 2015)

Benefit	Voluntary ($)	For Cause ($)	Death ($)	Disability ($)	Without Cause Or For Good Reason ($)	Without Cause Or For Good Reason In Connection With Change in Control ($)
Cash Severance	—	—	—	—	1,995,000	2,590,000
EAIP(1)	909,577	909,577	909,577	909,577	—	—
Annual Supplemental Award	538,000	538,000	538,000	538,000	538,000	538,000
Health & Welfare
- Medical/COBRA	—	—	—	—	39,873	39,873
- Dental/COBRA	—	—	—	—	2,110	2,110
Totals	1,447,577	1,447,577	1,447,577	1,447,577	2,574,983	3,169,983

____________

(1) Calculated as target award multiplied by company performance

Mr. Burke has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances.

1. In the event of Mr. Burke's voluntary resignation without good reason or termination for cause:

a. accrued but unpaid base salary and unused vacation earned through the date of termination;

b. accrued but unpaid annual bonus earned under the EAIP for the previously completed year;

c. accrued but unpaid portion of the Annual Supplemental Award for the immediately preceding performance period;

d. unreimbursed business expenses; and

e. payment of employee benefits to which Mr. Burke may be entitled (collectively, (a) - (e), the Accrued Rights).

2. In the event of Mr. Burke's death or disability:

a. the Accrued Rights; and

b. a prorated annual bonus earned under the EAIP for the year of termination.

3. In the event of Mr. Burke's termination without cause or resignation for good reason:

a. the Accrued Rights;

b. a lump sum payment equal to (i) two times his annualized base salary and (ii) a prorated annual bonus earned under the EAIP for the year of termination; and

c. certain continuing health care and company benefits.

4. In the event of Mr. Burke's termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. the Accrued Rights;

b. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target under the EAIP; and

c. certain continuing health care and company benefits.

177

4. Mr. McFarland

Potential Payments to Mr. McFarland upon Termination as of December 31, 2015 (per employment agreement in effect as of December 31, 2015)

Benefit	Voluntary ($)	For Cause ($)	Death ($)	Disability ($)	Without Cause Or For Good Reason ($)	Without Cause Or For Good Reason In Connection With Change in Control ($)
Cash Severance	—	—	—	—	1,995,000	2,590,000
EAIP(1)	752,616	752,616	752,616	752,616	—	—
Annual Supplemental Awards	538,000	538,000	538,000	538,000	538,000	538,000
Health & Welfare
- Medical/COBRA	—	—	—	—	39,873	39,873
- Dental/COBRA	—	—	—	—	2,110	2,110
Totals	1,290,616	1,290,616	1,290,616	1,290,616	2,574,983	3,169,983

____________

(1) Calculated as target award multiplied by company performance

Mr. McFarland entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. McFarland's voluntary resignation without good reason or termination for cause:

a. accrued but unpaid base salary and unused vacation earned through the date of termination;

b. accrued but unpaid annual bonus earned under the EAIP for the previously completed year;

c. accrued but unpaid portion of the Annual Supplemental Award for the immediately preceding performance period;

d. unreimbursed business expenses; and

e. payment of employee benefits to which Mr. McFarland may be entitled (collectively, (a) - (e), the Accrued Rights).

2. In the event of Mr. McFarland's death or disability:

a. the Accrued Rights; and

b. a prorated annual bonus earned under the EAIP for the year of termination.

3. In the event of Mr. McFarland's termination without cause or resignation for good reason:

a. the Accrued Rights;

b. a lump sum payment equal to (i) two times his annualized base salary and (ii) a prorated annual bonus under the EAIP for the year of termination; and

c. certain continuing health care and company benefits.

4. In the event of Mr. McFarland's termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. the Accrued Rights;

b. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target under the EAIP; and

c. certain continuing health care and company benefits.

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5. Ms. Doré

Potential Payments to Ms. Doré upon Termination as of December 31, 2015 (per employment agreement in effect as of December 31, 2015)

Benefit	Voluntary ($)	For Cause ($)	Death ($)	Disability ($)	Without Cause Or For Good Reason ($)	Without Cause Or For Good Reason In Connection With Change in Control ($)
Cash Severance	—	—	—	—	1,852,500	2,405,000
EAIP(1)	755,654	755,654	755,654	755,654	—	—
Annual Supplemental Award	538,000	538,000	538,000	538,000	538,000	538,000
Health & Welfare
- Medical/COBRA	—	—	—	—	39,873	39,873
- Dental/COBRA	—	—	—	—	2,110	2,110
Totals	1,293,654	1,293,654	1,293,654	1,293,654	2,432,483	2,984,983

____________

(1) Calculated as target award multiplied by company performance

Ms. Doré has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances.

1. In the event of Ms. Doré's voluntary resignation without good reason or termination for cause:

a. accrued but unpaid base salary and unused vacation earned through the date of termination;

b. accrued but unpaid annual bonus earned under the EAIP for the previously completed year;

c. accrued but unpaid portion of the Annual Supplemental Award for the immediately preceding performance period;

d. unreimbursed business expenses; and

e. payment of employee benefits to which Ms. Doré may be entitled (collectively, (a) - (e), the Accrued Rights).

2. In the event of Ms. Doré's death or disability:

a. the Accrued Rights; and

b. a prorated annual bonus earned under the EAIP for the year of termination.

3. In the event of Ms. Doré's termination without cause or resignation for good reason:

a. the Accrued Rights;

b. a lump sum payment equal to (i) two times her annualized base salary and (ii) a prorated annual bonus earned under the EAIP for the year of termination; and

c. certain continuing health care and company benefits.

4. In the event of Ms. Doré's termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. the Accrued Rights;

b. a lump sum payment equal to two times the sum of (i) her annualized base salary and (ii) her annual bonus target under the EAIP; and

c. certain continuing health care and company benefits.

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Compensation Committee Interlocks and Insider Participation

There are no relationships among our executive officers, members of the O&C Committee or entities whose executives served on the O&C Committee that required disclosure under applicable SEC rules and regulations. For a description of related person transactions involving members of the O&C Committee, see Item 13, entitled "Related Person Transactions."

Director Compensation

The table below sets forth information regarding the aggregate compensation earned by or paid to the members of the Board during the year ended December 31, 2015. Directors who are officers of EFH Corp. (other than our Executive Chairman or members of the Sponsor Group (or their respective affiliates)) do not receive any fees for service as a director. EFH Corp. reimburses directors for reasonable expenses incurred in connection with their services as directors. In March 2014, given the then likely bankruptcy filing, the Board terminated its annual equity grant program for non-employee and non-Sponsor directors.

Name	Fees Earned or Paid in Cash ($)	All Other Compensation ($)	Total ($)
Arcilia C. Acosta (1)(2)	251,000	—	251,000
David Bonderman	—	—	—
Donald L. Evans (3)	—	2,600,000	2,600,000
Thomas D. Ferguson	—	—	—
Brandon Freiman	—	—	—
Scott Lebovitz	—	—	—
Michael MacDougall	—	—	—
Kenneth Pontarelli	—	—	—
William K. Reilly (1)(2)	232,000	—	232,000
Jonathan D. Smidt	—	—	—
Billie I. Williamson (1)(4)	586,250		586,250
John F. Young	—	—	—
Kneeland Youngblood (1)(2)	248,000	—	248,000

______________

(1) Members of our Board who are not officers of EFH Corp., members of the Sponsor Group or the Executive Chairman, receive an annual retainer of $200,000.

(2) In July 2015, the EFH Corp. Board approved Special Meeting Fees be paid to Ms. Acosta, Mr. Reilly and Mr. Youngblood retroactive to January 1, 2015. Special Meeting Fees are $1,000 per meeting (capped at $75,000 per year per director) attended by Ms. Acosta, Mr. Reilly and Mr. Youngblood for meetings that are not those held in the normal course to support standard business operations.

(3) In April 2014, we entered into an Amended and Restated Employment Agreement with Mr. Evans, pursuant to which Mr. Evans receives an annual base salary of $2,500,000 for his service as Executive Chairman of the Board. Under the terms of the agreement, Mr. Evans also receives a payment by EFH Corp. of (a) $100,000 annually for office expenses and administrative support, (b) up to $200,000 annually in salary payments to a chief of staff, and (c) executive assistant services in Dallas and Midland, Texas. At December 31, 2015, Mr. Evans had 5,000,000 vested options to purchase common shares of EFH Corp for $0.50 per share. However, under the Plan of Reorganization and upon its effective date, all EFH Corp. options will be cancelled and released without any distribution or payment.

(4) In recognition of the additional responsibilities Ms. Williamson has been performing, and will continue to perform, in connection with our Chapter 11 Cases and as a disinterested director of EFH Corp., in February 2015, we agreed to pay her an additional $7,500 for each day substantially spent on matters related to our restructuring.

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Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table presents information concerning stock-based compensation plans as of December 31, 2015.

	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights(1)	(b) Weighted-average exercise price of outstanding options, warrants and rights(2)		(c) Number of securities remaining available for future issuance under equity compensation plans, excluding securities reflected in column (a)
Equity compensation plans approved by security holders	—	$	—	—
Equity compensation plans not approved by security holders	36,314,292	$	1.85	31,997,449
Total	36,314,292	$	1.85	31,997,449

____________

(1) Includes 19.6 million restricted stock units issued in exchange for previously issued stock options.

(2) The weighted average exercise price does not take into account the shares subject to outstanding restricted stock units which have no exercise price.

Under the terms of the Plan of Reorganization, the right to receive common stock of EFH Corp. under the restricted stock units described above will be cancelled and not be paid by EFH Corp.

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Beneficial Ownership of Common Stock of Energy Future Holdings Corp.

The following table lists the number of shares of common stock of EFH Corp. beneficially owned by each director and certain executive officers of EFH Corp. and the holders of more than 5% of EFH Corp.'s common stock as of February 1, 2016. Under the terms of the Plan of Reorganization, all of the shares of common stock set forth in the table below will be cancelled.

The amounts and percentages of shares of common stock of EFH Corp. beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under SEC rules, a person is deemed to be a "beneficial owner" of a security if that person has or shares voting power or investment power, which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person's ownership percentage, but not for purposes of computing any other person's percentage. Under these rules, more than one person may be deemed to be a beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest.

Name	Number of Shares Beneficially Owned	Percent of Class
Texas Holdings (1)(2)(3)(4)	1,657,600,000	98.943	%
Arcilia C. Acosta (6)	486,029	*
David Bonderman (2)	1,657,600,000	98.943	%
Donald L. Evans (7)	5,400,000	*
Thomas D. Ferguson (3)	1,657,600,000	98.943	%
Brandon Freiman (5)	—	—	%
Scott Lebovitz (3)	1,657,600,000	98.943	%
Michael MacDougall (8)	—	—	%
Kenneth Pontarelli (3)	1,657,600,000	98.943	%
William K. Reilly (9)	616,029	*
Jonathan D. Smidt (5)	—	—	%
Billie I. Williamson	250,000	*
John F. Young	1,021,222	*
Kneeland Youngblood (11)	556,029	*
James A. Burke (10)	443,474	*
Stacey H. Doré	—	*
Paul M. Keglevic	—	*
M. A. McFarland	—	*
All owners, directors and current executive officers as a group (18 persons)	1,666,372,783	98.943	%

___________

* Less than 1%.

(1) Texas Holdings beneficially owns 1,657,600,000 shares of EFH Corp. The sole general partner of Texas Holdings is Texas Energy Future Capital Holdings LLC ("Texas Capital"), which, pursuant to the Amended and Restated Limited Partnership Agreement of Texas Holdings, has the right to vote all of the EFH Corp. shares owned by Texas Holdings. The TPG Funds, the Goldman Entities and the KKR Entities (each as defined below, and collectively, the "Texas Capital Funds") collectively own 91.08% of the outstanding units of Texas Capital. The Texas Capital Funds exercise control over Texas Capital, and each has the right to designate and remove the managers of Texas Capital appointed by such Texas Capital Fund. Because of these relationships, each of the Texas Capital Funds may be deemed to have beneficial ownership of the shares of EFH Corp. held by Texas Holdings, but each disclaims beneficial ownership of such shares. The address of both Texas Holdings and Texas Capital is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

182

(2) The TPG Funds (as defined below) beneficially own 302,923,439.752 units of Texas Capital, representing 27.01% of the outstanding units, including (i) 271,639,218.931 units held by TPG Partners V, L.P., a Delaware limited partnership ("TPG Partners V"), whose general partner is TPG GenPar V, L.P., a Delaware limited partnership ("TPG GenPar V"), whose general partner is TPG GenPar V Advisors, LLC, a Delaware limited liability company, whose sole member is TPG Holdings I, L.P., a Delaware limited partnership ("TPG Holdings"), (ii) 29,999,994.650 units held by TPG Partners IV, L.P., a Delaware limited partnership ("TPG Partners IV"), whose general partner is TPG GenPar IV, L.P., a Delaware limited partnership, whose general partner is TPG GenPar IV Advisors, LLC, a Delaware limited liability company, whose sole member is TPG Holdings, (iii) 710,942.673 units held by TPG FOF V-A, L.P., a Delaware limited partnership (“TPG FOF A”), whose general partner is TPG GenPar V and (iv) 573,283.498 units held by TPG FOF V-B, L.P., a Delaware limited partnership ("TPG FOF B" and, together with TPG Partners V, TPG Partners IV and TPG FOF A, the "TPG Funds"), whose general partner is TPG GenPar V. The general partner of TPG Holdings is TPG Holdings I-A, LLC, a Delaware limited liability company, whose sole member is TPG Group Holdings (SBS), L.P., a Delaware limited partnership, whose general partner is TPG Group Holdings (SBS) Advisors, Inc., a Delaware corporation ("Group Advisors"). David Bonderman and James G. Coulter are officers and sole shareholders of Group Advisors and may therefore be deemed to beneficially own the units held by the TPG Funds. David Bonderman is also a manager of Texas Capital. Messrs. Bonderman and Coulter disclaim beneficial ownership of the shares of EFH Corp. held by Texas Holdings except to the extent of their pecuniary interest therein. The address of Group Advisors and Messrs. Bonderman and Coulter is c/o TPG Global, LLC, 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

(3) GS Capital Partners VI Fund, L.P., GSCP VI Offshore TXU Holdings, L.P., GSCP VI Germany TXU Holdings, L.P., GS Capital Partners VI Parallel, L.P., GS Global Infrastructure Partners I, L.P., GS Infrastructure Offshore TXU Holdings, L.P. (GSIP International Fund), GS Institutional Infrastructure Partners I, L.P., Goldman Sachs TXU Investors L.P. and Goldman Sachs TXU Investors Offshore Holdings, L.P. (collectively, the "Goldman Entities") beneficially own 303,049,945.955 units of Texas Capital, representing 27.02% of the outstanding units. Affiliates of The Goldman Sachs Group, Inc. ("Goldman Sachs") are the general partner, managing general partner or investment manager of each of the Goldman Entities, and each of the Goldman Entities shares voting and investment power with certain of their respective affiliates. Each of Goldman Sachs and the Goldman Entities disclaims beneficial ownership of such shares of common stock except to the extent of its pecuniary interest therein. Messrs. Ferguson, Lebovitz and Pontarelli are managers of Texas Capital and executives with affiliates of Goldman Sachs. By virtue of their position in relation to Texas Capital and the Goldman Entities, Messrs. Ferguson, Lebovitz and Pontarelli may be deemed to have beneficial ownership with respect to the units of Texas Capital held by the Goldman Entities. Each of Messrs. Ferguson, Lebovitz and Pontarelli disclaims beneficial ownership of the shares of EFH Corp. held by Texas Holdings except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Goldman, Sachs & Co., 200 West Street, New York, New York 10282.

(4) KKR 2006 Fund L.P., KKR PEI Investments, L.P., KKR Partners III, L.P., KKR North American Co-Invest Fund I L.P., KKR Reference Fund Investments L.P. and TEF TFO Co-Invest, LP (collectively, the "KKR Entities") beneficially own 415,473,419.680 units of Texas Capital, representing 37.05% of the outstanding units. The KKR Entities disclaim beneficial ownership of any shares of our common stock in which they do not have a pecuniary interest. KKR & Co. L.P., as the holding company of affiliates that directly or indirectly control the KKR Entities, other than KKR Partners III, LP., may be deemed to share voting and dispositive power with respect to the shares beneficially owned by such KKR Entities, but disclaims beneficial ownership of such shares except to the extent of its pecuniary interest in those shares. As the designated members of KKR Management LLC (which is the general partner of KKR & Co. L.P.) and the managing members of KKR III GP LLC (which is the general partner of KKR Partners III, L.P.), Henry R. Kravis and George R. Roberts may be deemed to share voting and dispositive power with respect to the shares beneficially owned by the KKR Entities but disclaim beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, New York 10019.

(5) Messrs. Freiman and Smidt are managers of Texas Capital and executives of Kohlberg Kravis Roberts & Co. L.P. and/or one or more of its affiliates. Neither Mr. Freiman or Mr. Smidt have voting or investment power over and each disclaim beneficial ownership of the units held by the KKR Entities and the shares of EFH Corp. held by Texas Holdings, except in each case to the extent of their pecuniary interest. The address of each individual listed in this footnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, New York 10019.

(6) 70,000 shares held in a family limited partnership, ACA Family LP.

(7) Includes 5,000,000 shares issuable upon exercise of vested options.

(8) Michael MacDougall is a TPG partner. Mr. MacDougall is a manager of Texas Capital. Mr. MacDougall does not have voting or investment power over and disclaims beneficial ownership of the units of Texas Capital held by the TPG Funds and the shares of EFH Corp. held by Texas Holdings. The address of Mr. MacDougall is c/o TPG Global, LLC, 301 Commerce Street, Suite 3300, Fort Worth, TX 76102.

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(9) William K. Reilly is a TPG senior advisor. Mr. Reilly does not have voting or investment power over and disclaims beneficial ownership of the units of Texas Capital held by the TPG Funds. The address of Mr. Reilly is c/o TPG Global, LLC, 301 Commerce Street, Suite 3300, Fort Worth, TX 76102.

(10) These are vested deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp.

(11) 100,000 shares held in a limited partnership, Burton Hills Limited, LP.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Policies and Procedures Relating to Related Party Transactions

The Board has adopted a related person transactions policy. Under this policy, a related person transaction shall be consummated or shall continue only if:

1. the Audit Committee of the Board approves or ratifies such transaction in accordance with the policy and determines that the transaction is on terms comparable to those that could be obtained in arm's length dealings with an unrelated third party;

2. the transaction is approved by the disinterested members of the Board or the Executive Committee; or

3. the transaction involves compensation approved by the Organization and Compensation Committee of the Board.

For purposes of this policy, the term "related person" includes EFH Corp.'s directors, executive officers, 5% shareholders and their immediate family members. "Immediate family members" means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law or any person (other than a tenant or employee) sharing the household of a director, executive officer or 5% shareholder.

A "related person transaction" is a transaction between EFH Corp. or its subsidiaries and a related person, other than the types of transactions described below, which are deemed to be pre-approved by the Audit Committee of the Board:

1. any compensation paid to a director if the compensation is required to be reported under Item 402 of Regulation S-K of the Securities Act;

2. any transaction with another company at which a related person's only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company's ownership interests;

3. any charitable contribution, grant or endowment by EFH Corp. to a charitable organization, foundation or university at which a related person's only relationship is as an employee (other than an executive officer) or director;

4. transactions where the related person's interest arises solely from the ownership of EFH Corp.'s equity securities and all holders of that class of equity securities received the same benefit on a pro rata basis;

5. transactions involving a related party where the rates or charges involved are determined by competitive bids;

6. any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, as rates or charges fixed in conformity with law or governmental authority;

7. any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar service;

8. transactions available to all employees or customers generally (unless required to be disclosed under Item 404 of Regulation S-K of the Securities Act, if applicable);

9. transactions involving less than $100,000 when aggregated with all similar transactions;

10. transactions between EFH Corp. and its subsidiaries or between subsidiaries of EFH Corp.;

11. transactions not required to be disclosed under Item 404 of Regulation S-K under the Securities Act of 1933, and

12. open market purchases of EFH Corp.'s or its subsidiaries' debt or equity securities and interest payments on such debt.

The Board has determined that it is appropriate for the Audit Committee of the Board to review and approve or ratify related person transactions. Accordingly, at least annually, management reviews related person transactions to be entered into, or previously entered into, by EFH Corp. or its subsidiaries, if any. After review, the Audit Committee of the Board approves, ratifies or disapproves such transactions. Management updates the Audit Committee of the Board as to any material changes to such related person transactions. In unusual circumstances, EFH Corp. or its subsidiaries may enter into related person transactions in advance of receiving approval, provided that such related person transactions are reviewed as soon as reasonably practicable by the Audit Committee of the Board. If the Audit Committee of the Board determines not to ratify such transactions, EFH Corp. makes all reasonable efforts to cancel or otherwise terminate the affected transactions.

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The related person transactions described below were either approved by the Board or its Executive Committee prior to the Board's adoption of this policy or were approved in accordance with this policy. Transactions described below under "Related Person Transactions - Transactions with Sponsor Affiliates" are not related person transactions under the EFH Corp. policy because they are not with a director, executive officer, 5% shareholder or any of their immediate family members, but are described in the interest of greater disclosure.

Related Person Transactions

Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership; Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC

The Sponsor Group and certain investors who agreed to co-invest with the Sponsor Group or through a vehicle jointly controlled by the Sponsor Group to provide equity financing for the Merger (Co-Investors) entered into (i) a limited partnership agreement (LP Agreement) in respect of EFH Corp.'s parent company, Texas Holdings and (ii) the LLC Agreement in respect of Texas Holdings' sole general partner, Texas Capital. The LP Agreement provides that Texas Capital has the right to vote or execute consents with respect to any shares of EFH Corp.'s common stock owned by Texas Holdings. The LLC Agreement and LP Agreement contain agreements among the parties with respect to the election of EFH Corp.'s directors, restrictions on the issuance or transfer of interests in EFH Corp., including tag-along rights and drag-along rights, and other corporate governance provisions (including the right to approve various corporate actions).

The LLC Agreement provides that Texas Capital and its members will take all action required to ensure that the managers of Texas Capital are also members of EFH Corp.'s Board. Pursuant to the LLC Agreement each of (i) KKR 2006 Fund L.P. and affiliated investment funds, (ii) TPG Partners V, L.P. and affiliated investment funds and (iii) certain funds affiliated with Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners, has the right to designate three managers of Texas Capital. These rights are subject to maintenance of certain investment levels in Texas Holdings.

Registration Rights Agreement

The Sponsor Group and the Co-Investors entered into a registration rights agreement with EFH Corp. upon completion of the Merger. Pursuant to this agreement, in certain circumstances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.'s common stock owned directly or indirectly by them under the Securities Act. In certain circumstances, the Sponsor Group and the Co-Investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.'s common stock under the Securities Act that it may undertake. Ms. Acosta and Messrs. Evans, Reilly and Youngblood, each of whom are members of our Board, and Messrs. Young, Burke, Keglevic, and McFarland, each of whom are executive officers of EFH Corp., are parties to this agreement. This agreement was rejected by EFH Corp. under the Bankruptcy Code in December 2015.

Management Services Agreement

In October 2007, in connection with the Merger, the Sponsor Group and Lehman Brothers Inc. entered into a management agreement with EFH Corp. (Management Agreement), pursuant to which affiliates of the Sponsor Group provide management, consulting, financial and other advisory services to EFH Corp. Pursuant to the Management Agreement, affiliates of the Sponsor Group are entitled to receive an aggregate annual management fee of $35 million, which amount increases 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of EFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties thereto mutually agree to terminate the Management Agreement. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances. Beginning with the quarterly management fee due December 31, 2013, the Sponsor Group, while reserving the right to receive the fees, directed EFH Corp. to suspend payments of the management fees for an indefinite period, and no such management fees were paid to the Sponsor Group in 2015. Pursuant to the Settlement Agreement approved by the Bankruptcy Court in December 2015, the Management Agreement has been terminated and the Sponsor Group has agreed to forego any and all claims under the Management Agreement in exchange for releases of alleged liabilities against the Debtors.

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Indemnification Agreement

Concurrently with entering into the Management Agreement, the Sponsor Group, Texas Holdings and EFH Corp. entered into an indemnification agreement (Indemnification Agreement), pursuant to which EFH Corp. and Texas Holdings agree to indemnify the Sponsor Group and their affiliates against any claims relating to (i) certain securities and financing transactions relating to the Merger, (ii) the performance of transaction services pursuant to the Management Agreement, (iii) actions or failures to act by EFH Corp., Texas Holdings, Texas Capital or their subsidiaries or affiliates (collectively, Company Group), (iv) service as an officer or director of, or at the request of, any member of the Company Group, and (v) any breach or alleged breach of fiduciary duty as a director or officer of any member of the Company Group. This agreement was rejected by EFH Corp. under the Bankruptcy Code in December 2015.

Sale Participation Agreement

Ms. Acosta and Messrs. Evans, Reilly and Youngblood, each of whom are members of our Board, and Mses. Doré and Kirby and Messrs. Young, Burke, Keglevic, and McFarland, each of whom are executive officers, entered into sale participation agreements with EFH Corp. Pursuant to the terms of these agreements, among other things, shares of EFH Corp.'s common stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Group of shares of EFH Corp.'s common stock held by the Sponsor Group.

Certain Certificate of Formation Provisions

EFH Corp.'s restated certificate of formation contains provisions limiting our directors' obligations in respect of corporate opportunities.

Management Stockholders' Agreement

Subject to a management stockholders' agreement, certain members of management, including EFH Corp.'s directors, executive officers, along with other members of management, elected to invest in EFH Corp. by contributing cash or common stock, or a combination of both, to EFH Corp. prior to or following the Merger and receiving common stock in EFH Corp. in exchange therefore. The management stockholders' agreement creates certain rights and restrictions on these shares of common stock, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.

Director Stockholders' Agreement

Certain members of our Board have entered into a stockholders' agreement with EFH Corp. These stockholders' agreements create certain rights and restrictions on the equity, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.

Business Affiliation

Ms. Acosta, a member of our board and a member of each of our Audit Committee and Organization and Compensation Committee, is the owner, president and chief executive officer of Southwest Testing Laboratories, LLC, also known as STL Engineers. STL Engineers provides geotechnical engineering and construction materials testing services to Oncor. In 2015, Oncor paid STL Engineers approximately $340,000 for its services, which is also the amount of Ms. Acosta’s interest in the transaction. As discussed in Notes 1 and 3 to the Financial Statements, EFH Corp. and Oncor have implemented certain structural and operational ring-fencing measures. As a result of these ring-fencing measures, neither EFH Corp., EFIH nor Ms. Acosta has any influence over Oncor’s selection of suppliers. STL Engineers was selected as a supplier by Oncor in the ordinary course through its established procurement process.

Transactions with Sponsor Affiliates

TCEH has entered into the TCEH Senior Secured Facilities, and Oncor has entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners.

Affiliates of GS Capital Partners have from time to time engaged in commercial and investment banking and financial advisory transactions with EFH Corp. in the normal course of business. Affiliates of Goldman are party to certain commodity and interest rate hedging transactions with EFH Corp. in the normal course of business.

186

From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. or its subsidiaries in open market transactions or through loan syndications.

Members of the Sponsor Group and/or their respective affiliates have from time to time entered into, and may continue to enter into, arrangements with the Company to use our products and services in the ordinary course of their business, which often result in revenues to the Company in excess of $120,000 annually. In addition, the Company has entered into, and may continue to enter into, arrangements with members of the Sponsor Group and/or their respective affiliates to use their products and services in the ordinary course of their business, which often result in revenues to members of the Sponsor Group or their respective affiliates in excess of $120,000 annually.

Director Independence

Though not formally considered by the Board because EFH Corp.'s common stock is not currently registered under the Securities Exchange Act of 1934, as amended, with the SEC or traded on any national securities exchange, based upon the listing standards for issuers of equity securities on the New York Stock Exchange (NYSE), the national securities exchange upon which EFH Corp.'s common stock was traded prior to the Merger, only Mses. Acosta and Williamson and Mr. Youngblood would be considered independent. Because of their relationships with the Sponsor Group or with EFH Corp. directly, none of the other directors would be considered independent under the NYSE listing standards for issuers of equity securities. See "Certain Relationships and Related Party Transactions" and Item 11, "Executive Compensation - Director Compensation." Accordingly, we believe that Ms. Acosta is the only member of the Organization and Compensation Committee who would meet the NYSE's independence requirements for issuers of equity securities. Under the NYSE's audit committee independence requirement for issuers of debt securities, Mses. Acosta and Williamson and Mr. Youngblood, who constitute the Audit Committee, are considered independent.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Deloitte & Touche LLP has been the independent auditor for EFH Corp. and for its Predecessor (TXU Corp.) since its organization in 1996.

The Audit Committee of the EFH Corp. Board of Directors has adopted a policy relating to the engagement of EFH Corp.'s independent auditor. The policy provides that in addition to the audit of the financial statements, related quarterly reviews and other audit services, and providing services necessary to complete SEC filings, EFH Corp.'s independent auditor may be engaged to provide non-audit services as described herein. Prior to engagement, all services to be rendered by the independent auditor must be authorized by the Audit Committee in accordance with preapproval procedures which are defined in the policy. The preapproval procedures require:

1. The annual review and preapproval by the Audit Committee of all anticipated audit and non-audit services; and

2. The quarterly preapproval by the Audit Committee of services, if any, not previously approved and the review of the status of previously approved services.

The Audit Committee may also approve certain ongoing non-audit services not previously approved in the limited circumstances provided for in the SEC rules. All services performed by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (Deloitte & Touche) for EFH Corp. in 2015 were preapproved by the Audit Committee.

The policy defines those non-audit services which EFH Corp.'s independent auditor may also be engaged to provide as follows:

1. Audit-related services, including:

a. due diligence accounting consultations and audits related to mergers, acquisitions and divestitures;

b. employee benefit plan audits;

c. accounting and financial reporting standards consultation;

d. internal control reviews, and

e. attest services, including agreed-upon procedures reports that are not required by statute or regulation.

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2. Tax-related services, including:

a. tax compliance;

b. general tax consultation and planning;

c. tax advice related to mergers, acquisitions, and divestitures, and

d. communications with and request for rulings from tax authorities.

3. Other services, including:

a. process improvement, review and assurance;

b. litigation and rate case assistance;

c. forensic and investigative services, and

d. training services.

The policy prohibits EFH Corp. from engaging its independent auditor to provide:

1. Bookkeeping or other services related to EFH Corp.'s accounting records or financial statements;

2. Financial information systems design and implementation services;

3. Appraisal or valuation services, fairness opinions, or contribution-in-kind reports;

4. Actuarial services;

5. Internal audit outsourcing services;

6. Management or human resource functions;

7. Broker-dealer, investment advisor, or investment banking services;

8. Legal and expert services unrelated to the audit, and

9. Any other service that the Public Company Accounting Oversight Board determines, by regulation, to be impermissible.

In addition, the policy prohibits EFH Corp.'s independent auditor from providing tax or financial planning advice to any officer of EFH Corp.

Compliance with the Audit Committee's policy relating to the engagement of Deloitte & Touche is monitored on behalf of the Audit Committee by EFH Corp.'s chief accounting officer. Reports describing the services provided by Deloitte & Touche and fees for such services are provided to the Audit Committee no less often than quarterly.

For the years ended December 31, 2015 and 2014, fees billed (in US dollars) to EFH Corp. by Deloitte & Touche were as follows:

	2015		2014
Audit Fees. Fees for services necessary to perform the annual audit, review SEC filings, fulfill statutory and other service requirements, provide comfort letters and consents	$	7,002,000	$	7,233,000
Audit-Related Fees. Fees for services including due diligence related to mergers, acquisitions and divestitures, accounting consultations and audits in connection with acquisitions, internal control reviews, attest services that are not required by statute or regulation, and consultation concerning financial accounting and reporting standards	645,000		360,000
Tax Fees. Fees for tax compliance, tax planning, and tax advice related to mergers and acquisitions, divestitures, and communications with and requests for rulings from taxing authorities	25,000		—
All Other Fees. Fees for services including process improvement reviews, forensic accounting reviews, litigation assistance and training services	—		—
Total	$	7,672,000	$	7,593,000

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PART IV.

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Schedule I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

ENERGY FUTURE HOLDINGS CORP. (PARENT), A DEBTOR-IN-POSSESSION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF INCOME (LOSS) (Millions of Dollars)
	Year Ended December 31,
	2015			2014			2013
Selling, general and administrative expenses	$	(58	)	$	(61	)	$	(45	)
Other income	22			—			568
Other deductions	—			(108		)	(646		)
Interest income	3			74			132
Interest expense and related charges	—			(83		)	(411		)
Reorganization items (Note 4)	606			(27		)	—
Loss before income taxes and equity in earnings of unconsolidated subsidiaries	573			(205		)	(402		)
Income tax (expense) benefit	(9		)	60			141
Equity in losses of consolidated subsidiaries (net of tax)	(6,240		)	(6,610		)	(2,399		)
Equity in earnings of unconsolidated subsidiaries (net of tax)	334			349			335
Net loss	(5,342		)	(6,406		)	(2,325		)
Net loss attributable to noncontrolling interests	—			—			107
Net loss attributable to EFH Corp. (parent)	$	(5,342	)	$	(6,406	)	$	(2,218	)

See Notes to the Financial Statements.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Millions of Dollars)
	Year Ended December 31,
	2015			2014			2013
Net loss	$	(5,342	)	$	(6,406	)	$	(2,325	)
Other comprehensive income (loss) (net of tax (expense) benefit of $(2), $36 and $9)	4			(67		)	(16		)
Comprehensive loss	(5,338		)	(6,473		)	(2,341		)
Comprehensive loss attributable to noncontrolling interests	—			—			107
Comprehensive loss attributable to EFH Corp. (parent)	$	(5,338	)	$	(6,473	)	$	(2,234	)

See Notes to the Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. (PARENT), A DEBTOR-IN-POSSESSION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF CASH FLOWS (Millions of Dollars)
	Year Ended December 31,
	2015			2014			2013
Cash flows — operating activities
Net loss	$	(5,342	)	$	(6,406	)	$	(2,325	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Equity in losses of consolidated subsidiaries	6,240			6,610			2,399
Equity in earnings of unconsolidated subsidiaries	(334		)	(349		)	(335		)
Deferred income tax expense (benefit) — net	23			3			10
Gain on settlement of debt held by affiliates (Note 4)	(1,283		)	—			—
Gain on settlement of interest on debt held by affiliates (Note 4)	(35		)	—			—
Adjustment to intercompany claims pursuant to the Settlement Agreement (Note 4)	341			—			—
Noncash adjustment for estimated allowed claims related to debt (Note 4)	354			—			—
Sponsor management agreement settlement (Note 4)	(27		)	—			—
Reduction in reserve recorded for income tax receivable (Note 3)	(22		)	—			—
Income tax benefit due to IRS audit resolutions	—			(14		)	(132		)
Reserve for income tax receivable from TCEH	—			91			—
Gain on debt exchanges	—			—			(566		)
Impairment of investment in debt of affiliates	—			—			70
Reserve for intercompany receivables	—			17			642
Amortization of debt related costs	—			12			36
Other, net	—			—			2
Changes in operating assets and liabilities:
Changes in assets	29			13			100
Changes in liabilities	135			158			(75		)
Cash provided by (used in) operating activities	79			135			(174		)
Cash flows — financing activities
Distributions received from subsidiaries	—			—			690
Change in notes/advances — affiliate	16			60			(622		)
Other, net	—			—			(5		)
Cash provided by financing activities	16			60			63
Cash flows — investing activities
Other, net	1			—			9
Cash provided by investing activities	1			—			9
Net change in cash and cash equivalents	96			195			(102		)
Cash and cash equivalents — beginning balance	392			197			299
Cash and cash equivalents — ending balance	$	488		$	392		$	197

See Notes to the Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. (PARENT), A DEBTOR-IN-POSSESSION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED BALANCE SHEETS (Millions of Dollars)
	December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	488		$	392
Accounts receivable from subsidiaries	8			6
Prepayments	2			7
Total current assets	498			405
Receivables from unconsolidated subsidiary	—			47
Investment in debt of subsidiaries (Note 2)	—			39
Other investments	24			60
Other noncurrent assets	5			3
Total assets	$	527		$	554
LIABILITIES AND EQUITY
Current liabilities:
Payables to subsidiaries	$	33		$	—
Trade accounts payable	5			1
Notes payable to affiliates	5			8
Accumulated deferred income taxes	—			18
Accrued taxes	17			69
Other current liabilities	42			40
Total current liabilities	102			136
Liabilities subject to compromise (Note 5)	1,409			1,899
Accumulated deferred income taxes	400			368
Payable to subsidiaries	18			7
Other noncurrent liabilities and deferred credits	248			374
Total liabilities	2,177			2,784
Commitments and Contingencies (Note 7)
Equity investment in consolidated subsidiaries	23,411			17,493
Shareholders' equity	(25,061		)	(19,723		)
Total equity	(1,650		)	(2,230		)
Total liabilities and equity	$	527		$	554

See Notes to the Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. (PARENT), A DEBTOR-IN-POSSESSION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

The accompanying unconsolidated condensed balance sheets, statements of income (loss) and cash flows present results of operations and cash flows of EFH Corp. (Parent). Certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the financial statements and related notes of Energy Future Holdings Corp. and Subsidiaries included in Item 8 of this Annual Report on Form 10-K. EFH Corp.'s subsidiaries have been accounted for under the equity method. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

2. INVESTMENT IN DEBT OF SUBSIDIARY

As a result of debt exchanges and purchases in 2009 through 2011, EFH Corp. (Parent) held debt securities of TCEH with carrying values totaling $39 million at December 31, 2014, reported as investment in debt of subsidiaries. The amounts of TCEH debt held by EFH Corp. (Parent) were eliminated as a result of the Settlement Agreement approved by the Bankruptcy Court in December 2015. This resulted in a loss of $33 million recorded in reorganization items.

As of December 31, 2014, all of these debt securities were classified as available-for-sale. In accordance with accounting guidance for investments classified as available-for-sale, the securities were recorded at fair value and unrealized gains or losses were recorded in other comprehensive income unless such losses were other than temporary, in which case they were reported as impairments. The principal amounts, coupon rates, maturities and carrying value were as follows as of December 31, 2014:

	December 31, 2014
	Principal Amount		Carrying Value (a)
Available-for-sale securities:
TCEH 4.730% Term Loan Facilities maturing October 10, 2017	$	19	$	12
TCEH 10.25% Fixed Senior Notes due November 1, 2015 (includes $102 million principal amount of Series B Notes)	284		27
Total available-for-sale securities	$	303	$	39

_____________

(a) Carrying value equals fair value.

Impairments — In 2015 and 2013, we deemed the declines in value of the TCEH debt securities were other than temporary and recorded impairments totaling $6 million and $70 million, respectively, as reductions of interest income. Our assessment considered that the securities were in a loss position for more than 12 months and that declines in natural gas prices and other corresponding effects on the profitability and cash flows of TCEH (which has below investment grade credit ratings) were unlikely to reverse in the near term. No cumulative unrealized losses were recorded in accumulated other comprehensive income at December 31, 2013.

Interest income recorded on these investments was as follows:

	Year Ended December 31,
	2015			2014		2013
Available-for-sale securities:
Interest received/accrued	$	—		$	12	$	30
Impairments related to issuer credit	(6		)	—		(70		)
Total interest income	$	(6	)	$	12	$	(40	)

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We determine fair value under the fair value hierarchy established in accounting standards. Under the fair value hierarchy, Level 2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. The fair value of our investment in debt of subsidiaries was estimated at the lesser of either the call price or the market value as determined by broker quotes and quoted market prices for similar securities in active markets. As of December 31, 2014, the fair values of our investment in debt of subsidiaries represent Level 2 valuations.

3. AFFILIATE BALANCES

Settlement Agreement

The Settling Parties entered into a settlement agreement (the Settlement Agreement) in August 2015 (as amended in September 2015) to compromise and settle, among other things (a) intercompany claims among the Debtors, (b) claims and causes of actions against holders of first lien claims against TCEH and the agents under the TCEH Senior Secured Facilities, (c) claims and causes of action against holders of interests in EFH Corp. and certain related entities and (d) claims and causes of action against each of the Debtors' current and former directors, the Sponsor Group, managers and officers and other related entities. The Settlement Agreement is expected to remain effective regardless of whether the EFH Acquisition is completed. The Bankruptcy Court approved the Settlement Agreement in December 2015.

In December 2015, pursuant to the approved Settlement Agreement, Backstop Agreement, Merger Agreement and Plan of Reorganization, EFH Corp. (Parent) recorded a gain for an adjustment related to the Sponsor Group's agreement to forego claims related to a management agreement of $64 million, which is reported in our statement of consolidated income (loss) in reorganization items. Additionally, we recorded adjustments to eliminate all intercompany claims among the debtors except for a TCEH unsecured claim against EFH Corp. of $700 million as contemplated by the Plan of Reorganization and a gain of $408 million was recorded in reorganization items related to the forgiveness of an income tax payable due to EFIH. Further, pursuant to the Settlement Agreement, EFH Corp. (Parent) recorded a gain of $1.283 billion related to forgiveness of debt held by affiliates.

Other

The EFH Corp. (Parent) net income tax receivable from TCEH was reduced during the year ended December 31, 2015, resulting in a credit to the existing reserve of $22 million, which is reported in other income.

EFH Corp. (Parent) fully reserved a net income tax receivable from TCEH, resulting in a charge of $91 million at December 31, 2014, reported in other deductions. EFH Corp. (Parent) also fully reserved pre-petition interest receivable from EFCH, resulting in a charge of $14 million at December 31, 2014, reported in other deductions. EFH Corp. (Parent) also fully reserved a pre-petition intercompany accounts receivable because of significant uncertainty regarding its ultimate settlement, resulting in a charge of $3 million at December 31, 2014, reported in other deductions.

On April 29, 2014, EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Prior to December 31, 2013, EFH Corp. (Parent) had entered into certain transactions with its subsidiaries that upon the Bankruptcy Filing resulted in unsecured prepetition liabilities on the part of the subsidiaries that are subject to settlement under a Chapter 11 plan. Because of the significant uncertainty regarding the ultimate settlement of these amounts, in the fourth quarter 2013 EFH Corp. (Parent) fully reserved the following receivables:

• A net income tax receivable from TCEH was fully reserved, resulting in a charge of $534 million, reported in other deductions. The receivable arose from a Federal and State Income Tax Allocation Agreement, which provides, among other things, that each of EFCH, EFIH, TCEH and other subsidiaries under the agreement is required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return.

• A demand note receivable from EFCH was fully reserved, resulting in a charge of $103 million reported in other deductions. The receivable arose from borrowings by EFCH to repay certain outstanding debt as it became due.

• An interest receivable from TCEH was fully reserved, resulting in a charge of $5 million reported in other deductions. The receivable represented accrued interest related to the EFH Corp.'s holdings of TCEH debt securities.

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In addition, in the fourth quarter 2013, EFH Corp. (Parent) determined that the likelihood that receivables and payables with certain of its direct subsidiaries would be cash settled was remote. As such $899 million of corporate affiliate receivables and $1.350 billion of corporate affiliate payables were reclassified to equity investment in consolidated subsidiaries. Substantially all of the affiliates represent discontinued operations and are no longer active.

4. REORGANIZATION ITEMS

Expenses and income directly associated with the Chapter 11 Cases are reported separately in the condensed statements of income (loss) as reorganization items as required by ASC 852, Reorganizations. Reorganization items also include adjustments to reflect the carrying value of liabilities subject to compromise (LSTC) at their estimated allowed claim amounts, as such adjustments are determined. The following table presents reorganization items incurred in the year ended December 31, 2015 and the post-petition period ended December 31, 2014 as reported in the condensed statement of income (loss):

	Year Ended December 31, 2015			Post-Petition Period Ended December 31, 2014
Expenses related to legal advisory and representation services	$	56		$	13
Expenses related to other professional consulting and advisory services	26			13
Noncash adjustment for estimated allowed claims related to debt	354			—
Adjustment to intercompany claims pursuant to settlement agreement	341			—
Gain on settlement of debt held by affiliates	(1,283		)	—
Gain on settlement of interest on debt held by affiliates	(35		)	—
Sponsor management agreement settlement	(64		)	—
Contract claims adjustments	(2		)	—
Other reorganization items	1			1
Total reorganization items	$	(606	)	$	27

5. LIABILITIES SUBJECT TO COMPROMISE

The amounts classified as liabilities subject to compromise (LSTC) reflect the company's estimate of pre-petition liabilities and other expected allowed claims to be addressed in the Chapter 11 Cases and may be subject to future adjustment as the Chapter 11 Cases proceed. Prior to December 2015, debt amounts include related unamortized deferred financing costs and discounts/premiums. Amounts classified to LSTC do not include pre-petition liabilities that are fully secured by letters of credit or cash deposits. The following table presents LSTC as reported in the condensed consolidated balance sheets at December 31, 2015 and 2014:

	December 31,
	2015		2014
Notes, loans and other debt	$	640	$	1,577
Accrued interest on notes, loans and other debt	20		57
Tax sharing liability	—		212
Trade accounts payable and accrued liabilities	49		52
Advances and other payables to affiliates	700		1
Total liabilities subject to compromise	$	1,409	$	1,899

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6. GUARANTEES

As discussed below, EFH Corp. (Parent) has entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Material guarantees are discussed below.

Assumption of Indebtedness—In prior periods, EFCHpurchased an electric co-op's minority ownership interest in the Comanche Peak nuclear generation facilities and assumed the co-op's indebtedness to the US government related to the co-op's investment in the facilities (without the co-op being released from its obligations under such indebtedness). EFCH is making principal and interest payments in an amount sufficient to satisfy the co-op's requirements under the indebtedness. In the event that payments on the indebtedness are not made in a timely manner, the US government would be entitled to enforce the payment of the debt against EFCH. At December 31, 2015, the balance of the indebtedness on EFCH's balance sheet was $37 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the Comanche Peak generation facilities. EFH Corp. (Parent) has guaranteed EFCH's obligation under this agreement.

7. COMMITMENTS AND CONTINGENCIES

In August 2014, the Bankruptcy Court entered an order establishing discovery procedures governing, among other things, certain prepetition transactions among the various Debtors' estates, including EFH Corp. (Parent). In February 2015, the ad hoc group of TCEH unsecured creditors; the official committee representing unsecured interests at EFCH and its direct subsidiary, TCEH; and the official committee representing unsecured interests at EFH and EFIH filed motions with the Bankruptcy Court seeking standing to prosecute derivative claims on behalf of TCEH relating to certain of these prepetition transactions. These claims were released effective when the Bankruptcy Court approved the Settlement Agreement.

The Settlement Agreement was approved in December 2015 and is expected to remain effective even if the Plan of Reorganization does not become effective.

8. DIVIDEND RESTRICTIONS

Under applicable law, EFH Corp. (Parent) is prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent. In addition, due to the Bankruptcy Filing, no dividends are eligible to be paid without the approval of the Bankruptcy Court. EFH Corp. (Parent) has not declared or paid any dividends since the Merger.

EFH Corp. (Parent) received no dividends from its consolidated subsidiaries in the years ended December 31, 2015 and 2014. EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $690 million for the year ended December 31, 2013.

9. SUPPLEMENTAL CASH FLOW INFORMATION

	Year Ended December 31,
	2015			2014			2013
Cash payments (receipts) related to:
Interest paid	$	—		$	30		$	525
Income taxes	(134		)	(243		)	(224		)
Reorganization items (a)	68			14			—

___________

(a) Represents cash payments for legal and other consulting services.

195

(b) Oncor Holdings Financial Statements are presented pursuant to Rule 3–09 of Regulation S-X as Exhibit 99(e).

(c) Exhibits:

EFH Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2014

Exhibits	Previously Filed* With File Number	As Exhibit
(2)	Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2(a)	1-12833 Form 8-K (filed February 26, 2007)	2.1	—	Agreement and Plan of Merger, dated February 25, 2007, by and among Energy Future Holdings Corp. (formerly known as TXU Corp.), Texas Energy Future Holdings Limited Partnership and Texas Energy Future Merger Sub Corp.
2(b)	1-12833 Form 8-K (filed December 11, 2015)	2(a)	—	Amended Order Confirming the Debtors' Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code entered by the Bankruptcy Court on December 9, 2015
2(c)	1-12833 Form 8-K (filed December 11, 2015)	2(b)	—	The Debtors' Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code effective as of December 7, 2015
(3(i))	Articles of Incorporation
3(a)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	3(a)	—	Restated Certificate of Formation of Energy Future Holdings Corp.
(3(ii))	By-laws
3(b)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	3(b)	—	Amended and Restated Bylaws of Energy Future Holdings Corp.
(4)	Instruments Defining the Rights of Security Holders, Including Indentures**
	Energy Future Holdings Corp.
4(a)	1-12833 Form 10-K (2007) (filed March 31, 2008)	4(c)	—	Indenture (For Unsecured Debt Securities Series P), dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee.
4(b)	1-12833 Form 8-K (filed July 7, 2010)	99.1	—	Supplemental Indenture, dated July 1, 2010, to the Indenture, dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee (For Unsecured Debt Securities Series P due 2014).
4(c)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(f)	—	Second Supplemental Indenture, dated April 15, 2013, to the Indenture, dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee (For Unsecured Debt Securities Series P due 2014).
4(d)	1-12833 Form 10-K (2004) (filed March 16, 2005)	4(q)	—	Officers’ Certificate, dated November 26, 2004, establishing the form and certain terms of Energy Future Holdings Corp.’s 5.55% Series P Senior Notes due 2014.
4(e)	1-12833 Form 10-K (2010) (filed February 18, 2011)	4(d)	—	Indenture (For Unsecured Debt Securities Series Q), dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee. Energy Future Holdings Corp.’s Indentures for its Series R Senior Notes are not filed as it is substantially similar to this Indenture.
4(f)	1-12833 Form 10-K (2004) (filed March 16, 2005)	4(r)	—	Officers' Certificate, dated November 26, 2004, establishing the form and certain terms of Energy Future Holdings Corp.’s 6.50% Series Q Senior Notes due 2024.

196

Exhibits	Previously Filed* With File Number	As Exhibit
4(g)	1-12833 Form 8-K (filed December 5, 2012)	4.3	—	Supplemental Indenture, dated December 5, 2012, to the Indenture, dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee (For Unsecured Debt Securities Series Q due 2024).
4(h)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(g)	—	Second Supplemental Indenture, dated April 15, 2013, to the Indenture, dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee (For Unsecured Debt Securities Series Q due 2024).
4(i)	1-12833 Form 10-K (2004) (filed March 16, 2005)	4(s)	—	Officer’s Certificate, dated November 26, 2004, establishing the form and certain terms of Energy Future Holdings Corp.’s 6.55% Series R Senior Notes due 2034.
4(j)	1-12833 Form 8-K (filed December 5, 2012)	4.4	—	Supplemental Indenture, dated December 5, 2012, to the Indenture, dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee (For Unsecured Debt Securities Series R due 2034).
4(k)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(h)	—	Second Supplemental Indenture, dated April 15, 2013, to the Indenture, dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee (For Unsecured Debt Securities Series R due 2034).
4(l)	1-12833 Form 8-K (filed October 31, 2007)	4.1	—	Indenture, dated October 31, 2007, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon, as trustee, relating to Senior Notes due 2017 and Senior Toggle Notes due 2017.
4(m)	1-12833 Form 10-K (2009) (filed February 19, 2010)	4(f)	—	Supplemental Indenture, dated July 8, 2008, to Indenture, dated October 31, 2007.
4(n)	1-12833 Form 10-Q (Quarter ended June 30, 2009) (filed August 4, 2009)	4(a)	—	Second Supplemental Indenture, dated August 3, 2009, to Indenture, dated October 31, 2007.
4(o)	1-12833 Form 8-K (filed July 30, 2010)	99.1	—	Third Supplemental Indenture, dated July 29, 2010, to Indenture, dated October 31, 2007.
4(p)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	4(b)	—	Fourth Supplemental Indenture, dated October 18, 2011, to Indenture dated October 31, 2007.
4(q)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(a)	—	Fifth Supplemental Indenture, dated April 15, 2013, to the Indenture, dated October 31, 2007, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to Senior Notes due 2017 and Senior Toggle Notes due 2017.
4(r)	1-12833 Form 8-K (filed November 20, 2009)	4.1	—	Indenture, dated November 16, 2009, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019.
4(s)	1-12833 Form 8-K (January 30, 2013)	4.1	—	Supplemental Indenture, dated January 25, 2013, to the Indenture, dated November 16, 2009, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019.
4(t)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(c)	—	Second Supplemental Indenture, dated April 15, 2013, to the Indenture, dated November 16, 2009, among Energy Future Holdings Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019.

197

Exhibits	Previously Filed* With File Number	As Exhibit
4(u)	333-171253 Form S-4 (filed January 24, 2011)	4(k)	—	Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(v)	333-165860 Form S-3 (filed April 1, 2010)	4(j)	—	First Supplemental Indenture, dated March 16, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(w)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(a)	—	Second Supplemental Indenture, dated April 13, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(x)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(b)	—	Third Supplemental Indenture, dated April 14, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(y)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(c)	—	Fourth Supplemental Indenture, dated May 21, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(z)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(d)	—	Fifth Supplemental Indenture, dated July 2, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(aa)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(e)	—	Sixth Supplemental Indenture, dated July 6, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(bb)	333-171253 Form S-4 (filed January 24, 2011)	4(r)	—	Seventh Supplemental Indenture, dated July 7, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(cc)	1-12833 Form 8-K (January 30, 2013)	4.2	—	Eighth Supplemental Indenture, dated January 25, 2013, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(dd)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(e)	—	Ninth Supplemental Indenture, dated April 15, 2013, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
	Oncor Electric Delivery Company LLC
4(ee)	333-100240 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon, as trustee.
4(ff)	1-12833 Form 8-K (filed October 31, 2005)	10.1	—	Supplemental Indenture No. 1, dated October 25, 2005, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon.

198

Exhibits	Previously Filed* With File Number	As Exhibit
4(gg)	333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	4(b)	—	Supplemental Indenture No. 2, dated May 15, 2008, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon.
4(hh)	333-100240 Form S-4 (filed October 2, 2002)	4(b)	—	Officer’s Certificate, dated May 6, 2002, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes due 2012 and 7.000% Senior Notes due 2032.
4(ii)	333-100242 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture (for Unsecured Debt Securities), dated August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon, as trustee.
4(jj)	333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	4(c)	—	Supplemental Indenture No. 1, dated May 15, 2008, to Indenture and Deed of Trust, dated August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York.
4(kk)	333-100242 Form S-4 (filed October 2, 2002)	4(b)	—	Officer’s Certificate, dated August 30, 2002, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 5% Debentures due 2007 and 7% Debentures due 2022.
4(ll)	333-106894 Form S-4 (filed July 9, 2003)	4(c)	—	Officer’s Certificate, dated December 20, 2002, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes due 2015 and 7.250% Senior Notes due 2023.
4(mm)	333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	4(a)	—	Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008, by Oncor Electric Delivery Company LLC, as grantor, to and for the benefit of, The Bank of New York Mellon Trust, as collateral agent and trustee.
4(nn)	333-100240 Form 10-K (2008) (filed March 3, 2009)	4(n)	—	First Amendment, dated March 2, 2009, to Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008.
4(oo)	333-100240 Form 8-K (filed September 3, 2010)	10.1	—	Second Amendment, dated September 3, 2010, to Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008.
4(pp)	333-100240 Form 8-K (filed November 15, 2011)	10.1	—	Third Amendment, dated November 10, 2011, to Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008.
4(qq)	333-100242 Form 8-K (filed September 9, 2008)	4.1	—	Officer’s Certificate, dated September 8, 2008, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 5.95% Senior Secured Notes due 2013, 6.80% Senior Secured Notes due 2018 and 7.50% Senior Secured Notes due 2038.
4(rr)	333-100240 Form 8-K (filed September 16, 2010)	4.1	—	Officer’s Certificate, dated September 13, 2010, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 5.25% Senior Secured Notes due 2040.
4(ss)	333-100240 Form 8-K (filed October 12, 2010)	4.1	—	Officer's Certificate, dated October 8, 2010, establishing the form and certain terms of Oncor Electric Delivery Company LLC's 5.00% Senior Secured Notes due 2017 and 5.75% Senior Secured Notes due 2020.
4(tt)	333-100240 Form 8-K (filed November 23, 2011)	4.1	—	Officer's Certificate, dated November 23, 2011, establishing the terms of Oncor's 4.55% Senior Secured Notes due 2041.
4(uu)	333-100240 Form 8-K (filed May 18, 2012)	4.1	—	Officer's Certificate, dated May 18, 2012, establishing the terms of Oncor's 4.10% Senior Secured Notes due 2022 and 5.30% Senior Secured Notes due 2042.

199

Exhibits	Previously Filed* With File Number	As Exhibit
4(vv)	333-100240 Form 8-K (filed May 13, 2013)	4.1	—	Registration Rights Agreement, dated May 13, 2013, among Oncor Electric Delivery Company LLC and the representatives of the initial purchasers of the addition 4.55% Senior Secure Notes due 2041.
4(ww)	333-100240 Form 8-K (filed May 13, 2014)	4.1	—	Officer's Certificate, dated May 13, 2014, establishing the terms of Oncor Electric Delivery Company LLC's 2.15% Senior Secured Notes due 2019.
4(xx)	333-100240 Form 8-K (filed May 13, 2014)	4.2	—	Registration Rights Agreement, dated May 13, 2014, among Oncor Electric Delivery Company LLC and the representatives of the initial purchasers of Oncor Electricity Delivery Company LLC's 2.15% Senior Secured Notes due 2019.
4(yy)	333-100240 Form 8-K (filed March 30, 2015)	4.1	—	Officer's Certificate dated March 24, 2015, establishing the terms of Oncor Electric Delivery Company LLC's 2.950% Senior Secured Notes due 2025 and 3.750% Senior Secured Notes due 2045.
4(zz)	333-100240 Form 8-K (filed March 30, 2015)	4.2	—	Registration Rights Agreement, dated March 24, 2015, among Oncor Electric Delivery Company LLC and the representatives of the initial purchasers of Oncor Electricity Delivery Company LLC's 2.950% Senior Secured Notes due 2025 and 3.750% Senior Secured Notes due 2045.
	Texas Competitive Electric Holdings Company LLC
4(aaa)	333-108876 Form 8-K (filed October 31, 2007)	4.2	—	Indenture, dated October 31, 2007, among Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc., the guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.25% Senior Notes due 2015.
4(bbb)	1-12833 Form 8-K (filed December 12, 2007)	4.1	—	First Supplemental Indenture, dated December 6, 2007, to Indenture, dated October 31, 2007, relating to Texas Competitive Electric Holdings Company LLC’s and TCEH Finance, Inc.’s 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016.
4(ccc)	1-12833 Form 10-Q (Quarter ended June 30, 2009) (filed August 4, 2009)	4(b)	—	Second Supplemental Indenture, dated August 3, 2009, to Indenture, dated October 31, 2007, relating to Texas Competitive Electric Holdings Company LLC’s and TCEH Finance, Inc.’s 10.25% Senior Notes due 2015, 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016.
4(ddd)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(i)	—	Third Supplemental Indenture, dated January 11, 2013, to the Indenture dated October 31, 2007, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.25% Senior Notes due 2015, 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016.
4(eee)	1-12833 Form 10-K (2013) (filed April 30, 2014)	4(ccc)	—	Fourth Supplemental Indenture, dated February 24, 2014, to the Indenture dated October 31, 2007, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.25% Senior Notes due 2015, 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016.
4(fff)	1-12833 Form 8-K (filed October 8, 2010)	4.1	—	Indenture, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc., the guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 15% Senior Secured Second Lien Notes due 2021.
4(ggg)	1-12833 Form 8-K (filed October 26, 2010)	4.1	—	First Supplemental Indenture, dated October 20, 2010, to the Indenture, dated October 6, 2010.

200

Exhibits	Previously Filed* With File Number	As Exhibit
4(hhh)	1-12833 Form 8-K (filed November 17, 2010)	4.1	—	Second Supplemental Indenture, dated November 15, 2010, to the Indenture, dated October 6, 2010.
4(iii)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	4(a)	—	Third Supplemental Indenture, dated as of September 26, 2011, to the Indenture, dated October 6, 2010.
4(jjj)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(k)	—	Fourth Supplemental Indenture, dated January 11, 2013, to the Indenture dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 15% Senior Secured Second Lien Notes due 2021 and 15% Senior Secured Second Lien Notes due 2021, Series B.
4(kkk)	1-12833 Form 10-K (2013) (filed April 30, 2014)	4(iii)	—	Fifth Supplemental Indenture, dated February 24, 2014, to the Indenture dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 15% Senior Secured Second Lien Notes due 2021 and 15% Senior Secured Second Lien Notes due 2021, Series B.
4(lll)	1-12833 Form 8-K (filed October 8, 2010)	4.3	—	Second Lien Pledge Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as collateral agent for the benefit of the second lien secured parties.
4(mmm)	1-12833 Form 8-K (filed October 8, 2010)	4.4	—	Second Lien Security Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the subsidiary guarantors named therein and The Bank Of New York Mellon Trust Company, N.A., as collateral agent and as the initial second priority representative for the benefit of the second lien secured parties.
4(nnn)	1-12833 Form 8-K (filed October 8, 2010)	4.5	—	Second Lien Intercreditor Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the subsidiary guarantors named therein, Citibank, N.A., as collateral agent for the senior collateral agent and the administrative agent, The Bank of New York Mellon Trust Company, N.A., as the initial second priority representative.
4(ooo)	1-12833 Form 10-K (2010) (filed February 18, 2011)	4(aaa)	—	Form of Second Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of The Bank of New York Mellon Trust Company, N.A., as Collateral Agent and Initial Second Priority Representative for the benefit of the Second Lien Secured Parties, as Beneficiary.
4(ppp)	1-12833 Form 8-K (filed April 20, 2011)	4.1	—	Indenture, dated as of April 19, 2011, among Texas Competitive Electric Holdings Company LLC, TCEH Finance Inc., the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.5% Senior Secured Notes due 2020.
4(qqq)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(j)	—	Supplemental Indenture, dated January 11, 2013, to the Indenture dated April 19, 2011, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.5% Senior Secured Notes due 2020.
4(rrr)	1-12833 Form 10-K (2013) (filed April 30, 2014)	4(ppp)	—	Second Supplemental Indenture, dated February 24, 2014, to the Indenture dated April 19, 2011, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.5% Senior Secured Notes due 2020.

201

Exhibits	Previously Filed* With File Number	As Exhibit
4(sss)	1-12833 Form 8-K (filed April 20, 2011)	4.2	—	Form of Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Fling to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as Collateral Agent for the benefit of the Holders of the 11.5% Senior Secured Notes due 2020, as Beneficiary.
4(ttt)	1-12833 Form 8-K (filed April 20, 2011)	4.3	—	Form of Deed of Trust and Security Agreement to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as Collateral Agent for the benefit of the Holders of the 11.5% Senior Secured Notes due 2020, as Beneficiary.
4(uuu)	1-12833 Form 8-K (filed April 20, 2011)	4.4	—	Form of Subordination and Priority Agreement, among Citibank, N.A., as beneficiary under the First Lien Credit Deed of Trust, The Bank of New York Mellon Trust Company, N.A., as beneficiary under the Second Lien Indenture Deed of Trust, Citibank, N.A., as beneficiary under the First Lien Indenture Deed of Trust, Texas Competitive Electric Holdings Company LLC and the subsidiary guarantors party thereto.
	Energy Future Intermediate Holding Company LLC
4(vvv)	1-12833 Form 8-K (filed November 20, 2009)	4.2	—	Indenture, dated November 16, 2009, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019.
4(www)	1-12833 Form 8-K (filed January 30, 2013)	4.3	—	Supplemental Indenture, dated January 25, 2013, to the indenture, dated November 16, 2009, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019.
4(xxx)	1-12833 Form 8-K (filed August 18, 2010)	4.1	—	Indenture, dated August 17, 2010, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(yyy)	1-12833 Form 8-K (filed January 30, 2013)	4.4	—	First Supplemental Indenture, dated January 29, 2013, to the indenture, dated August 17, 2010, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(zzz)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(n)	—	Second Supplemental Indenture, dated March 21, 2013, to the Indenture dated August 17, 2010, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(aaaa)	1-12833 Form 10-Q (Quarter ended March 31, 2011) (filed April 29, 2011)	4(e)	—	Indenture, dated as of April 25, 2011, among Energy Future Intermediate Holding Company LLC, EFIH Finance, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11% Senior Secured Second Lien Notes due 2021.
4(bbbb)	1-12833 Form 8-K (filed February 7, 2012)	4.1	—	First Supplemental Indenture, dated February 6, 2012, to the indenture dated April 25, 2011, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to 11.750% Senior Secured Second Lien Notes due 2022.
4(cccc)	1-12833 Form 8-K (filed February 29, 2012)	4.1	—	Second Supplemental Indenture, dated February 28, 2012, to the indenture dated April 25, 2011, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to 11.750% Senior Secured Second Lien Notes due 2022.

202

Exhibits	Previously Filed* With File Number	As Exhibit
4(dddd)	1-12833 Form 10-Q (Quarter ended June 30, 2012) (filed July 31, 2012)	4(a)	—	Third Supplemental Indenture, dated May 31, 2012, to the indenture dated April 25, 2011, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to 11.750% Senior Secured Second Lien Notes due 2022.
4(eeee)	1-12833 Form 8-K (filed August 17, 2012)	4.2	—	Fourth Supplemental Indenture, dated August 14, 2012, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and the Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.75% Senior Secured Second Lien Notes due 2022.
4(ffff)	1-12833 Form 8-K (filed August 17, 2012)	4.1	—	Indenture, dated August 14, 2012, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and the Bank of New York Mellon Trust Company, N.A., as trustee, relating to 6.875% Senior Secured Notes due 2017.
4(gggg)	1-12833 Form 8-K (filed October 24, 2012)	4.1	—	First Supplemental Indenture, dated October 23, 2012, to the indenture dated August 14, 2012, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc., and the Bank of New York Mellon Trust Company, N.A., as trustee, relating to 6.875% Senior Secured Notes due 2017.
4(hhhh)	1-12833 Form 8-K (filed December 5, 2012)	4.1	—	Indenture, dated December 5, 2012, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc., and the Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.25%/12.25% Senior Toggle Notes due 2018.
4(iiii)	1-12833 Form 8-K (filed December 21, 2012)	4.1	—	First Supplemental Indenture, dated December 19, 2012, to the indenture dated December 5, 2012, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc., and the Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.25%/12.25% Senior Toggle Notes due 2018.
4(jjjj)	1-12833 Form 8-K (filed January 30, 2013)	4.5	—	Second Supplemental Indenture, dated January 29, 2013, to the indenture dated December 5, 2012, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc., and the Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.25%/12.25% Senior Toggle Notes due 2018.
4(kkkk)	1-12833 Form 10-K (2012) (filed February 19, 2013)	4(uuu)	—	Third Supplemental Indenture, dated January 30, 2013, to the indenture, dated December 5, 2012, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc., and the Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.25%/12.25% Senior Toggle Notes due 2018.
4(llll)	1-12833 Form 10-Q (Quarter ended March 31, 2011) (filed April 29, 2011)	4(f)	—	Junior Lien Pledge Agreement, dated as of April 25, 2011, from Energy Future Intermediate Holding Company LLC, as pledgor, to The Bank of New York Mellon Trust Company, N.A., as collateral trustee.
(10)	Material Contracts
	Management Contracts; Compensatory Plans, Contracts and Arrangements
10(a)	1-12833 Form 8-K (filed May 23, 2005)	10.6	—	Energy Future Holdings Corp. Executive Change in Control Policy effective May 20, 2005.
10(b)	333-153529 Amendment No. 2 to Form S-4 (filed December 23, 2008)	10(p)	—	Amendment to the Energy Future Holdings Corp. Executive Change in Control Policy, dated December 23, 2008.
10(c)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(e)	—	Amendment to the Energy Future Holdings Corp. Executive Change in Control Policy, dated December 20, 2010.

203

Exhibits	Previously Filed* With File Number	As Exhibit
10(d)	1-12833 Form 8-K (filed May 23, 2005)	10.7	—	Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Plan Description.
10(e)	333-153529 Amendment No. 2 to Form S-4 (filed December 23, 2008)	10(n)	—	Amendment to the Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Plan Description, dated December 23, 2008.
10(f)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(f)	—	Amendment to the Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Plan Description, dated December 10, 2010.
10(g)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(a)	—	2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its affiliates.
10(h)	1-12833 Form 10-K (2009) (filed February 19, 2010)	10(ii)	—	Amendment No. 1 to the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates, dated July 14, 2009, effective as of December 23, 2008.
10(i)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(i)	—	EFH Executive Annual Incentive Plan, effective as of January 1, 2010.
10(j)	1-12833 Form 10-K (2008) (filed March 3, 2009)	10(q)	—	EFH Second Supplemental Retirement Plan, effective as of October 10, 2007.
10(k)	1-12833 Form 10-K (2009) (filed February 19, 2010)	10(ee)	—	Amendment to EFH Second Supplemental Retirement Plan, dated July 31, 2009.
10(l)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(l)	—	Second Amendment to EFH Second Supplemental Retirement Plan, dated April 9, 2010 with effect as of January 1, 2010.
10(m)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(m)	—	Third Amendment to EFH Second Supplemental Retirement Plan, dated April 21, 2010 with effect as of January 1, 2010.
10(n)	1-12833 Form 10-K (2011) (filed February 21, 2012)	10(n)	—	Fourth Amendment to EFH Second Supplemental Retirement Plan, dated June 17, 2011.
10(o)	1-12833 Form 10-K (2009) (filed February 19, 2010)	10(dd)	—	EFH Salary Deferral Program, effective January 1, 2010.
10(p)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(o)	—	Amendment to EFH Salary Deferral Program, effective January 20, 2011.
10(q)	1-12833 Form 10-K (2011) (filed February 21, 2012)	10(q)	—	Second Amendment to EFH Salary Deferral Program, dated June 17, 2011.
10(r)	1-12833 Form 10-Q (Quarter ended September 30, 2012) (filed October 30, 2012)	10(a)	—	Third Amendment to the EFH Salary Deferral Program, effective September 20, 2012.
10(s)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(b)	—	Registration Rights Agreement, dated October 10, 2007, among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp. and the stockholders party thereto.

204

Exhibits	Previously Filed* With File Number	As Exhibit
10(t)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(a)	—	Form of Stockholder’s Agreement (for Directors) among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and the stockholder party thereto.
10(u)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(b)	—	Form of Sale Participation Agreement (for Directors) between Texas Energy Future Holdings Limited Partnership and the stockholder party hereto.
10(v)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(f)	—	Form of Management Stockholder’s Agreement (For Executive Officers) among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and the stockholder party thereto.
10(w)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(g)	—	Form of Sale Participation Agreement (For Executive Officers) between Texas Energy Future Holdings Limited Partnership and the stockholder party thereto.
10(x)	1-12833 Form 10-K (2009) (filed February 19, 2010)	10(m)	—	Form of Amended and Restated Non-Qualified Stock Option Agreement (For Executive Officers) between Energy Future Holdings Corp. and the optionee thereto.
10(y)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(i)	—	Form of Restricted Stock Unit Agreement between Energy Future Holdings Corp. and the stockholder party thereto.
10(z)	1-12833 Form 10-K (2011) (filed February 21, 2012)	10(y)	—	EFH Corp. Retention Award Plan (For Key Employees), effective December 20, 2011.
10(aa)	1-12833 Form 10-K (2011) (filed February 21, 2012)	10(z)	—	Form of Participation Agreement (For Key Employees) between Energy Future Holdings Corp. and the participant party thereto.
10(bb)			—	Energy Future Holdings Corp. Non-Employee Director Compensation Arrangements.
10(cc)	1-12833 Form 10-K (2013) (filed April 30, 2014)	10(cc)	—	Amended and Restated Employment Agreement, dated April 23, 2014, between Energy Future Holdings Corp. and Donald L. Evans.
10(dd)	1-12833 Form 10-K (2014) (filed March 31, 2015)	10(dd)	—	Amended and Restated Employment Agreement, dated March 30, 2015, between Energy Future Holdings Corp. and John Young.
10(ee)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(r)	—	Management Stockholder’s Agreement, dated February 1, 2008, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and John Young.
10(ff)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(s)	—	Sale Participation Agreement, dated February 1, 2008, between Texas Energy Future Holdings Limited Partnership and John F. Young.
10(gg)	1-12833 Form 10-K (2014) (filed March 31, 2015)	10(gg)	—	Amended and Restated Employment Agreement, dated March 27, 2015, between EFH Corporate Services Company, Energy Future Holdings Corp. and Paul Keglevic.
10(hh)	1-12833 Form 10-K (2014) (filed March 31, 2015)	10(hh)	—	Amended and Restated Employment Agreement, dated March 27, 2015, between TXU Energy Retail Company LLC, Energy Future Holdings Corp. and James A. Burke.

205

Exhibits	Previously Filed* With File Number	As Exhibit
10(ii)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ff)	—	Additional Payment Agreement, dated October 10, 2007, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership, Texas Competitive Electric Holdings Company LLC and James Burke.
10(jj)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(nn)	—	Deferred Share Agreement, dated October 9, 2007, between Texas Energy Future Holdings Limited Partnership and James Burke.
10(kk)	1-12833 Form 10-K (2014) (filed March 31, 2015)	10(kk)	—	Amended and Restated Employment Agreement, dated March 27, 2015, between Luminant Holding Company LLC, Energy Future Holdings Corp. and Mark Allen McFarland.
10(ll)	1-12833 Form 10-K (2014) (filed March 31, 2015)	10(mm)	—	Amended and Restated Employment Agreement, dated March 27, 2015, between EFH Corporate Services Company, Energy Future Holdings Corp. and Stacey H. Doré.
10(mm)	1-12833 Form 10-K (2014) (filed March 31, 2015)	10(nn)	—	Amended and Restated Employment Agreement, dated March 27, 2015, between EFH Corporate Services Company, Energy Future Holdings Corp. and Carrie L. Kirby.
	Credit Agreements and Related Agreements
10(nn)	333-100240 Form 8-K (filed October 11, 2011)	10.1	—	Amended and Restated Revolving Credit Agreement, dated as of October 11, 2011, among Oncor Electric Delivery Company LLC, as borrower, the lenders listed therein, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., as swingline lender, and JPMorgan Chase Bank, N.A., Barclays Bank PLC, The Royal Bank of Scotland plc, Bank of America, N.A. and Citibank N.A., as fronting banks for letters of credit issued thereunder.
10(oo)	333-100240 Form 8-K (filed May 15, 2012)	10.1	—	Joinder Agreement, dated as of May 15, 2012, by and among Oncor, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent under the Credit Agreement, swingline lender and fronting bank, Barclays Bank PLC, Bank of America, N.A., Citibank, N.A. and The Royal Bank of Scotland PLC, as fronting banks, and each party identified as an “Incremental Lender” on the signature pages thereto.
10(pp)	333-171253 Post-Effective Amendment #1 to Form S-4 (filed February 7, 2011)	10(rr)	—	$24,500,000,000 Credit Agreement, dated October 10, 2007, among Energy Future Competitive Holdings Company; Texas Competitive Electric Holdings Company LLC, as the borrower; the several lenders from time to time parties thereto; Citibank, N.A., as administrative agent, collateral agent, swingline lender, revolving letter of credit issuer and deposit letter of credit issuer; Goldman Sachs Credit Partners L.P., as posting agent, posting syndication agent and posting documentation agent; JPMorgan Chase Bank, N.A., as syndication agent and revolving letter of credit issuer; Citigroup Global Markets Inc., J.P. Morgan Securities Inc., Goldman Sachs Credit Partners L.P., Lehman Brothers Inc., Morgan Stanley Senior Funding, Inc. and Credit Suisse Securities (USA) LLC, as joint lead arrangers and bookrunners; Goldman Sachs Credit Partners L.P., as posting lead arranger and bookrunner; Credit Suisse, Goldman Sachs Credit Partners L.P., Lehman Commercial Paper Inc., Morgan Stanley Senior Funding, Inc., as co-documentation agents; and J. Aron & Company, as posting calculation agent.
10(qq)	1-12833 Form 8-K (filed August 10, 2009)	10.1	—	Amendment No. 1, dated August 7, 2009, to the $24,500,000,000 Credit Agreement.
10(rr)	1-12833 Form 8-K (filed April 20, 2011)	10.1	—	Amendment No. 2, dated April 7, 2011, to the $24,500,000,000 Credit Agreement.
10(ss)	1-12833 Form 8-K (filed January 7, 2013)	10.1	—	December 2012 Extension Amendment, dated January 4, 2013, to the $24,500,000,000 Credit Agreement.

206

Exhibits	Previously Filed* With File Number	As Exhibit
10(tt)	1-12833 Form 8-K (filed January 7, 2013)	10.2	—	Incremental Amendment No. 1, dated January 4, 2013, to the $24,500,000,000 Credit Agreement.
10(uu)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ss)	—	Guarantee, dated October 10, 2007, by the guarantors party thereto in favor of Citibank, N.A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement, dated October 10, 2007.
10(vv)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(vv)	—	Form of Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as beneficiary.
10(ww)	1-12833 Form 10-Q (Quarter ended March 31, 2011) (filed April 29, 2011)	10(b)	—	Form of First Amendment to Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as Beneficiary.
10(xx)	1-12833 Form 8-K (filed August 10, 2009)	10.2	—	Amended and Restated Collateral Agency and Intercreditor Agreement, dated October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company; Texas Competitive Electric Holdings Company LLC; the subsidiary guarantors party thereto; Citibank, N.A., as administrative agent and collateral agent; Credit Suisse Energy LLC, J. Aron & Company, Morgan Stanley Capital Group Inc., Citigroup Energy Inc., each as a secured hedge counterparty; and any other person that becomes a secured party pursuant thereto.
10(yy)	1-12833 Form 8-K (filed August 10, 2009)	10.3	—	Amended and Restated Security Agreement, dated October 10, 2007, as amended and restated as of August 7, 2009, among Texas Competitive Electric Holdings Company LLC, the subsidiary grantors party thereto, and Citibank, N.A., as collateral agent for the benefit of the first lien secured parties, including the secured parties under the $24,500,000,000 Credit Agreement, dated October 10, 2007.
10(zz)	1-12833 Form 8-K (filed August 10, 2009)	10.4	—	Amended and Restated Pledge Agreement, dated October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary pledgors party thereto, and Citibank, N.A., as collateral agent for the benefit first lien secured parties, including the secured parties under the $24,500,000,000 Credit Agreement, dated October 10, 2007.
10(aaa)	1-12833 Form 8-K filed November 20, 2009)	4.3	—	Pledge Agreement, dated November 16, 2009, made by Energy Future Intermediate Holding Company LLC and the additional pledgers to The Bank of New York Mellon Trust Company, N.A., as collateral trustee for the holders of parity lien obligations.
10(bbb)	1-12833 Form 8-K (filed November 20, 2009)	4.4	—	Collateral Trust Agreement, dated November 16, 2009, among Energy Future Intermediate Holding Company LLC, The Bank of New York Mellon Trust Company, N.A., as first lien trustee and as collateral trustee, and the other secured debt representatives party thereto.
	Other Material Contracts
10(ccc)	1-12833 Form 10-K (2003) (filed March 15, 2004)	10(qq)	—	Lease Agreement, dated February 14, 2002, between State Street Bank and Trust Company of Connecticut, National Association, an owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust, as lessor and EFH Properties Company, as Lessee (Energy Plaza Property).
10(ddd)	1-12833 Form 10-Q (Quarter ended June 30, 2007) (filed August 9, 2007)	10.1	—	First Amendment, dated June 1, 2007, to Lease Agreement, dated February 14, 2002.

207

Exhibits	Previously Filed* With File Number	As Exhibit
10(eee)	333-100240 Form 10-K (2004) (filed March 23, 2005)	10(i)	—	Agreement, dated March 10, 2005, between Oncor Electric Delivery Company LLC and TXU Energy Company LLC, allocating to Oncor Electric Delivery Company LLC the pension and post-retirement benefit costs for all Oncor Electric Delivery Company LLC employees who had retired or had terminated employment as vested employees prior to January 1, 2002.
10(fff)	1-12833 Form 10-K (2006) (filed March 2, 2007)	10(iii)	—	Amended and Restated Transaction Confirmation by Generation Development Company LLC, dated February 2007 (subsequently assigned to Texas Competitive Electric Holdings Company LLC on October 10, 2007) (confidential treatment has been requested for portions of this exhibit).
10(ggg)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(eee)	—	Stipulation as approved by the PUCT in Docket No. 34077.
10(hhh)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(fff)	—	Amendment to Stipulation Regarding Section 1, Paragraph 35 and Exhibit B in Docket No. 34077.
10(iii)	333-100240 Form 10-K (2010) (filed February 18, 2011)	10(ae)	—	PUCT Order on Rehearing in Docket No. 34077.
10(jjj)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(sss)	—	ISDA Master Agreement, dated October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(kkk)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ttt)	—	Schedule to the ISDA Master Agreement, dated October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(lll)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(uuu)	—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(mmm)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(vvv)	—	ISDA Master Agreement, dated October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International.
10(nnn)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(www)	—	Schedule to the ISDA Master Agreement, dated October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International.
10(ooo)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(xxx)	—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Credit Suisse International.
10(ppp)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(yyy)	—	Management Agreement, dated October 10, 2007, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership, Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P., Goldman, Sachs & Co. and Lehman Brothers Inc.
10(qqq)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(cccc)	—	Indemnification Agreement, dated October 10, 2007, among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp., Kohlberg Kravis Roberts & Co., L.P., TPG Capital, L.P. and Goldman, Sachs & Co.
10(rrr)	1-12833 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	10(g)	—	Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Holdings Company LLC, dated November 5, 2008.
10(sss)	333-100240 Form 10-K (2008) (filed March 3, 2009)	3(c)	—	Amendment No. 1, dated February 18, 2009, to Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery LLC.

208

Exhibits	Previously Filed* With File Number	As Exhibit
10(ttt)	333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	4(c)	—	Investor Rights Agreement, dated November 5, 2008, among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
10(uuu)	333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	4(d)	—	Registration Rights Agreement, dated November 5, 2008, among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
10(vvv)	333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	10(b)	—	Amended and Restated Tax Sharing Agreement, dated November 5, 2008, among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Oncor Management Investment LLC, Texas Transmission Investment LLC, Energy Future Intermediate Holding Company LLC and Energy Future Holdings Corp.
10(www)	1-12833 Form 10-Q (Quarter ended September 30, 2012) (filed October 30, 2012)	10(b)	—	Federal and State Income Tax Allocation Agreement, effective January 1, 2010, by and among members of the Energy Future Holdings Corp. consolidated group.
10(xxx)	1-12833 Form 8-K (filed November 18, 2015)	10(a)	—	Second Amendment to Amended and Restated Plan Support Agreement dated November 12, 2015, among the Debtors and the other parties thereto
10(yyy)	1-12833 Form 8-K (filed December 11, 2015)	10(a)	—	Amended and Restated Settlement Agreement dated December 2, 2015 among the Debtors and the other parties thereto.
10(zzz)	1-12833 Form 8-K (filed August 10, 2015)	10(c)	—	Purchase Agreement and Plan of Merger by and among Ovation Acquisition I, L.L.C., Ovation Acquisition II, L.L.C., Energy Future Intermediate Holding Company L.L.C. and Energy Future Holdings Corp. dated as of August 9, 2015.
10(aaaa)	1-12833 Form 8-K (filed August 10, 2015)	10(d)	—	Backstop Agreement, dated as of August 9, 2015, by and among Ovation Acquisition I, L.L.C., Energy Future Holdings Corp., Energy Future Intermediate Holding Company L.L.C. and the Investors party thereto.
10(bbbb)	1-12833 Form 8-K (filed November 27, 2015)	10(a)	—	Purchase and Sale Agreement, dated as of November 25, 2015, by and between La Frontera Ventures, LLC and Luminant Holding Company LLC
	Debtor-In-Possession Facilities
10(cccc)	1-12833 Form 8-K (filed May 7, 2014)	10.1	—	Senior Secured Superpriority Debtor-in-Possession Credit Agreement dated as of May 5, 2014 among EFCH, as Parent Guarantor, TCEH, as Borrower, the Several Lenders from Time to Time Parties Thereto, Citibank, N.A., as Administrative Agent and Collateral Agent, the Co-Syndication Agents Parties Thereto, the Co-Documentation Agents Parties thereto and the Joint Lead Arrangers and Joint Bookrunners Parties thereto.
10(dddd)	1-12833 Form 8-K (filed June 25, 2014)	10(a)	—	Senior Secured Superpriority Debtor-In-Possession Credit Agreement, dated as of June 19, 2014, among the EFIH Debtors, the lenders party thereto, Deutsche Bank AG New York Branch, as Administrative Agent and Collateral Agent, Citibank, N.A., Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents, Barclays Bank PLC, Royal Bank of Canada and Union Bank, N.A., as Co-Documentation Agents, Deutsche Bank Securities Inc., Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley Senior Funding, Inc., Barclays Bank PLC, RBC Capital Markets and Union Bank, N.A., as Joint Lead Arrangers and Joint Bookrunners, and Loop Capital Markets, LLC and Williams Capital Group, LLC, as Co-Managers.

209

Exhibits	Previously Filed* With File Number	As Exhibit
10(eeee)	1-12833 Form 8-K (filed June 25, 2014)	10(b)	—	Pledge Agreement, dated as of June 19, 2014, by and among the EFIH Debtors and Deutsche Bank AG New York Branch, as collateral agent.
10(ffff)	1-12833 Form 8-K (filed June 25, 2014)	10(c)	—	Security Agreement, dated as of June 19, 2014, by and among the EFIH Debtors and Deutsche Bank AG New York Branch, as collateral agent.
10(gggg)	1-12833 Form 8-K (filed June 25, 2014)	10(d)	—	Amendment No. 1 to the TCEH DIP Credit Agreement, dated May 13, 2014, among the TCEH Debtors and the other parties thereto.
10(hhhh)	1-12833 Form 8-K (filed June 25, 2014)	10(e)	—	Amendment No. 2 to the TCEH DIP Credit Agreement, dated June 12, 2014, among the TCEH Debtors and the other parties thereto.
10(iiii)	1-12833 Form 10-K (2014) (filed March 31, 2015)	10(jjjj)	—	Amendment No. 3 to the TCEH DIP Credit Agreement, dated November 6, 2014, among the TCEH Debtors and the other parties thereto.
10(jjjj)	1-12833 Form 8-K (filed November 27, 2015)	10(b)	—	Amendment No. 4 to the TCEH DIP Credit Agreement, dated November 20, 2015, among the TCEH Debtors and the other parties thereto.
(12)	Statement Regarding Computation of Ratios
12(a)			—	Computation of Ratio of Earnings to Fixed Charges.
(21)	Subsidiaries of the Registrant
21(a)			—	Subsidiaries of Energy Future Holdings Corp.
(23)	Consent of Experts
23(a)			—	Consent of Deloitte & Touche LLP, an independent registered public accounting firm, relating to the consolidated financial statements of Energy Future Holdings Corp.
23(b)			—	Consent of Deloitte & Touche LLP, an independent registered public accounting firm, relating to the consolidated financial statements of Oncor Electric Delivery Holdings Company LLC
31	Rule 13a - 14(a)/15d-14(a) Certifications
31(a)			—	Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Section 1350 Certifications
32(a)			—	Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(95)	Mine Safety Disclosures
95(a)			—	Mine Safety Disclosures
(99)	Additional Exhibits

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Exhibits	Previously Filed* With File Number	As Exhibit
99(a)	33-55408 Post-Effective Amendment No. 1 to Form S-3 (filed July, 1993)	99(b)	—	Amended Agreement dated January 30, 1990, between Energy Future Competitive Holdings Company and Tex-La Electric Cooperative of Texas, Inc.
99(b)			—	Texas Competitive Electric Holdings Company LLC Consolidated EBITDA reconciliation for the years ended December 31, 2015 and 2014
99(c)			—	Oncor Electric Delivery Holdings Company LLC financial statements presented pursuant to Rules 3–09 and 3–16 of Regulation S–X.
	XBRL Data Files
101.INS			—	XBRL Instance Document
101.SCH			—	XBRL Taxonomy Extension Schema Document
101.CAL			—	XBRL Taxonomy Extension Calculation Document
101.DEF			—	XBRL Taxonomy Extension Definition Document
101.LAB			—	XBRL Taxonomy Extension Labels Document
101.PRE			—	XBRL Taxonomy Extension Presentation Document

____________

* Incorporated herein by reference

** Certain instruments defining the rights of holders of debt of the Company’s subsidiaries included in the financial statements filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10 percent of the total assets of the Company and its subsidiaries on a consolidated basis. The Company hereby agrees, upon request of the SEC, to furnish a copy of any such omitted instrument.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Energy Future Holdings Corp. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		ENERGY FUTURE HOLDINGS CORP.
Date:	February 29, 2016	By	/s/ JOHN F. YOUNG
			(John F. Young, President and Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Energy Future Holdings Corp. and in the capacities and on the date indicated.

Signature	Title	Date
/s/ JOHN F. YOUNG	Principal Executive	February 29, 2016
(John F. Young, President and Chief Executive Officer)	Officer and Director
/s/ PAUL M. KEGLEVIC	Principal Financial Officer	February 29, 2016
(Paul M. Keglevic, Executive Vice President, Chief Financial Officer and Co-Chief Restructuring Officer)
/s/ TERRY L. NUTT	Principal Accounting Officer	February 29, 2016
(Terry L. Nutt, Senior Vice President and Controller)
/s/ DONALD L. EVANS	Director	February 29, 2016
(Donald L. Evans, Chairman of the Board)
/s/ ARCILIA C. ACOSTA	Director	February 29, 2016
(Arcilia C. Acosta)
/s/ DAVID BONDERMAN	Director	February 29, 2016
(David Bonderman)
/s/ THOMAS D. FERGUSON	Director	February 29, 2016
(Thomas D. Ferguson)
/s/ BRANDON A. FREIMAN	Director	February 29, 2016
(Brandon A. Freiman)
/s/ SCOTT LEBOVITZ	Director	February 29, 2016
(Scott Lebovitz)
/s/ MICHAEL MACDOUGALL	Director	February 29, 2016
(Michael MacDougall)
/s/ KENNETH PONTARELLI	Director	February 29, 2016
(Kenneth Pontarelli)
/s/ WILLIAM K. REILLY	Director	February 29, 2016
(William K. Reilly)
/s/ JONATHAN D. SMIDT	Director	February 29, 2016
(Jonathan D. Smidt)
/s/ BILLIE I. WILLIAMSON	Director	February 29, 2016
(Billie I. Williamson)
/s/ KNEELAND YOUNGBLOOD	Director	February 29, 2016
(Kneeland Youngblood)

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