Energy Future Competitive Holdings Co LLC - FORM 10-Q - July 31, 2015

Attached files

file filename
EX-99.A - EXHIBIT 99.A TWELVE MONTH INCOME STATEMENT - Energy Future Competitive Holdings Co LLCexhibit99a-twelvemonthinco.htm
EX-99.B - EXHIBIT 99.B EBITDA - Energy Future Competitive Holdings Co LLCexhibit99b-tcehebitdarecon.htm
EX-32.A - EXHIBIT 32.A CHIEF EXECUTIVE OFFICER CERTIFICATION - Energy Future Competitive Holdings Co LLCexhibit32a-906certificatio.htm
EX-32.B - EXHIBIT 32.B CHIEF FINANCIAL OFFICER CERTIFICATION - Energy Future Competitive Holdings Co LLCexhibit32b-906certificatio.htm
EX-31.B - EXHIBIT 31.B CHIEF FINANCIAL OFFICER CERTIFICATION - Energy Future Competitive Holdings Co LLCexhibit31b-302certificatio.htm
EX-95.A - EXHIBIT 95.A MINE SAFETY DISCLOSURE - Energy Future Competitive Holdings Co LLCexhibit95a-minesafetydiscl.htm
EX-31.A - EXHIBIT 31.A CHIEF EXECUTIVE OFFICER CERTIFICATION - Energy Future Competitive Holdings Co LLCexhibit31a-302certificatio.htm

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 


FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2015
— OR —
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-34543
Energy Future Competitive Holdings Company LLC
(Exact name of registrant as specified in its charter)
 
 
Delaware
75-1837355
(State 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)
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 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 July 31, 2015, the outstanding membership interest in Energy Future Competitive Holdings Company LLC was directly held by Energy Future Holdings Corp.



 


TABLE OF CONTENTS

 
 
PAGE
 
PART I.
 
Item 1.
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
PART II.
 
Item 1.
Item 1A.
Item 4.
Item 6.

Energy Future Competitive Holdings Company LLC's (EFCH) 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 Energy Future Holdings Corp. (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. EFCH also from time to time makes available to the public, free of charge, on the EFH Corp. website certain financial statements of its wholly owned subsidiary, Texas Competitive Electric Holdings Company LLC. The information on EFH Corp.'s website shall not be deemed a part of, or incorporated by reference into, this quarterly report on Form 10-Q. The representations and warranties contained in any agreement that EFCH has filed as an exhibit to this quarterly report on Form 10-Q, or that EFCH has 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 quarterly report on Form 10-Q and other Securities and Exchange Commission filings of EFCH and its subsidiaries occasionally make references to EFCH, TCEH, TXU Energy or Luminant (or "we," "our," "us" or "the Company") 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 relevant 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.
 
 
 
2014 Form 10-K
  
EFCH's Annual Report on Form 10-K for the year ended December 31, 2014
 
 
 
CAIR
  
Clean Air Interstate Rule
 
 
 
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


 
 
 
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-Q (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.

 
 
 
CSAPR
 
the final Cross-State Air Pollution Rule issued by the EPA in July 2011

 
 
 
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
 
Amended Disclosure Statement for the Debtors' Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code filed by the Debtors with the Bankruptcy Court in July 2015, as it may be amended, modified or supplemented from time to time.
 
 
 
D.C. Circuit Court
 
US Court of Appeals for the District of Columbia Circuit
 
 
 
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 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
 
 
 
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 Agreement
 
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.  See Management's Discussion and Analysis, under Financial Condition.

 
 
 
Fifth Circuit Court
 
US Court of Appeals for the Fifth Circuit
 
 
 
GAAP
  
generally accepted accounting principles
 
 
 

ii

GWh
  
gigawatt-hours
 
 
 
ICE
 
the IntercontinentalExchange, an electronic commodity derivative exchange
 
 
 
IRS
 
US Internal Revenue Service
 
 
 
LIBOR
  
London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
 
 
 
Luminant
  
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.
 
 
 
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
 
 
 
MW
  
megawatts
 
 
 
MWh
  
megawatt-hours
 
 
 
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
 
Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code filed by the Debtors with the Bankruptcy Court in July 2015, as it may be amended, modified or supplemented from time to time
 
 
 
PUCT
  
Public Utility Commission of Texas
 
 
 
purchase accounting
  
The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or "purchase price" of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
 
 
 
REP
  
retail electric provider
 
 
 

iii

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
 
 
 
SG&A
  
selling, general and administrative
 
 
 
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 DIP Facility
 
TCEH's $3.375 billion debtor-in-possession financing facility approved by the Bankruptcy Court in June 2014 (see Note 8 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 $5.237 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 $22.635 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.
 
 
 
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

iv

PART I. FINANCIAL INFORMATION

Item 1.
FINANCIAL STATEMENTS

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC
A DEBTOR-IN-POSSESSION
CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)
(Unaudited)


 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(millions of dollars)
Operating revenues
$
1,256

 
$
1,406

 
$
2,527

 
$
2,924

Fuel, purchased power costs and delivery fees
(646
)
 
(656
)
 
(1,259
)
 
(1,388
)
Net gain (loss) from commodity hedging and trading activities
20

 
27

 
123

 
(192
)
Operating costs
(217
)
 
(242
)
 
(410
)
 
(455
)
Depreciation and amortization
(219
)
 
(329
)
 
(434
)
 
(656
)
Selling, general and administrative expenses
(161
)
 
(169
)
 
(321
)
 
(364
)
Impairment of goodwill (Note 3)
—

 
—

 
(700
)
 
—

Impairment of long-lived assets (Note 5)
—

 
(21
)
 
(676
)
 
(21
)
Other income (Note 15)
8

 
2

 
11

 
7

Other deductions (Note 15)
(2
)
 
(2
)
 
(61
)
 
(3
)
Interest expense and related charges (Note 6)
(322
)
 
(447
)
 
(639
)
 
(1,112
)
Reorganization items (Note 7)
(40
)
 
(423
)
 
(114
)
 
(423
)
Loss before income taxes
(323
)
 
(854
)
 
(1,953
)
 
(1,683
)
Income tax benefit (Note 4)
107

 
269

 
400

 
553

Net loss
$
(216
)
 
$
(585
)
 
$
(1,553
)
 
$
(1,130
)

See Notes to the Financial Statements.



CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Unaudited)

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(millions of dollars)
Net loss
$
(216
)
 
$
(585
)
 
$
(1,553
)
 
$
(1,130
)
Other comprehensive income, net of tax effects – cash flow hedges derivative value net loss related to hedged transactions recognized during the period (net of tax benefit of $— in all periods)
—

 
1

 
1

 
1

Comprehensive loss
$
(216
)
 
$
(584
)
 
$
(1,552
)
 
$
(1,129
)

See Notes to the Financial Statements.



1

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC
A DEBTOR-IN-POSSESSION
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
 
Six Months Ended June 30,
 
2015
 
2014
 
(millions of dollars)
Cash flows — operating activities:
 
 
 
Net loss
$
(1,553
)
 
$
(1,130
)
Adjustments to reconcile net loss to cash used in operating activities:
 
 
 
Depreciation and amortization
507

 
736

Deferred income tax benefit, net
(417
)
 
(581
)
Fees paid for TCEH DIP Facility (Note 8) (reported as financing activities)
—

 
92

Impairment of goodwill (Note 3)
700

 
—

Impairment of long-lived assets (Note 5)
676

 
21

Contract claims adjustments (Note 7)
28

 
—

Unrealized net (gain) loss from mark-to-market valuations of commodity positions
(74
)
 
549

Unrealized net gain from mark-to-market valuations of interest rate swaps (Note 6)
—

 
(1,290
)
Liability adjustment arising from termination of interest rate swaps (Note 13)
—

 
277

Noncash realized loss on termination of interest rate swaps (Note 6)
—

 
1,225

Noncash realized gain on termination of natural gas hedging positions (Note 13)
—

 
(117
)
Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 6)
1

 
87

Impairment of intangible assets (Note 3)
59

 
—

Other, net
28

 
36

Changes in operating assets and liabilities:
 
 
 
Margin deposits, net
46

 
(300
)
Accrued interest
(3
)
 
477

Other operating assets and liabilities, including liabilities subject to compromise
(214
)
 
(128
)
Cash used in operating activities
(216
)
 
(46
)
Cash flows — financing activities:
 
 
 
Proceeds from TCEH DIP Facility before fees paid (Note 8)
—

 
1,425

Fees paid for TCEH DIP Facility (Note 8)
—

 
(92
)
Repayments/repurchases of debt (Notes 8 and 9)
(11
)
 
(212
)
Other, net
—

 
1

Cash provided by (used in) financing activities
(11
)
 
1,122

Cash flows — investing activities:
 
 
 
Capital expenditures
(209
)
 
(193
)
Nuclear fuel purchases
(11
)
 
(36
)
Settlements of notes/advances due from affiliates
—

 
(17
)
Changes in restricted cash
(4
)
 
310

Proceeds from sales of nuclear decommissioning trust fund securities
73

 
85

Investments in nuclear decommissioning trust fund securities
(81
)
 
(93
)
Other, net
9

 
—

Cash provided by (used in) investing activities
(223
)
 
56

Net change in cash and cash equivalents
(450
)
 
1,132

Cash and cash equivalents — beginning balance
1,843

 
746

Cash and cash equivalents — ending balance
$
1,393

 
$
1,878


See Notes to the Financial Statements.

2

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC
A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
June 30,
2015
 
December 31,
2014
 
(millions of dollars)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
1,393

 
$
1,843

Restricted cash (Note 15)
401

 
2

Trade accounts receivable — net (Note 15)
680

 
588

Advance to parent (Note 14)
6

 
8

Inventories (Note 15)
441

 
468

Commodity and other derivative contractual assets (Note 13)
396

 
492

Other current assets
61

 
68

Total current assets
3,378

 
3,469

Restricted cash (Note 15)
506

 
901

Advance to parent (Note 14)
5

 
7

Investments (Note 15)
950

 
941

Property, plant and equipment — net (Note 15)
11,398

 
12,288

Goodwill (Note 3)
1,652

 
2,352

Identifiable intangible assets — net (Note 3)
1,211

 
1,336

Commodity and other derivative contractual assets (Note 13)
17

 
5

Other noncurrent assets
44

 
34

Total assets
$
19,161

 
$
21,333

 
 
 
 
LIABILITIES AND MEMBERSHIP INTERESTS
 
 
 
Current liabilities:
 
 
 
Borrowings under debtor-in-possession credit facility (Note 8)
$
1,425

 
$
—

Long-term debt due currently (Note 8)
31

 
35

Trade accounts payable
357

 
382

Trade accounts and other payables to affiliates
160

 
165

Commodity and other derivative contractual liabilities (Note 13)
168

 
316

Margin deposits related to commodity contracts
64

 
26

Accumulated deferred income taxes
110

 
114

Accrued income taxes payable to parent (Note 14)
1

 
16

Accrued taxes other than income
66

 
107

Accrued interest (Notes 6 and 9)
114

 
117

Other current liabilities
236

 
264

Total current liabilities
2,732

 
1,542

Borrowings under debtor-in-possession credit facility (Note 8)
—

 
1,425

Long-term debt, less amounts due currently (Note 8)
79

 
85

Liabilities subject to compromise (Note 9)
34,015

 
34,033

Accumulated deferred income taxes
639

 
1,022

Commodity and other derivative contractual liabilities (Note 13)
4

 
1

Other noncurrent liabilities and deferred credits (Note 15)
1,707

 
1,699

Total liabilities
39,176

 
39,807

Commitments and Contingencies (Note 10)

 

Membership interests (Note 11):
(20,015
)
 
(18,474
)
Total liabilities and membership interests
$
19,161

 
$
21,333


See Notes to the Financial Statements.

3

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC
A DEBTOR-IN-POSSESSION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

 
1.     BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

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

EFCH, a Delaware limited liability company and a wholly owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. We conduct our operations almost entirely through our wholly owned subsidiary, TCEH. 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. Key management activities, including commodity risk management and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis; consequently, there are no reportable business segments.

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, (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 July 2015, the Debtors filed with the Bankruptcy Court the Plan of Reorganization and the Disclosure Statement. See Note 2 for further discussion regarding the Chapter 11 Cases and our recent filing of the Plan of Reorganization and the Disclosure Statement.

Basis of Presentation, Including Application of Bankruptcy Accounting

The condensed consolidated financial statements have been prepared in accordance with US GAAP. The condensed consolidated financial statements have been prepared as if EFCH is a going concern and contemplate the realization of assets and liabilities in the normal course of business. The condensed 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 7 and 9 for discussion of these accounting and reporting changes.

Adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in our 2014 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.


4

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). Prior to the fourth quarter of 2014, we consolidated as a VIE Comanche Peak Nuclear Power Company LLC (CPNPC), a joint venture formed by subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our existing Comanche Peak nuclear fueled generation facility. In the fourth quarter of 2014, the MHI subsidiary withdrew from the joint venture. As a result, the TCEH subsidiary owns 100% of CPNPC, CPNPC no longer qualifies as a VIE and CPNPC is now consolidated as a wholly owned subsidiary. Activity related to the VIE in the six months ended June 30, 2014 was immaterial. There are no material investments accounted for under the equity or cost method.

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.

Changes in Accounting Standards

In April 2014, the FASB issued ASU No. 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 and financial 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 is effective for the Company for the first quarter of 2015. This new requirement is relevant to our presentation of TCEH. Based on our analysis, ASU 2014-08 will not materially affect our results of operations, financial position, or cash flows, unless a spin-off of TCEH is approved by the Bankruptcy Court (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 within those periods, beginning after December 15, 2015. Early adoption is permitted. 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. During the Chapter 11 Cases, debt issuance costs on prepetition debt subject to compromise will continue to be reported in liabilities subject to compromise.

In May 2015, the FASB issued Accounting Standards Update 2015-07 (ASU 2015-07) Disclosures for Investments in Certain Entities that Calculate Net Asset Value Per Share (or its Equivalent). The ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, with retrospective application to all periods presented. Early adoption is permitted. ASU 2015-07 removes the requirement to categorize within the fair value hierarchy investments for which fair values are estimated using the net asset value practical expedient provided by Accounting Standards Codification 820, Fair Value Measurement. Disclosures about investments in certain entities that calculate net asset value per share are limited under ASU 2015-07 to those investments for which the entity has elected to estimate the fair value using the net asset value practical expedient. We are currently evaluating the impact of the adoption of this ASU on our financial statements.


5

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.

Proposed 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 and is subject to the ultimate outcome of stakeholder negotiations and Bankruptcy Court decisions ongoing through the date on which the Chapter 11 plan is confirmed. 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. The Debtors have the exclusive right to file a Chapter 11 plan of reorganization in the Chapter 11 Cases through October 29, 2015 and the exclusive right to solicit the appropriate votes for any such plan it filed prior to such date until December 29, 2015 (collectively, the exclusivity period).

In July 2015, the Debtors filed with the Bankruptcy Court the Plan of Reorganization and the Disclosure Statement. In general, the Plan of Reorganization proposes a structure that involves a tax-free deconsolidation or tax-free spin-off of TCEH from EFH Corp. (Reorganized TCEH) and the reorganization of EFH Corp. and EFIH either (a) pursuant to a standalone plan of reorganization or (b) pursuant to a plan of reorganization backstopped by existing creditors and third-party investors. Pursuant to the Plan of Reorganization, among other things, holders of TCEH first lien secured claims would receive 100% of the common stock of Reorganized TCEH and 100% of the proceeds of new debt issued by Reorganized TCEH. Also, pursuant to the Plan of Reorganization, the Debtors would select the highest or otherwise best transaction to maximize value for reorganized EFH Corp. and EFIH.

The Plan of Reorganization is subject to revision in response to creditor and/or stakeholder claims and objections and the requirements of the Bankruptcy Code and/or the Bankruptcy Court. Unless the Plan of Reorganization receives the requisite approval from holders of claims and the Bankruptcy Court, upon expiration of the exclusivity period (which has already been extended to the maximum period permitted by the Bankruptcy Code, but which has been, as described below, contractually extended with certain creditors), any creditor or stakeholder would have the ability to file in the Chapter 11 Cases one or more Chapter 11 plans of reorganization. Under an agreed stipulation approved by the Bankruptcy Court, if the exclusivity period has not been terminated by December 29, 2015, certain creditor constituencies have agreed that they will not file a chapter 11 plan of reorganization (or a disclosure statement) or cause such a filing until the Bankruptcy Court issues a final ruling regarding the confirmation of the Plan of Reorganization and that until the issuance of such a ruling, the Debtors will prosecute the Plan of Reorganization with reasonable diligence.

The Disclosure Statement contains, among other things, detailed information about the Plan of Reorganization, a historical profile of our businesses, a description of proposed distributions to creditors under the Plan of Reorganization, and an analysis of the Plan of Reorganization's feasibility, as well as many of the technical matters required for the Debtors to exit from bankruptcy, such as descriptions of who will be eligible to vote on the Plan of Reorganization and the voting process itself. The information contained in the Disclosure Statement is subject to change, for a number of reasons, including amendments to the Plan of Reorganization, actions of third parties, including the Bankruptcy Court, or otherwise.


6

The Plan of Reorganization and the Disclosure Statement contain or discuss certain projections of certain of the Debtors' financial performance for fiscal years 2015 through 2020. The Debtors do not, as a matter of course, publish their business plans, budgets or strategies, or make external projections or forecasts of their anticipated financial position or results of operations. The projections reflected numerous assumptions concerning our anticipated future performance and prevailing and anticipated market and economic conditions at the time they were prepared that were and continue to be beyond our control and that may not materialize. Projections are inherently subject to uncertainties and to a wide variety of significant business, economic and competitive risks, including those risks discussed in Part I, Item 1A. Risk Factors in our 2014 Form 10-K and our subsequent quarterly reports on Form 10-Q. Our actual results will vary from those contemplated by the projections and the variations may be material.

Nothing contained in this quarterly report on Form 10-Q is intended to be, nor should it be construed as, a solicitation for a vote on the Plan of Reorganization, as filed or as it may be amended. The Plan of Reorganization will become effective only if it receives the requisite approval and is confirmed by the Bankruptcy Court and the conditions to consummation set forth therein are satisfied. There can be no assurance that the Bankruptcy Court will approve the Disclosure Statement, that the Debtors' stakeholders will approve the Plan of Reorganization, that the Bankruptcy Court will confirm the Plan of Reorganization or that the conditions to consummation of the Plan of Reorganization will be satisfied.

Proposed Sale of EFH Corp.'s Indirect Economic Ownership Interest in Oncor

In September 2014, the Debtors filed a motion with the Bankruptcy Court seeking the entry of an order approving bidding procedures with respect to the potential sale of EFH Corp.'s indirect economic ownership interest in Oncor. In January 2015, the Bankruptcy Court approved the Debtors' bidding procedures motion that sets forth the process by which the Debtors are authorized to solicit proposals (i.e., bids) from third parties to acquire (in any form and employing any structure, whether taxable (in whole or in part) or tax-free) EFH Corp.'s indirect economic ownership interest in Oncor in accordance with the Bankruptcy Code. These bidding procedures contemplated that the Debtors select a stalking horse bid after a two-stage closed bidding process, and, after approval by the Bankruptcy Court of such stalking horse bid, the Debtors conduct a round of open bidding culminating in an auction intended to obtain a higher or otherwise best bid for a transaction. Initial bids were received in early March 2015 and second round bids were received in April 2015. Following receipt and negotiation of second round bids, the Debtors elected not to select a stalking horse bid. The Debtors continue to engage in discussions with various interested parties regarding the formal auction process as well as potential transactions in the context of modifications to, or alternatives to, the Plan of Reorganization. Certain of the potential transactions the Debtors are discussing with certain creditor constituencies would involve converting Oncor into a real estate investment trust (a REIT).

Scheduling Matters

In July 2015, the Bankruptcy Court issued an order establishing (a) August 18, 2015 as the date for the hearing to approve the Disclosure Statement and (b) January 20, 2016 as the date for the hearing to confirm the Plan of Reorganization, provided that, if certain circumstances are met, the date for the hearing to confirm the Plan of Reorganization could potentially commence on October 5, 2015. These dates could be changed by the Bankruptcy Court (on its own, upon the motion of a party or upon the Debtors' request).

Mediation

In May 2015, the Bankruptcy Court issued an order authorizing and establishing mediation between the Debtors and certain TCEH stakeholders with respect to Plan of Reorganization issues that affect the TCEH Debtors' estates. In July 2015, the parties to the mediation and the mediator agreed to extend mediation to October 31, 2015 unless otherwise extended or terminated by the Bankruptcy Court or the mediator.


7

Tax Matters

In June 2014, EFH Corp. filed a request with the IRS for a private letter ruling (Private Letter Ruling) that, among other things, will provide (a) that (i) the transfer by TCEH of all of its assets and its ordinary course operating liabilities to reorganized TCEH completed through a tax-free spin (in accordance with the Private Letter Ruling) in connection with TCEH's emergence from bankruptcy (Reorganized TCEH), (ii) the transfer by the Debtors to Reorganized TCEH of certain assets and liabilities that are reasonably necessary to the operation of Reorganized TCEH and (iii) the distribution by TCEH of (A) the equity it holds in Reorganized TCEH and (B) the cash proceeds TCEH receives from Reorganized TCEH to the holders of TCEH first lien claims, will qualify as a reorganization within the meaning of Sections 368(a)(1)(G), 355 and 356 of the Code and (b) for certain other rulings under Sections 368(a)(1)(G) and 355 of the Code. The Debtors intend to continue to pursue the Private Letter Ruling to support the Plan of Reorganization and other potential Chapter 11 plans of reorganization that could ultimately be proposed. In October 2014, the Debtors filed a memorandum with the Bankruptcy Court that described tax related matters regarding restructuring alternatives.

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 TCEH DIP Facility described in Note 8, our ability to obtain new debtor in possession financing in the event the TCEH DIP Facility was to expire during the pendency of the Chapter 11 Cases and our ability to complete a Chapter 11 plan of reorganization in a timely manner, including obtaining creditor and Bankruptcy Court approval of such plan as well as applicable regulatory approvals required for such plan and obtaining any exit financing needed to implement such plan. 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 TCEH DIP Facility discussed in Note 8.

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. The Debtors have received approximately 10,000 filed claims since the Petition Date. The Debtors 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 July 31, 2015, approximately 4,500 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. 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.


8

Beginning 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 condensed consolidated balance sheets will be recognized as reorganization items in our statements of condensed consolidated income (loss) as they are resolved. The determination of how liabilities will ultimately be resolved cannot be made until the Bankruptcy Court approves a plan of reorganization or approves orders related to settlement of specific liabilities. 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 three and six months ended June 30, 2015, this activity has resulted in the recognition of approximately a $2 million benefit and a $28 million expense, respectively, in contract claim adjustment charges recorded in reorganization items as detailed in Note 7.



9

3.     GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides information regarding our goodwill balance, all of which arose in connection with accounting for the Merger. None of the goodwill is being deducted for tax purposes.
Goodwill before impairment charges
$
18,322

Accumulated noncash impairment charges
(15,970
)
Balance at December 31, 2014
2,352

Additional noncash impairment charge in 2015
(700
)
Balance at June 30, 2015 (a)
$
1,652

____________
(a)
Net of accumulated impairment charges totaling $16.67 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 TCEH 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 TCEH exceeds its estimated fair value (enterprise value). Consequently, we continually monitor trends in 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 three months ended March 31, 2015, we experienced an impairment indicator 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 as of March 31, 2015. We completed our testing of goodwill for impairment during the period, which resulted in an impairment of $700 million of goodwill at March 31, 2015. There were no significant changes to market factors identified in the three months ended June 30, 2015 and thus there was no change to the goodwill balance during this same period.

There was no change to the goodwill balance for the three and six months ended June 30, 2014.


10

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

•
The carrying value (excluding debt) of TCEH exceeded its estimated enterprise value by approximately 34% at March 31, 2015 and by 17% at December 1, 2014.

•
The fair value of TCEH 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% and 6.25% at March 31, 2015 and December 1, 2014, respectively. 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.

The impairment determinations involved significant assumptions and judgments. The calculations supporting the estimates of the fair value of our business 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 TCEH 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 12). Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.

Identifiable Intangible Assets

Identifiable intangible assets, including amounts that arose in connection with accounting for the Merger, are comprised of the following:
 
 
June 30, 2015
 
December 31, 2014
Identifiable Intangible Asset
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net
Retail customer relationship
 
$
463

 
$
433

 
$
30

 
$
463

 
$
425

 
$
38

Software and other technology-related assets
 
367

 
201

 
166

 
369

 
202

 
167

Other identifiable intangible assets (a)
 
80

 
26

 
54

 
460

 
291

 
169

Total identifiable intangible assets subject to amortization
 
$
910

 
$
660

 
250

 
$
1,292

 
$
918

 
374

Retail trade name (not subject to amortization)
 
 
 
 
 
955

 
 
 
 
 
955

Mineral interests (not currently subject to amortization)
 
 
 
 
 
6

 
 
 
 
 
7

Total identifiable intangible assets
 
 
 
 
 
$
1,211

 
 
 
 
 
$
1,336

____________
(a)
See discussion below regarding impairment charges recorded in the three months ended March 31, 2015 related to other identifiable intangible assets.


11

At June 30, 2015 and December 31, 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 condensed statements of consolidated income (loss) line item) consisted of:
Identifiable Intangible Asset
 
Condensed Statement of Consolidated Income (Loss) Line
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2015
 
2014
 
2015
 
2014
Retail customer relationship
 
Depreciation and amortization
 
$
4

 
$
6

 
$
9

 
$
11

Software and other technology-related assets
 
Depreciation and amortization
 
15

 
15

 
28

 
30

Other identifiable intangible assets
 
Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization
 
7

 
18

 
12

 
36

Total amortization expense (a)
 
 
 
$
26

 
$
39

 
$
49

 
$
77

_______________
(a)
Amounts recorded in depreciation and amortization totaled $22 million and $29 million for the three months ended June 30, 2015 and 2014, respectively, and $39 million and $58 million for the six months ended June 30, 2015 and 2014, respectively.

Intangible Impairments

During the three months ended March 31, 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 three months ended March 31, 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 prices in ERCOT. As a result of the analysis, we recorded a noncash impairment charge of $8 million (before deferred income tax benefit) in other deductions (see Note 15).

The impairment of our Big Brown generation facility (see Note 5) resulted in the impairment of the SO2 allowances under the Clean Air Act's acid rain cap-and-trade program that are associated with that facility 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 12). Accordingly, in the three months ended March 31, 2015 we recorded a noncash impairment charge of $51 million (before deferred income tax benefit) in other deductions related to our existing environmental allowances and credits intangible asset. 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.

There were no impairments to intangible assets during the three months ended June 30, 2015.

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
2015
 
$
86

2016
 
$
68

2017
 
$
53

2018
 
$
29

2019
 
$
14




12

4.
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 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. 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 calculation of our effective tax rate is as follows:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Loss before income taxes
$
(323
)
 
$
(854
)
 
$
(1,953
)
 
$
(1,683
)
Income tax benefit
$
107

 
$
269

 
$
400

 
$
553

Effective tax rate
33.1
%
 
31.5
%
 
20.5
%
 
32.9
%

For the three months ended June 30, 2015, the effective tax rate of 33.1% related to our income tax benefit was lower than the US Federal statutory rate of 35% due primarily to the nondeductible legal and other professional services costs related to the Chapter 11 Cases, partially offset by the tax benefit recognized due to the Texas margin tax rate reduction in 2015. For the three months ended June 30, 2014, the effective tax rate of 31.5% related to our income tax benefit was lower than the US Federal statutory rate of 35% due primarily to nondeductible legal and other professional services costs related to the Chapter 11 Cases.

For the six months ended June 30, 2015, the effective tax rate of 20.5% related to our income tax benefit was lower than the US Federal statutory rate of 35% due primarily to the nondeductible goodwill impairment charge (see Note 3) and nondeductible legal and other professional services costs related to the Chapter 11 Cases, partially offset by the difference in the forecasted effective tax rate and the statutory rate applied to long-lived and intangible asset impairment charges (see Notes 3 and 5) and the tax benefit recognized due to the Texas margin tax rate reduction in the three months ended June 30, 2015. For the six months ended June 30, 2014, the effective tax rate of 32.9% related to our income tax benefit was lower than the US Federal statutory rate of 35% due primarily to nondeductible legal and other professional services costs related to the Chapter 11 Cases.

Liability for Uncertain Tax Positions

In June 2015, EFH Corp. 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 EFH Corp.'s signing of the RAR in July 2015. As a result of EFH Corp. receiving, agreeing to and signing the RAR, we reduced the liability for uncertain tax positions by $22 million, resulting in an $18 million increase in noncurrent inter-company tax payable to EFH Corp., a $2 million reclassification to the accumulated deferred income tax liability and the recording of a $2 million income tax benefit.


13

5.
IMPAIRMENT OF LONG-LIVED ASSETS

Impairment of Lignite/Coal Fueled Generation and Mining Assets

We evaluated our generation assets for impairment during March 2015 as a result of an impairment indicator related to lower forecasted wholesale electricity prices in ERCOT. Our evaluation concluded that an impairment existed at our Big Brown generation facility, and the carrying value for that facility and related mining facility was reduced by $676 million. 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 12). 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 July 2015, we filed notice with ERCOT that we intend to seasonally suspend operations at a second of the three units at our Martin Lake generation facility, with the units returning to service for the peak demand months of summer. In June 2015, we also assessed whether this planned notice constituted an impairment indicator for the Martin Lake generation facility and concluded that since the decision is expected to result in improved cash flows for the plant, it was not an indicator of impairment.

In the three months ended June 30, 2014, we wrote off previously incurred and deferred costs totaling $21 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.

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.


14

6.     INTEREST EXPENSE AND RELATED CHARGES

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Interest paid/accrued on debtor-in-possession financing
$
16

 
$
6

 
$
31

 
$
6

Adequate protection amounts paid/accrued (a)
307

 
211

 
609

 
211

Interest paid/accrued on pre-petition debt (b)
2

 
214

 
4

 
883

Interest related to pushed down debt
—

 
—

 
—

 
1

Noncash realized net loss on termination of interest rate swaps (offset in unrealized net gain) (c)
—

 
1,225

 
—

 
1,225

Unrealized mark-to-market net gain on interest rate swaps
—

 
(1,226
)
 
—

 
(1,290
)
Amortization of debt issuance, amendment and extension costs and discounts
—

 
20

 
—

 
85

Capitalized interest
(3
)
 
(4
)
 
(6
)
 
(11
)
Other
—

 
1

 
1

 
2

Total interest expense and related charges
$
322

 
$
447

 
$
639

 
$
1,112

____________
(a)
Post-petition period only.
(b)
Includes amounts related to interest rate swaps totaling zero and $48 million for the three months ended June 30, 2015 and 2014, respectively, and zero and $193 million for the six months ended June 30, 2015 and 2014, respectively.
(c)
See Note 13.

Interest expense for the six months ended June 30, 2015 reflects interest paid and accrued on debtor-in-possession financing (see Note 8), adequate protection amounts paid and accrued, as approved by the Bankruptcy Court in June 2014 for the benefit of secured creditors of (a) $22.635 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 $1.235 billion net liability related to the TCEH interest rate swaps and natural gas hedging positions terminated shortly after the Bankruptcy Filing (see Note 13), 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. The interest rate applicable to the adequate protection amounts paid/accrued for the six months ended June 30, 2015 is 4.68% (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.

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. 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 condensed statements of consolidated income (loss) for the three and six months ended June 30, 2015 and the post-petition period ended June 30, 2014 does not include $227 million, $452 million and $156 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 three and six months ended June 30, 2015 and the post-petition period ended June 30, 2014, adequate protection paid/accrued presented below excludes $15 million, $29 million and $10 million, respectively, related to interest paid/accrued on the TCEH first-lien interest rate and commodity hedge claims (see Note 13), as such amounts are not included in contractual interest amounts below.

 
 
Three Months Ended June 30, 2015
Entity:
 
Contractual Interest on
Debt Classified as LSTC
 
Adequate Protection
Paid/Accrued
 
Contractual Interest on
Debt Classified as LSTC Not
Paid/Accrued
EFCH
 
$
2

 
$
—

 
$
2

TCEH
 
516

 
291

 
225

Total
 
$
518

 
$
291

 
$
227



15

 
 
Six Months Ended June 30, 2015
Entity:
 
Contractual Interest on
Debt Classified as LSTC
 
Adequate Protection
Paid/Accrued
 
Contractual Interest on
Debt Classified as LSTC Not
Paid/Accrued
EFCH
 
$
3

 
$
—

 
$
3

TCEH
 
1,029

 
580

 
449

Total
 
$
1,032

 
$
580

 
$
452


 
 
Post-Petition Period Ended June 30, 2014
Entity:
 
Contractual Interest on
Debt Classified as LSTC
 
Adequate Protection
Paid/Accrued
 
Contractual Interest on
Debt Classified as LSTC Not
Paid/Accrued
EFCH
 
$
1

 
$
—

 
$
1

TCEH
 
356

 
201

 
155

Total
 
$
357

 
$
201

 
$
156




16

7.
REORGANIZATION ITEMS

Expenses and income directly associated with the Chapter 11 Cases are reported separately in the condensed 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 three and six months ended June 30, 2015 and the post-petition period ended June 30, 2014 as reported in the condensed statements of consolidated income (loss):
 
Three Months Ended
June 30, 2015
 
Six Months Ended
June 30, 2015
 
Post-Petition Period Ended
June 30, 2014
Noncash liability adjustment arising from termination of interest rate swaps (Note 13)
$
—

 
$
—

 
$
277

Fees associated with completion of TCEH DIP Facility
—

 
—

 
92

Expenses related to legal advisory and representation services
24

 
50

 
21

Expenses related to other professional consulting and advisory services
17

 
33

 
32

Contract claims adjustments
(2
)
 
28

 
—

Other
1

 
3

 
1

Total reorganization items
$
40

 
$
114

 
$
423




17

8.
DEBTOR-IN-POSSESSION BORROWING FACILITY 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 June 30, 2015 are presented below. Borrowings are reported in the condensed consolidated balance sheets as borrowings under debtor-in-possession credit facilities. In the June 30, 2015 condensed consolidated balance sheet the borrowings under the TCEH DIP Facility are reported as current liabilities since the maturity date of the facility is May 2016.
 
 
June 30, 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

 
—

 
401

Total TCEH DIP Facility
 
$
3,375

 
$
1,950

 
$
401

___________
(a)
Facility used for general corporate purposes. No amounts were borrowed at June 30, 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 June 30, 2015 and December 31, 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 June 30, 2015, $401 million is reported as cash and cash equivalents and $399 million is reported as restricted cash, which represents the amount of outstanding letters of credit.

Amounts borrowed under the TCEH DIP Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 3%. At both June 30, 2015 and December 31, 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 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 TCEH's assets or (c) May 2016. The maturity date may be extended to no later than November 2016 subject to the satisfaction of certain conditions, including the payment of a 25 basis point extension fee, a requirement that an acceptable plan of reorganization has been filed on or prior to such extension and the availability of certain metrics of liquidity applicable to the TCEH Debtors. In addition, TCEH's existing cash collateral order expires in October 2015. The expiration of the cash collateral order is an event of default under the TCEH DIP Facility. Accordingly, absent an extension of the existing cash collateral order or a new cash collateral order (acceptable to the facility's lead arrangers and the Bankruptcy Court), the lenders under the TCEH DIP Facility could accelerate the obligations under the 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.


18

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.

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 beginning with the test period ending June 30, 2014. 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.

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.
 
June 30,
2015
 
December 31,
2014
EFCH
 
 
 
9.58% Fixed Notes due in annual installments through December 4, 2019 (a)
$
21

 
$
21

8.254% Fixed Notes due in quarterly installments through December 31, 2021 (a)
26

 
29

Unamortized fair value discount (b)
(3
)
 
(3
)
Total EFCH
44

 
47

TCEH
 
 
 
7.48% Fixed Secured Facility Bonds with amortizing payments through January 2017 (c)
23

 
25

7.46% Fixed Secured Facility Bonds with amortizing payments through January 2015 (c)
—

 
4

Capital lease obligations
42

 
44

Other
2

 
2

Unamortized discount
(1
)
 
(2
)
Total TCEH
66

 
73

Total EFCH consolidated
110

 
120

Less amounts due currently
(31
)
 
(35
)
Total long-term debt not subject to compromise
$
79

 
$
85

____________
(a)
Approved by the Bankruptcy Court for repayment.
(b)
Amount represents unamortized fair value adjustments recorded under purchase accounting.
(c)
Debt issued by trust and secured by assets held by the trust.



19

9.
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. 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 condensed consolidated balance sheets at June 30, 2015 and December 31, 2014:
 
June 30,
2015
 
December 31,
2014
Notes, loans and other debt per the following table
$
31,192

 
$
31,192

Accrued interest on notes, loans and other debt
668

 
668

Net liability under terminated TCEH interest rate swap and natural gas hedging agreements (Note 13)
1,235

 
1,235

Trade accounts payable and other expected allowed claims
184

 
179

Liability under the Federal and State Income Tax Allocation Agreement (Note 14)
605

 
626

Advances and other payables to affiliates
131

 
133

Total liabilities subject to compromise
$
34,015

 
$
34,033



20

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.

 
June 30,
2015
 
December 31, 2014
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

TCEH Floating Rate Term Loan Facilities due October 10, 2017 (a)
15,710

 
15,710

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)
2,046

 
2,046

10.25% Fixed Senior Notes due November 1, 2015, Series B (a)
1,442

 
1,442

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
)
 
(103
)
Other:

 

Other
1

 
1

Unamortized discount
(91
)
 
(91
)
Total TCEH
31,856

 
31,856

EFCH (parent entity)
 
 
 
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
)
 
(1
)
Subtotal
8

 
8

 
 
 
 
 
 
 
 

21


 
June 30, 2015

 
December 31, 2014
 
 
 
 
EFH Corp. pre-petition debt pushed down (c)
 
 
 
10.875% Fixed Senior Notes due November 1, 2017
16

 
16

11.25%/12.00% Senior Toggle Notes due November 1, 2017
14

 
14

Subtotal — EFH Corp. debt pushed down
30

 
30

Total EFCH (parent entity)
38

 
38

Deferred debt issuance and extension costs
(702
)
 
(702
)
Total EFCH consolidated notes, loans and other debt
$
31,192

 
$
31,192

____________
(a)
As discussed below and in Note 14, principal amounts of notes/term loans totaling $382 million at both June 30, 2015 and December 31, 2014 were held by EFH Corp. and EFIH.
(b)
Amount represents unamortized fair value adjustments recorded under purchase accounting.
(c)
Represents 50% of the amount of these EFH Corp. securities guaranteed by, and pushed down to (pushed-down debt), EFCH (parent entity) per the discussion below under "Guarantees and Push Down of EFH Corp. Pre-Petition Debt."

Guarantees and Push Down of EFH Corp. Pre-Petition Debt

Merger-related debt of EFH Corp. and its subsidiaries consists of debt issued or existing at the time of the Merger. Debt issued in exchange for Merger-related debt is considered Merger-related. Debt issuances for cash are considered Merger-related debt to the extent the proceeds are used to repurchase Merger-related debt. EFCH and EFIH (excluding their subsidiaries) fully and unconditionally guarantee on a joint and several basis the Merger-related debt of EFH Corp. (parent). Such debt is subject to push down in accordance with SEC Staff Accounting Bulletin Topic 5-J, and as a result, a portion of such debt and related interest expense is reflected in our financial statements. Merger-related debt of EFH Corp. held by its subsidiaries is not subject to push down.

Debt guaranteed and subject to push down at June 30, 2015 totals $60 million and consists of $33 million principal amount of EFH Corp. 10.875% Senior Notes and $27 million principal amount of EFH Corp. 11.25%/12.00% Senior Toggle Notes. The amount reflected in our condensed consolidated balance sheets as pushed down pre-petition debt ($30 million at both June 30, 2015 and December 31, 2014, as shown in the debt table above) represents 50% of the principal amount of the EFH Corp. Merger-related debt guaranteed. This percentage reflects the fact that at the time of the Merger, the equity investments of EFCH and EFIH in their respective operating subsidiaries were essentially equal amounts. Because payment of principal and interest on the debt is the responsibility of EFH Corp., we record the settlement of such amounts as noncash capital contributions from EFH Corp.

There were no payments of interest by EFH Corp. on pre-petition debt pushed down for the three and six months ended June 30, 2015 or 2014.

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 June 30, 2015, the restricted cash related to the pre-petition TCEH Letter of Credit Facility totaled $506 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 year ended December 31, 2014 and the six months ended June 30, 2015, $245 million and $45 million, respectively, of letters of credit have been drawn upon by counterparties to settle amounts due from TCEH. Included in the six months ended June 30, 2015 amount was $20 million drawn by certain executive officers to satisfy payments related to long-term incentive awards.

22

Information Regarding Significant Pre-Petition Debt

The TCEH pre-petition debt described below is junior in right of priority and payment to the TCEH DIP Facility.

TCEH Senior Secured Facilities — Borrowings under the TCEH Senior Secured Facilities total $22.635 billion and consist of:

•
$3.809 billion of TCEH Term Loan Facilities with interest at LIBOR plus 3.50%;
•
$15.710 billion of TCEH Term Loan Facilities with interest at LIBOR plus 4.50%, including $19 million aggregate principal amount held by EFH Corp.;
•
$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.


23

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 $5.237 billion, including $363 million aggregate principal amount held by EFH Corp. and EFIH, 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.

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.


24

10.     COMMITMENTS AND CONTINGENCIES

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 8 and 9 for discussion of guarantees and security for certain of our post-petition and pre-petition debt.

Letters of Credit

At June 30, 2015, TCEH had outstanding letters of credit under credit facilities totaling $399 million as follows:
•
$226 million to support commodity risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions and collateral postings with ERCOT;
•
$77 million to support executory contracts and insurance agreements;
•
$62 million to support TCEH's REP financial requirements with the PUCT, and
•
$34 million for other credit support requirements.

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 9 for discussion of letter of credit draws in 2014 and 2015.

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.

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 motions are currently scheduled to be heard on August 11, 2015. In addition to the claims described above, certain of the Debtors (or creditors purporting to act derivatively in the name of a Debtor) may bring inter-Debtor or intra-Debtor claims (including claims under the Federal and State Income Tax Allocation Agreement among EFH Corp. and certain of its subsidiaries under which TCEH and EFH Corp. have previously filed claims in the Chapter 11 Cases) that could be material in amount. Certain of these creditors provided confidential disclosures to the Debtors in April 2015 regarding the material claims or causes of action for which they may seek standing to prosecute. We are currently evaluating these disclosures. Creditors who wish to seek derivative standing to prosecute claims on behalf of a Debtor relating to pre-petition transactions addressed by the discovery protocol governing the Debtors' Chapter 11 Cases are currently required to file motions seeking standing fifteen days after approval of a disclosure statement.

We cannot predict the timing or outcome of future proceedings, if any, related to these transactions. The outcome of any of these claims could be material and could affect the results of operations, liquidity or financial condition of a particular Debtor.


25

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. We believe that we have complied with all requirements of the CAA and intend to vigorously defend against these 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.

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 (NOx) 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 NOx and 2% higher for seasonal NOx.

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. We plan to participate in the EPA's reconsideration process to develop increased budgets that do not over-control Texas. 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. We filed comments on the EPA proposal in November 2014. 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 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.

26


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.


27

11.     MEMBERSHIP INTERESTS

Under applicable law, we are prohibited from paying any distribution to the extent that immediately following payment of such distribution, we would be insolvent. In addition, due to the Chapter 11 Cases, no distributions are eligible to be paid without the approval of the Bankruptcy Court.

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.

Membership Interests

The following tables present the changes to membership interests for the six months ended June 30, 2015 and 2014:
Six Months Ended June 30, 2015
 
EFCH Membership Interests 
 
 
 
 
 
Capital Account
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interests
 
Total
Membership Interests
Balance at December 31, 2014
$
(18,439
)
 
$
(35
)
 
$
—

 
$
(18,474
)
Net loss
(1,553
)
 
—

 
—

 
(1,553
)
Net effect of cash flow hedges
—

 
1

 
—

 
1

Effect of debt push-down from EFH Corp. (a)
11

 
—

 
—

 
11

Balance at June 30, 2015
$
(19,981
)
 
$
(34
)
 
$
—

 
$
(20,015
)

Six Months Ended June 30, 2014
 
EFCH Membership Interests
 
 
 
 
 
Capital Account
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interests
 
Total
Membership Interests
Balance at December 31, 2013
$
(12,233
)
$
(36
)
 
$
1

 
$
(12,268
)
Net loss
(1,130
)
—

 
—

 
(1,130
)
Effect of stock-based incentive compensation plans
1

—

 
—

 
1

Net effect of cash flow hedges
—

1

 
—

 
1

Investment by noncontrolling interests
—

—

 
1

 
1

Effect of debt push-down from EFH Corp. (a)
11

—

 
—

 
11

Other
(1
)
—

 
(2
)
 
(3
)
Balance at June 30, 2014
$
(13,352
)
$
(35
)
 
$
—

 
$
(13,387
)
____________
(a)
Represents the interest and income tax effects of debt pushed down from EFH Corp. (Note 9).


28

12.     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 an EFH Corp. centralized risk management group that reports to the EFH Corp. 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 13 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.


29

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:
June 30, 2015
 
Level 1
 
Level 2
 
Level 3 (a)
 
Reclassification (b)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
268

 
$
92

 
$
50

 
$
3

 
$
413

Nuclear decommissioning trust – equity securities (c)
380

 
219

 
—

 
—

 
599

Nuclear decommissioning trust – debt securities (c)
—

 
306

 
—

 
—

 
306

Total assets
$
648

 
$
617

 
$
50

 
$
3

 
$
1,318

Liabilities:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
136

 
$
27

 
$
6

 
$
3

 
$
172

Total liabilities
$
136

 
$
27

 
$
6

 
$
3

 
$
172


December 31, 2014
 
Level 1
 
Level 2
 
Level 3 (a)
 
Reclassification (b)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
402

 
$
46

 
$
49

 
$
—

 
$
497

Nuclear decommissioning trust – equity securities (c)
375

 
217

 
—

 
—

 
592

Nuclear decommissioning trust – debt securities (c)
—

 
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)
Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in the condensed consolidated balance sheets.
(c)
The nuclear decommissioning trust investment is included in the investments line in the condensed consolidated balance sheets. See Note 15.


30

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 13 for further discussion regarding derivative instruments, including the termination of certain natural gas hedging agreements shortly after the Bankruptcy Filing.

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.

There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the three and six months ended June 30, 2015 and 2014. 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 three and six months ended June 30, 2015 and 2014.

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 June 30, 2015 and December 31, 2014:
June 30, 2015
 
 
Fair Value
 
 
 
 
 
 
Contract Type (a)
 
Assets
 
Liabilities
 
Total
 
Valuation Technique
 
Significant Unobservable Input
 
Range (b)
Electricity purchases and sales
 
$
6

 
$
(1
)
 
$
5

 
Valuation Model
 
Illiquid pricing locations (c)
 
$25 to $45/MWh
 
 
 
 
 
 
 
 
 
 
Hourly price curve shape (d)
 
$15 to $60/MWh
 
 
 
 
 
 
 
 
 
 
 
 
 
Electricity congestion revenue rights
 
34

 
(4
)
 
30

 
Market Approach (e)
 
Illiquid price differences between settlement points (f)
 
$0.00 to $10.00/MWh
 
 
 
 
 
 
 
 
 
 
 
 
 
Other (i)
 
10

 
(1
)
 
9

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
50

 
$
(6
)
 
$
44

 
 
 
 
 
 

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)
 
$0.00 to $20.00/MWh
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal purchases
 
—

 
(4
)
 
(4
)
 
Market Approach (e)
 
Illiquid price variances between mines (g)
 
$0.00 to $1.00/ton
 
 
 
 
 
 
 
 
 
 
Illiquid price variances between heat content (h)
 
$0.30 to $0.40/ton
 
 
 
 
 
 
 
 
 
 
 
 
 
Other (i)
 
7

 
(1
)
 
6

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
49

 
$
(14
)
 
$
35

 
 
 
 
 
 


31

____________
(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.

The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and six months ended June 30 2015 and 2014.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Net asset (liability) balance at beginning of period
$
60

 
$
(897
)
 
$
35

 
$
(973
)
Total unrealized valuation gains (losses)
(2
)
 
(9
)
 
14

 
(94
)
Purchases, issuances and settlements (a):
 
 
 
 
 
 
 
Purchases
13

 
20

 
32

 
29

Issuances
(2
)
 
(1
)
 
(5
)
 
(2
)
Settlements
(17
)
 
933

 
(25
)
 
1,084

Transfers into Level 3 (b)
—

 
—

 
—

 
—

Transfers out of Level 3 (b)
(8
)
 
(1
)
 
(7
)
 
1

Net change (c)
(16
)
 
942

 
9

 
1,018

Net asset balance at end of period
$
44

 
$
45

 
$
44

 
$
45

Unrealized valuation gains (losses) relating to instruments held at end of period
$
1

 
$
(9
)
 
$
9

 
$
(5
)
____________
(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 13.
(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 periods presented are in and out of Level 2.
(c)
Substantially all changes in values of commodity contracts are reported in the condensed statements of consolidated income (loss) in net gain (loss) from commodity hedging and trading activities. 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.



32

13.    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 12 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 condensed 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 condensed statements of consolidated income (loss) in interest expense and related charges. As of June 30, 2015 and December 31, 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 upon the terminations totaled $1.108 billion, which represented a realized loss of $1.225 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 $1.235 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 condensed 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 6).

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 $277 million substantially all of which represented the nonperformance risk adjustment, and is reported as a noncash charge in reorganization items in the condensed statements of consolidated income (loss) in accordance with ASC 852-10, Reorganizations (see Note 7).

33

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 condensed consolidated balance sheets at June 30, 2015 and December 31, 2014. All amounts relate to commodity contracts.
 
June 30, 2015
 
December 31, 2014
 
Derivative Assets
 
Derivative Liabilities
 
Derivative Assets
 
Derivative Liabilities
Current assets
$
396

 
$
—

 
$
492

 
$
—

Noncurrent assets
16

 
1

 
5

 
—

Current liabilities
—

 
(168
)
 
—

 
(316
)
Noncurrent liabilities
(2
)
 
(2
)
 
—

 
(1
)
Net assets (liabilities)
$
410

 
$
(169
)
 
$
497

 
$
(317
)


At June 30, 2015 and December 31, 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:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Derivative (condensed statements of consolidated income (loss) presentation)
 
2015
 
2014
 
2015
 
2014
Commodity contracts (Net gain (loss) from commodity hedging and trading activities) (a)
 
$
26

 
$
11

 
$
151

 
$
(168
)
Interest rate swaps (Interest expense and related charges) (b)
 
—

 
(47
)
 
—

 
(128
)
Interest rate swaps (Reorganization items) (Note 7)
 
—

 
(277
)
 
—

 
(277
)
Net gain (loss)
 
$
26

 
$
(313
)
 
$
151

 
$
(573
)
_______________
(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 6).

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 both the three and six months ended June 30, 2015 and 2014. There were no amounts recognized in OCI for the three and six months ended June 30, 2015 and 2014.

Accumulated other comprehensive income related to cash flow hedges at June 30, 2015 and December 31, 2014 totaled $34 million and $35 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 June 30, 2015 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.


34

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 condensed 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 condensed 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 June 30, 2015 and December 31, 2014, all margin deposits held were unrestricted.

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 condensed consolidated balance sheets to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
June 30, 2015
 
 
Amounts Presented in Balance Sheet
 
Offsetting Instruments (a)
 
Financial Collateral (Received) Pledged (b)
 
Net Amounts
Derivative assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
413

 
$
(163
)
 
$
(61
)
 
$
189

Derivative liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
(172
)
 
163

 
1

 
(8
)
Net amounts
 
$
241

 
$
—

 
$
(60
)
 
$
181


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.


35

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at June 30, 2015 and December 31, 2014:
 
 
 
 
 
 
 
 
 
June 30, 2015
 
December 31, 2014
 
 
Derivative type
 
Notional Volume
 
Unit of Measure
Natural gas (a)
 
2,534

 
1,687

 
Million MMBtu
Electricity
 
39,357

 
22,820

 
GWh
Congestion Revenue Rights (b)
 
109,345

 
89,484

 
GWh
Coal
 
6

 
10

 
Million US tons
Fuel oil
 
39

 
36

 
Million gallons
Uranium
 
151

 
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.

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 our credit ratings being below investment grade, substantially all of such collateral posting requirements have already been effective.

At June 30, 2015 and December 31, 2014, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully collateralized and the liquidity exposure associated with those liabilities were immaterial.

In addition, certain derivative agreements that are collateralized primarily with liens on certain of our assets include indebtedness cross-default provisions that have resulted in the termination of such contracts as a result of the Bankruptcy Filing. Substantially all of the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, were triggered upon the Bankruptcy Filing, and substantially all of the contracts had been cancelled. There was no liquidity exposure associated with these liabilities at both June 30, 2015 and December 31, 2014. See Note 9 for a description of other pre-petition obligations that are supported by liens on certain of our assets.

As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, were not material at both June 30, 2015 and December 31, 2014.

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

TCEH has concentrations of credit risk with the counterparties to its derivative contracts. At June 30, 2015, total credit risk exposure to all counterparties related to derivative contracts totaled $524 million (including associated accounts receivable). The net exposure to those counterparties totaled $284 million at June 30, 2015 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $45 million. At June 30, 2015, the credit risk exposure to the banking and financial sector represented 65% of the total credit risk exposure and 46% of the net exposure.


36

Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because substantially 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.

37

14.     RELATED-PARTY TRANSACTIONS

The following represent our significant related-party transactions.

•
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 $224 million and $225 million for the three months ended June 30, 2015 and 2014, respectively, and $460 million and $465 million for the six months ended June 30, 2015 and 2014, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The condensed consolidated balance sheets at June 30, 2015 and December 31, 2014 reflect amounts due currently to Oncor totaling $138 million and $118 million, respectively, (included in trade accounts and other payables to affiliates) largely related to these electricity delivery fees.

•
EFCH (parent entity) has a demand note payable to EFH Corp., the proceeds from which were used to repay outstanding debt. The note totaled $107 million at both June 30, 2015 and December 31, 2014 and carried interest at a rate based on the one-month LIBOR rate plus 5.00%. Interest expense related to this note totaled $1 million and $2 million for the three and six months ended June 30, 2014, respectively. At June 30, 2015 and December 31, 2014, the $107 million note payable as of the Petition Date is classified as a liability subject to compromise (LSTC), and interest expense on the note has not been recorded since the Petition Date.

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, which resulted in the EFH Corp. retirement plan being fully funded as calculated under the provisions of the Employee Retirement Income Security Act of 1974, as amended. 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 payment by TCEH was accounted for as an advance to EFH Corp. that will be settled as pension and other postretirement employee benefits expenses are allocated to TCEH in the normal course. The balance of the advance totaled $11 million at June 30, 2015, with $6 million recorded as a current asset and $5 million recorded as a noncurrent asset.

Receivables from affiliates are measured at historical cost and primarily have consisted of notes receivable for cash loaned to EFH Corp. for debt principal and interest payments and other general corporate purposes of EFH Corp. as discussed above. EFCH reviews economic conditions, counterparty credit scores and historical payment activity to assess the overall collectability of its affiliated receivables. There were no credit loss allowances at June 30, 2015 and December 31, 2014.

•
A subsidiary of EFH Corp. bills our subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges, which are largely settled in cash and primarily reported in SG&A expenses, totaled $47 million and $44 million for the three months ended June 30, 2015 and 2014, respectively, and totaled $98 million and $100 million for the six months ended June 30, 2015 and 2014, respectively. These amounts include allocated expense, which totaled $2 million and $10 million for the three and six months ended June 30, 2014 for management fees owed and paid by EFH Corp. to the Sponsor Group. Effective with the Petition Date, EFH Corp. suspended allocations of such fees to EFCH. Fees accrued as of the Petition Date are classified as LSTC.

See Note 9 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.

•
In the three months ended March 31, 2015, TCEH settled a $15 million payable related to information technology assets purchased from a subsidiary of EFH Corp. in 2014. In the three months ended June 30, 2015, TCEH purchased and settled $12 million of additional assets. In April 2014, prior to the Bankruptcy Filing, a subsidiary of EFH Corp. sold information technology assets to TCEH totaling $24 million. TCEH cash settled these transactions in April 2014. The assets are substantially for the use of TCEH and its subsidiaries.

38


•
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 investments in our condensed consolidated balance sheets, will ultimately be sufficient to fund the future decommissioning liability, reported in noncurrent liabilities in our condensed consolidated balance sheet. The delivery fee surcharges remitted to TCEH totaled $4 million for both the three months ended June 30, 2015 and 2014 and totaled $8 million for both the six months ended June 30, 2015 and 2014. 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 June 30, 2015 and December 31, 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 other noncurrent liabilities. In June 2015, Luminant filed an updated nuclear decommissioning cost study and funding analysis with the PUCT.

•
EFH Corp. files consolidated federal income tax and Texas state margin tax returns that include our results; however, under a Federal and State Income Tax Allocation Agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., are recorded as if we file our own corporate income tax return. As of June 30, 2015, we had current income tax liabilities of $1 million and $605 million in noncurrent income tax liabilities payable to EFH Corp. reported as LSTC. As of December 31, 2014, we had current income tax liabilities of $16 million and noncurrent income tax liabilities of $626 million payable to EFH Corp. We made tax payments of $24 million and $28 million to EFH Corp. for the six months ended June 30, 2015 and 2014, respectively.

•
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 both June 30, 2015 and December 31, 2014, TCEH had posted letters of credit and/or cash in the amount of $9 million for the benefit of Oncor.

•
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.

•
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.

•
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.

39


•
As a result of debt repurchase and exchange transactions in 2009 through 2011, EFH Corp. and EFIH held TCEH debt securities at both June 30, 2015 and December 31, 2014 as shown below (principal amounts). At June 30, 2015 and December 31, 2014, the $382 million in notes payable as of the Petition Date is classified as LSTC.
 
Principal Amount
TCEH Senior Notes:
 
Held by EFH Corp.
$
284

Held by EFIH
79

TCEH Term Loan Facilities:
 
Held by EFH Corp.
19

Total
$
382


Interest expense on the notes totaled zero and $3 million for the three months ended June 30, 2015 and 2014 respectively, and zero and $13 million for the six months ended June 30, 2015 and 2014, respectively. Contractual interest, not paid or recorded, totaled $9 million and $19 million for the three and six months ended June 30, 2015, respectively. See Note 6.

See Notes 8 and 9 for discussion of guarantees and push down of certain EFH Corp. debt.

40

15.     SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Other income:
 
 
 
 
 
 
 
Sale of land
$
6

 
$
—

 
$
6

 
$
—

Mineral rights royalty income
1

 
1

 
2

 
2

All other
1

 
1

 
3

 
5

Total other income
$
8

 
$
2

 
$
11

 
$
7

Other deductions:
 
 
 
 
 
 
 
Impairment of favorable purchase contracts (Note 3)
$
—

 
$
—

 
$
8

 
$
—

Impairment of emission allowances (Note 3)
—

 
—

 
51

 
—

All other
2

 
2

 
2

 
3

Total other deductions
$
2

 
$
2

 
$
61

 
$
3


Restricted Cash

 
June 30, 2015
 
December 31, 2014
 
Current
Assets
 
Noncurrent Assets
 
Current
Assets
 
Noncurrent Assets
Amounts related to TCEH's DIP Facility (Note 8)
$
399

 
$
—

 
$
—

 
$
350

Amounts related to TCEH's pre-petition Letter of Credit Facility (Note 9) (a)
—

 
506

 
—

 
551

Other
2

 
—

 
2

 
—

Total restricted cash
$
401

 
$
506

 
$
2

 
$
901

____________
(a)
See Note 9 for discussion of letter of credit draws in 2015 and 2014.

Trade Accounts Receivable

 
June 30, 2015
 
December 31, 2014
Wholesale and retail trade accounts receivable
$
692

 
$
603

Allowance for uncollectible accounts
(12
)
 
(15
)
Trade accounts receivable — net
$
680

 
$
588


Gross trade accounts receivable at June 30, 2015 and December 31, 2014 included unbilled revenues of $284 million and $239 million, respectively.

Allowance for Uncollectible Accounts Receivable

 
Six Months Ended June 30,
 
2015
 
2014
Allowance for uncollectible accounts receivable at beginning of period
$
15

 
$
14

Increase for bad debt expense
16

 
20

Decrease for account write-offs
(19
)
 
(21
)
Allowance for uncollectible accounts receivable at end of period
$
12

 
$
13



41

Inventories by Major Category

 
June 30, 2015
 
December 31, 2014
Materials and supplies
$
214

 
$
214

Fuel stock
190

 
215

Natural gas in storage
37

 
39

Total inventories
$
441

 
$
468


Investments

 
June 30, 2015
 
December 31, 2014
Nuclear plant decommissioning trust
$
905

 
$
893

Assets related to employee benefit plans, including employee savings programs, net of distributions
1

 
1

Land
36

 
37

Miscellaneous other
8

 
10

Total investments
$
950

 
$
941


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 14). The nuclear decommissioning trust fund is not a debtor under the Chapter 11 Cases. A summary of investments in the fund follows:
 
June 30, 2015
 
Cost (a)
 
Unrealized gain
 
Unrealized loss
 
Fair market
value
Debt securities (b)
$
299

 
$
9

 
$
(2
)
 
$
306

Equity securities (c)
284

 
320

 
(5
)
 
599

Total
$
583

 
$
329

 
$
(7
)
 
$
905

 
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 Investors Services, Inc. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.56% and 4.35% at June 30, 2015 and December 31, 2014, respectively, and an average maturity of 6 years at both June 30, 2015 and December 31, 2014.
(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 June 30, 2015 mature as follows: $74 million in one to five years, $76 million in five to ten years and $156 million after ten years.


42

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Realized gains
$
1

 
$
—

 
$
1

 
$
1

Realized losses
$
—

 
$
(1
)
 
$
(1
)
 
$
(1
)
Proceeds from sales of securities
$
50

 
$
52

 
$
73

 
$
85

Investments in securities
$
(54
)
 
$
(56
)
 
$
(81
)
 
$
(93
)

Property, Plant and Equipment

At June 30, 2015 and December 31, 2014, property, plant and equipment of $11.4 billion and $12.3 billion, respectively, is stated net of accumulated depreciation and amortization of $4.8 billion and $5.2 billion, respectively.

The estimated remaining useful lives of our lignite/coal and nuclear generation facilities range from 17 to 54 years. Those estimated lives are subject to change as market factors evolve, including changes in environmental regulation and wholesale electricity price forecasts.

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.

In December 2014, the EPA signed the final Disposal of Coal Combustion Residuals from Electric Utilities rule (the CCR rule), and in April 2015, the rule was posted in the Federal Register. We have established an estimated $54 million asset retirement obligation related to the 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 condensed consolidated balance sheets, for the six months ended June 30, 2015:
 
Nuclear Plant Decommissioning
 
Mining Land Reclamation
 
Other
 
Total
Liability at December 31, 2014
$
413

 
$
165

 
$
36

 
$
614

Additions:
 
 
 
 
 
 
 
Accretion
12

 
10

 
1

 
23

Adjustment for new cost estimate (a)
70

 
—

 
—

 
70

Incremental reclamation costs (b)
—

 
—

 
54

 
54

Reductions:
 
 
 
 
 
 
 
Payments
—

 
(28
)
 
—

 
(28
)
Liability at June 30, 2015
495

 
147

 
91

 
733

Less amounts due currently
—

 
(61
)
 
—

 
(61
)
Noncurrent liability at June 30, 2015
$
495

 
$
86

 
$
91

 
$
672

____________
(a)
The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in the second quarter of 2015. In accordance with regulatory requirements, a new cost estimate is completed every five years. The increase in the liability was driven by increased security and fuel-handling costs.
(b)
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 new CCR rule discussed above.


43

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:
 
June 30, 2015
 
December 31, 2014
Uncertain tax positions, including accrued interest
$
53

 
$
74

Asset retirement and mining reclamation obligations
672

 
560

Unfavorable purchase and sales contracts
554

 
566

Nuclear decommissioning fund excess over asset retirement obligation (Note 14)
409

 
479

Other, including retirement and other employee benefits
19

 
20

Total other noncurrent liabilities and deferred credits
$
1,707

 
$
1,699


Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $6 million for both the three months ended June 30, 2015 and 2014 and $12 million for both the six months ended June 30, 2015 and 2014. See Note 3 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
2015
 
$
24

2016
 
$
24

2017
 
$
24

2018
 
$
24

2019
 
$
24


Fair Value of Debt

 
 
June 30, 2015
 
December 31, 2014
Debt:
 
Carrying Amount
 
Fair
Value
 
Carrying Amount
 
Fair
Value
Borrowings under debtor-in-possession credit facility (Note 8)
 
$
1,425

 
$
1,427

 
$
1,425

 
$
1,430

Pre-petition notes, loans and other debt reported as liabilities subject to compromise (Note 9) (a)
 
$
31,894

 
$
14,863

 
$
31,894

 
$
16,664

Long-term debt not subject to compromise, excluding capital lease obligations (Note 8)
 
$
68

 
$
78

 
$
76

 
$
79

____________
(a)
Carrying amount excludes deferred debt issuance and extension costs.

We determine fair value in accordance with accounting standards as discussed in Note 12, and at June 30, 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.


44

Supplemental Cash Flow Information

 
Six Months Ended June 30,
 
2015
 
2014
Cash payments related to:
 
 
 
Interest paid (a)
$
647

 
$
623

Capitalized interest
(6
)
 
(11
)
Interest paid (net of capitalized interest) (a)
$
641

 
$
612

Reorganization items (b)
$
71

 
$
26

Income taxes
$
24

 
$
28

Noncash investing and financing activities:
 
 
 
Construction expenditures (c)
$
58

 
$
48

____________
(a)
Net of amounts received under interest rate swap agreements. 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.


45

16.     SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

At June 30, 2015 TCEH and TCEH Finance, as Co-Issuers, had outstanding $5.237 billion aggregate principal amount of pre-petition 10.25% Senior Notes Due 2015, 10.25% Senior Notes due 2015 Series B and Toggle Notes (collectively, the TCEH Senior Notes) and $1.571 billion aggregate principal amount of pre-petition 15% Senior Secured Second Lien Notes due 2021 and 15% Senior Secured Second Lien Notes due 2021 (Series B) (collectively, the TCEH Senior Secured Second Lien Notes). The TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes are unconditionally guaranteed by EFCH and by each subsidiary (all 100% owned by TCEH) that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes. The guarantees of the TCEH Senior Notes rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. The guarantees of the TCEH Senior Secured Second Lien Notes 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 (see Note 9). All other subsidiaries of EFCH, either direct or indirect, do not guarantee the TCEH Senior Notes or TCEH Senior Secured Second Lien Notes (collectively the Non-Guarantors). The indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes contain certain restrictions, subject to certain exceptions, on EFCH's ability to pay dividends or make investments. See Note 9.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, "Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered" in order to present the condensed consolidating statements of income (loss) for the three and six months ended June 30, 2015 and 2014 and of cash flows for the six months ended June 30, 2015 and 2014 of EFCH (Parent), TCEH (Issuer), the Guarantors and the Non-Guarantors and the condensed consolidating balance sheets at June 30, 2015 and December 31, 2014 of the Parent, Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5J, "Push Down Basis of Accounting Required in Certain Limited Circumstances," including the effects of the push down of $30 million of the EFH Corp. pre-petition 10.875% Senior Notes and EFH Corp. pre-petition 11.25%/12.00% Senior Toggle Notes to the Parent at both June 30, 2015 and December 31, 2014 and the TCEH Senior Notes, TCEH Senior Secured Notes, TCEH Senior Secured Second Lien Notes and TCEH Senior Secured Facilities to the Other Guarantors at June 30, 2015 and December 31, 2014 (see Note 9). TCEH Finance's sole function is to be the co-issuer of certain TCEH debt securities; therefore, it has no other independent assets, liabilities or operations. Amounts reported as advances to affiliates arise from recurring intercompany transactions among EFCH, TCEH and TCEH’s subsidiaries in the normal course of business. In consideration of the Bankruptcy Filing, the ultimate settlement of the advances is uncertain and is dependent on the Chapter 11 plan ultimately approved. Accordingly, as of June 30, 2015, the Other Guarantors' pre-petition advances from parent have been reclassified to membership interests as a noncash transaction.

EFCH (parent entity) received no dividends/distributions from its consolidated subsidiaries for the three and six months ended June 30, 2015 and 2014.

46

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES
A DEBTOR-IN-POSSESSION
Condensed Consolidating Statements of Income (Loss)
Three Months Ended June 30, 2015
(millions of dollars)

 
Parent
Guarantor
 
Issuer
 
Other
Guarantors
 
Non-
guarantors
 
Eliminations
 
Consolidated
Operating revenues
$
—

 
$
—

 
$
1,256

 
$
—

 
$
—

 
$
1,256

Fuel, purchased power costs and delivery fees
—

 
—

 
(646
)
 
—

 
—

 
(646
)
Net gain from commodity hedging and trading activities
—

 
—

 
20

 
—

 
—

 
20

Operating costs
—

 
—

 
(217
)
 
—

 
—

 
(217
)
Depreciation and amortization
—

 
(1
)
 
(218
)
 
—

 
—

 
(219
)
Selling, general and administrative expenses
—

 
1

 
(162
)
 
—

 
—

 
(161
)
Other income
—

 
—

 
2

 
6

 
—

 
8

Other deductions
—

 
—

 
(2
)
 
—

 
—

 
(2
)
Interest income
—

 
7

 
27

 
—

 
(34
)
 
—

Interest expense and related charges
(2
)
 
(349
)
 
(5
)
 
—

 
34

 
(322
)
Reorganization items
—

 
(40
)
 
—

 
—

 
—

 
(40
)
Income (loss) before income taxes
(2
)
 
(382
)
 
55

 
6

 
—

 
(323
)
Income tax (expense) benefit
—

 
114

 
(10
)
 
(2
)
 
5

 
107

Equity earnings (losses) of subsidiaries
(214
)
 
54

 
4

 
—

 
156

 
—

Net income (loss)
(216
)
 
(214
)
 
49

 
4

 
161

 
(216
)
Other comprehensive income (loss)
—

 
—

 
—

 
—

 
—

 
—

Comprehensive income (loss)
$
(216
)
 
$
(214
)
 
$
49

 
$
4

 
$
161

 
$
(216
)


47

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES
A DEBTOR-IN-POSSESSION
Condensed Consolidating Statements of Income (Loss)
Six Months Ended June 30, 2015
(millions of dollars)

 
Parent
Guarantor
 
Issuer
 
Other
Guarantors
 
Non-
guarantors
 
Eliminations
 
Consolidated
Operating revenues
$
—

 
$
—

 
$
2,527

 
$
—

 
$
—

 
$
2,527

Fuel, purchased power costs and delivery fees
—

 
—

 
(1,259
)
 
—

 
—

 
(1,259
)
Net gain from commodity hedging and trading activities
—

 
—

 
123

 
—

 
—

 
123

Operating costs
—

 
—

 
(410
)
 
—

 
—

 
(410
)
Depreciation and amortization
—

 
(3
)
 
(431
)
 
—

 
—

 
(434
)
Selling, general and administrative expenses
—

 
2

 
(323
)
 
—

 
—

 
(321
)
Impairment of goodwill
—

 
(700
)
 
—

 
—

 
—

 
(700
)
Impairment of long-lived assets
—

 
—

 
(676
)
 
—

 
—

 
(676
)
Other income
—

 
—

 
5

 
6

 
—

 
11

Other deductions
—

 
—

 
(61
)
 
—

 
—

 
(61
)
Interest income
—

 
8

 
45

 
—

 
(53
)
 
—

Interest expense and related charges
(3
)
 
(686
)
 
(2
)
 
—

 
52

 
(639
)
Reorganization items
—

 
(83
)
 
(31
)
 
—

 
—

 
(114
)
Income (loss) before income taxes
(3
)
 
(1,462
)
 
(493
)
 
6

 
(1
)
 
(1,953
)
Income tax (expense) benefit
—

 
226

 
165

 
(2
)
 
11

 
400

Equity earnings (losses) of subsidiaries
(1,550
)
 
(314
)
 
4

 
—

 
1,860

 
—

Net income (loss)
(1,553
)
 
(1,550
)
 
(324
)
 
4

 
1,870

 
(1,553
)
Other comprehensive income (loss)
1

 
1

 
—

 
—

 
(1
)
 
1

Comprehensive income (loss)
$
(1,552
)
 
$
(1,549
)
 
$
(324
)
 
$
4

 
$
1,869

 
$
(1,552
)


48

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES
A DEBTOR-IN-POSSESSION
Condensed Consolidating Statements of Income (Loss)
Three Months Ended June 30, 2014
(millions of dollars)

 
Parent
Guarantor
 
Issuer
 
Other
Guarantors
 
Non-
guarantors
 
Eliminations
 
Consolidated
Operating revenues
$
—

 
$
—

 
$
1,406

 
$
—

 
$
—

 
$
1,406

Fuel, purchased power costs and delivery fees
—

 
—

 
(656
)
 
—

 
—

 
(656
)
Net gain (loss) from commodity hedging and trading activities
—

 
(38
)
 
65

 
—

 
—

 
27

Operating costs
—

 
—

 
(242
)
 
—

 
—

 
(242
)
Depreciation and amortization
—

 
—

 
(329
)
 
—

 
—

 
(329
)
Selling, general and administrative expenses
—

 
(12
)
 
(157
)
 
—

 
—

 
(169
)
Impairment of long-lived assets
—

 
—

 
(21
)
 
—

 
—

 
(21
)
Other income
—

 
—

 
2

 
—

 
—

 
2

Other deductions
—

 
—

 
(2
)
 
—

 
—

 
(2
)
Interest income
—

 
19

 
66

 
—

 
(85
)
 
—

Interest expense and related charges
(3
)
 
(511
)
 
(192
)
 
—

 
259

 
(447
)
Reorganization items
—

 
(423
)
 
—

 
—

 
—

 
(423
)
Income (loss) before income taxes
(3
)
 
(965
)
 
(60
)
 
—

 
174

 
(854
)
Income tax (expense) benefit
1

 
317

 
7

 
—

 
(56
)
 
269

Equity earnings (losses) of subsidiaries
(583
)
 
65

 
—

 
—

 
518

 
—

Net income (loss)
(585
)
 
(583
)
 
(53
)
 
—

 
636

 
(585
)
Other comprehensive income (loss)
1

 
1

 
—

 
—

 
(1
)
 
1

Comprehensive income (loss)
$
(584
)
 
$
(582
)
 
$
(53
)
 
$
—

 
$
635

 
$
(584
)


49

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES
A DEBTOR-IN-POSSESSION
Condensed Consolidating Statements of Income (Loss)
Six Months Ended June 30, 2014
(millions of dollars)

 
Parent
Guarantor
 
Issuer
 
Other
Guarantors
 
Non-
guarantors
 
Eliminations
 
Consolidated
Operating revenues
$
—

 
$
—

 
$
2,924

 
$
—

 
$
—

 
$
2,924

Fuel, purchased power costs and delivery fees
—

 
—

 
(1,388
)
 
—

 
—

 
(1,388
)
Net loss from commodity hedging and trading activities
—

 
(90
)
 
(102
)
 
—

 
—

 
(192
)
Operating costs
—

 
—

 
(455
)
 
—

 
—

 
(455
)
Depreciation and amortization
—

 
—

 
(656
)
 
—

 
—

 
(656
)
Selling, general and administrative expenses
—

 
(29
)
 
(333
)
 
(2
)
 
—

 
(364
)
Impairment of long-lived assets
—

 
—

 
(21
)
 
—

 
—

 
(21
)
Other income
—

 
—

 
5

 
2

 
—

 
7

Other deductions
—

 
—

 
(3
)
 
—

 
—

 
(3
)
Interest income
1

 
80

 
262

 
—

 
(343
)
 
—

Interest expense and related charges
(6
)
 
(1,375
)
 
(806
)
 
—

 
1,075

 
(1,112
)
Reorganization items
—

 
(423
)
 
—

 
—

 
—

 
(423
)
Income (loss) before income taxes
(5
)
 
(1,837
)
 
(573
)
 
—

 
732

 
(1,683
)
Income tax (expense) benefit
1

 
614

 
184

 
—

 
(246
)
 
553

Equity earnings (losses) of subsidiaries
(1,126
)
 
97

 
—

 
—

 
1,029

 
—

Net income (loss)
(1,130
)
 
(1,126
)
 
(389
)
 
—

 
1,515

 
(1,130
)
Other comprehensive income (loss)
1

 
1

 
—

 
—

 
(1
)
 
1

Comprehensive income (loss)
$
(1,129
)
 
$
(1,125
)
 
$
(389
)
 
$
—

 
$
1,514

 
$
(1,129
)


50

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES
A DEBTOR-IN-POSSESSION
Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2015
(millions of dollars)

 
Parent/
Guarantor
 
Issuer
 
Other
Guarantors
 
Non-
guarantors
 
Eliminations
 
Consolidated
Cash provided by (used in) operating activities
$
(4
)
 
$
(769
)
 
$
558

 
$
(1
)
 
$
—

 
$
(216
)
Cash flows – financing activities:
 
 
 
 
 
 
 
 
 
 
 
Notes/advances due to affiliates
7

 
324

 
—

 
2

 
(333
)
 
—

Repayments/repurchases of debt
(3
)
 
—

 
(8
)
 
—

 
—

 
(11
)
Cash provided by (used in) financing activities
4

 
324

 
(8
)
 
2

 
(333
)
 
(11
)
Cash flows – investing activities:
 
 
 
 
 
 
 
 
 
 
 
Capital expenditures
—

 
(13
)
 
(196
)
 
—

 
—

 
(209
)
Nuclear fuel purchases
—

 
—

 
(11
)
 
—

 
—

 
(11
)
Settlements of notes due from affiliates
—

 
—

 
(333
)
 
—

 
333

 
—

Changes in restricted cash
—

 
(4
)
 
—

 
—

 
—

 
(4
)
Proceeds from sales of nuclear decommissioning trust fund securities
—

 
—

 
73

 
—

 
—

 
73

Investments in nuclear decommissioning trust fund securities
—

 
—

 
(81
)
 
—

 
—

 
(81
)
Other, net
—

 
—

 
—

 
9

 
—

 
9

Cash provided by (used in) investing activities
—

 
(17
)
 
(548
)
 
9

 
333

 
(223
)
Net change in cash and cash equivalents
—

 
(462
)
 
2

 
10

 
—

 
(450
)
Cash and cash equivalents – beginning balance
—

 
1,826

 
16

 
1

 
—

 
1,843

Cash and cash equivalents – ending balance
$
—

 
$
1,364

 
$
18

 
$
11

 
$
—

 
$
1,393



51

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES
A DEBTOR-IN-POSSESSION
Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2014
(millions of dollars)

 
Parent/
Guarantor
 
Issuer
 
Other
Guarantors
 
Non-
guarantors
 
Eliminations
 
Consolidated
Cash provided by (used in) operating activities
$
(3
)
 
$
(775
)
 
$
736

 
$
(4
)
 
$
—

 
$
(46
)
Cash flows – financing activities:
 
 
 
 
 
 
 
 
 
 
 
Proceeds from TCEH DIP Facility
—

 
1,425

 
—

 
—

 
—

 
1,425

Fees paid for TCEH DIP Facility
—

 
(92
)
 
—

 
—

 
—

 
(92
)
Notes/advances due to affiliates
6

 
465

 
—

 
—

 
(471
)
 
—

Repayments/repurchases of debt
(3
)
 
(203
)
 
(6
)
 
—

 
—

 
(212
)
Contributions from noncontrolling interests
—

 
—

 
—

 
1

 
—

 
1

Cash provided by (used in) financing activities
3

 
1,595

 
(6
)
 
1

 
(471
)
 
1,122

Cash flows – investing activities:
 
 
 
 
 
 
 
 
 
 
 
Capital expenditures
—

 
—

 
(193
)
 
—

 
—

 
(193
)
Nuclear fuel purchases
—

 
—

 
(36
)
 
—

 
—

 
(36
)
Settlements of notes due from affiliates
—

 
—

 
(488
)
 
—

 
471

 
(17
)
Changes in restricted cash
—

 
310

 
—

 
—

 
—

 
310

Proceeds from sales of nuclear decommissioning trust fund securities
—

 
—

 
85

 
—

 
—

 
85

Investments in nuclear decommissioning trust fund securities
—

 
—

 
(93
)
 
—

 
—

 
(93
)
Other, net
—

 
1

 
(1
)
 
—

 
—

 
—

Cash provided by (used in) investing activities
—

 
311

 
(726
)
 
—

 
471

 
56

Net change in cash and cash equivalents
—

 
1,131

 
4

 
(3
)
 
—

 
1,132

Cash and cash equivalents – beginning balance
—

 
725

 
16

 
5

 
—

 
746

Cash and cash equivalents – ending balance
$
—

 
$
1,856

 
$
20

 
$
2

 
$
—

 
$
1,878


52

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES
A DEBTOR-IN-POSSESSION
Condensed Consolidating Balance Sheets
June 30, 2015
(millions of dollars)

 
Parent
Guarantor
 
Issuer
 
Other
Guarantors
 
Non-guarantors
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
—

 
$
1,364

 
$
18

 
$
11

 
$
—

 
$
1,393

Restricted cash
—

 
399

 
2

 
—

 
—

 
401

Advances to parent and affiliates
—

 
6

 
1,510

 
—

 
(1,510
)
 
6

Trade accounts receivable – net
—

 
—

 
680

 
—

 
—

 
680

Income taxes receivable
1

 
389

 
—

 
—

 
(390
)
 
—

Accounts receivable from affiliates
—

 
4

 
—

 
—

 
(4
)
 
—

Inventories
—

 
—

 
441

 
—

 
—

 
441

Commodity and other derivative contractual assets
—

 
—

 
396

 
—

 
—

 
396

Other current assets
—

 
4

 
57

 
—

 
—

 
61

Total current assets
1

 
2,166

 
3,104

 
11

 
(1,904
)
 
3,378

Restricted cash
—

 
506

 
—

 
—

 
—

 
506

Investments
(29,666
)
 
10,529

 
973

 
5

 
19,109

 
950

Property, plant and equipment – net
—

 
19

 
11,376

 
3

 
—

 
11,398

Advances to parent and affiliates
—

 
5

 
—

 
—

 
—

 
5

Goodwill
—

 
1,652

 
—

 
—

 
—

 
1,652

Identifiable intangible assets – net
—

 
27

 
1,184

 
—

 
—

 
1,211

Commodity and other derivative contractual assets
—

 
—

 
17

 
—

 
—

 
17

Accumulated deferred income taxes
—

 
813

 
—

 
14

 
(827
)
 
—

Other noncurrent assets
—

 
3

 
41

 
—

 
—

 
44

Total assets
$
(29,665
)
 
$
15,720

 
$
16,695

 
$
33

 
$
16,378

 
$
19,161

 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND MEMBERSHIP INTERESTS
 
 
 
 
 
 
 
 
 
 
Borrowings under debtor-in-possession credit facility due currently
$
—

 
$
1,425

 
$
—

 
$
—

 
$
—

 
$
1,425

Notes/advances from affiliates
15

 
1,495

 
—

 
—

 
(1,510
)
 
—

Long-term debt due currently
13

 
—

 
18

 
—

 
—

 
31

Trade accounts payable
—

 
13

 
344

 
—

 
—

 
357

Trade accounts and other payables to affiliates
—

 
—

 
164

 
—

 
(4
)
 
160

Commodity and other derivative contractual liabilities
—

 
—

 
168

 
—

 
—

 
168

Margin deposits related to commodity positions
—

 
—

 
64

 
—

 
—

 
64

Accumulated deferred income taxes
24

 
43

 
43

 
—

 
—

 
110

Accrued income taxes payable to parent
—

 
—

 
389

 
2

 
(390
)
 
1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

53

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES
A DEBTOR-IN-POSSESSION
Condensed Consolidating Balance Sheets
June 30, 2015
(millions of dollars)

 
Parent
Guarantor
 
Issuer
 
Other
Guarantors
 
Non-guarantors
 
Eliminations
 
Consolidated
Accrued taxes other than income
$
—

 
$
—

 
$
66

 
$
—

 
$
—

 
$
66

Accrued interest
—

 
113

 
1

 
—

 
—

 
114

Other current liabilities
1

 
46

 
189

 
—

 
—

 
236

Total current liabilities
53

 
3,135

 
1,446

 
2

 
(1,904
)
 
2,732

Accumulated deferred income taxes
28

 
—

 
679

 
—

 
(68
)
 
639

Commodity and other derivative contractual liabilities
—

 
—

 
4

 
—

 
—

 
4

Notes or other liabilities due affiliates
—

 
—

 
—

 
2

 
(2
)
 
—

Long-term debt, less amounts due currently
31

 
—

 
48

 
—

 
—

 
79

Liabilities subject to compromise
144

 
42,255

 
32,547

 
—

 
(40,931
)
 
34,015

Other noncurrent liabilities and deferred credits
1

 
(4
)
 
1,710

 
—

 
—

 
1,707

Total liabilities
257

 
45,386

 
36,434

 
4

 
(42,905
)
 
39,176

Total membership interests
(29,922
)
 
(29,666
)
 
(19,739
)
 
29

 
59,283

 
(20,015
)
Total liabilities and membership interests
$
(29,665
)
 
$
15,720

 
$
16,695

 
$
33

 
$
16,378

 
$
19,161



54


ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES
A DEBTOR-IN-POSSESSION
Condensed Consolidating Balance Sheets
December 31, 2014
(millions of dollars)

 
Parent
Guarantor
 
Issuer
 
Other
Guarantors
 
Non-guarantors
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
—

 
$
1,826

 
$
16

 
$
1

 
$
—

 
$
1,843

Restricted cash
—

 
—

 
2

 
—

 
—

 
2

Advances to parent and affiliates
—

 
8

 
1,179

 
—

 
(1,179
)
 
8

Trade accounts receivable – net
—

 
—

 
588

 
—

 
—

 
588

Income taxes receivable
—

 
176

 
—

 
—

 
(176
)
 
—

Inventories
—

 
—

 
468

 
—

 
—

 
468

Commodity and other derivative contractual assets
—

 
—

 
492

 
—

 
—

 
492

Other current assets
—

 
9

 
59

 
—

 
—

 
68

Total current assets
—

 
2,019

 
2,804

 
1

 
(1,355
)
 
3,469

Restricted cash
—

 
901

 
—

 
—

 
—

 
901

Investments
(28,114
)
 
10,845

 
958

 
8

 
17,244

 
941

Property, plant and equipment – net
—

 
34

 
12,251

 
3

 
—

 
12,288

Advances to parent and affiliates
—

 
7

 
—

 
—

 
—

 
7

Goodwill
—

 
2,352

 
—

 
—

 
—

 
2,352

Identifiable intangible assets – net
—

 
14

 
1,322

 
—

 
—

 
1,336

Commodity and other derivative contractual assets
—

 
—

 
5

 
—

 
—

 
5

Accumulated deferred income taxes
—

 
757

 
—

 
15

 
(772
)
 
—

Other noncurrent assets, principally unamortized debt amendment and issuance costs
—

 
3

 
31

 
—

 
—

 
34

Total assets
$
(28,114
)
 
$
16,932

 
$
17,371

 
$
27

 
$
15,117

 
$
21,333

LIABILITIES AND MEMBERSHIP INTERESTS
 
 
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
 
 
Notes/advances from affiliates
$
8

 
$
1,171

 
$
—

 
$
—

 
$
(1,179
)
 
$
—

Long-term debt due currently
13

 
—

 
22

 
—

 
—

 
35

Trade accounts payable
—

 
7

 
375

 
—

 
—

 
382

Trade accounts and other payables to affiliates
2

 
7

 
154

 
2

 
—

 
165

Commodity and other derivative contractual liabilities
—

 
—

 
316

 
—

 
—

 
316

Margin deposits related to commodity positions
—

 
—

 
26

 
—

 
—

 
26

Accumulated deferred income taxes
24

 
47

 
43

 
—

 
—

 
114

Accrued income taxes payable to parent
—

 
—

 
192

 
—

 
(176
)
 
16

 
 
 
 
 
 
 
 
 
 
 
 

55

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES
A DEBTOR-IN-POSSESSION
Condensed Consolidating Balance Sheets
December 31, 2014
(millions of dollars)

 
Parent
Guarantor
 
Issuer
 
Other
Guarantors
 
Non-guarantors
 
Eliminations
 
Consolidated
Accrued taxes other than income
$
—

 
$
—

 
$
107

 
$
—

 
$
—

 
$
107

Accrued interest
—

 
116

 
1

 
—

 
—

 
117

Other current liabilities
—

 
37

 
227

 
—

 
—

 
264

Total current liabilities
47

 
1,385

 
1,463

 
2

 
(1,355
)
 
1,542

Accumulated deferred income taxes
40

 
—

 
944

 
—

 
38

 
1,022

Commodity and other derivative contractual liabilities
—

 
—

 
1

 
—

 
—

 
1

Borrowings under debtor-in-possession credit facility
—

 
1,425

 
—

 
—

 
—

 
1,425

Long-term debt, less amounts due currently
34

 
—

 
51

 
—

 
—

 
85

Liabilities subject to compromise
144

 
42,239

 
32,581

 
—

 
(40,931
)
 
34,033

Other noncurrent liabilities and deferred credits
—

 
(3
)
 
1,702

 
—

 
—

 
1,699

Total liabilities
265

 
45,046

 
36,742

 
2

 
(42,248
)
 
39,807

EFCH membership interests
(28,379
)
 
(28,114
)
 
(19,371
)
 
25

 
57,365

 
(18,474
)
Noncontrolling interests in subsidiaries
—

 
—

 
—

 
—

 
—

 
—

Total membership interests
(28,379
)
 
(28,114
)
 
(19,371
)
 
25

 
57,365

 
(18,474
)
Total liabilities and membership interests
$
(28,114
)
 
$
16,932

 
$
17,371

 
$
27

 
$
15,117

 
$
21,333


56

Item 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations for the three and six months ended June 30, 2015 and 2014 should be read in conjunction with our condensed 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

EFCH, a Delaware limited liability company and a wholly owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. We conduct our operations almost entirely through our wholly owned subsidiary, TCEH. 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. Key management activities, including commodity risk management and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis; consequently, there are no 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 (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.

For additional discussion of the Bankruptcy Filing and its effects, see Note 2 to the Financial Statements. See Note 8 to the Financial Statements for discussion of the TCEH DIP Facility.

Proposed Restructuring Plan — In July 2015, the Debtors filed the Plan of Reorganization and Disclosure Statement with the Bankruptcy Court. For additional discussion see Note 2 to the Financial Statements.

Proposed Sale of EFH Corp.'s Indirect Economic Ownership Interest in Oncor — In January 2015, the Bankruptcy Court approved the Debtors' bidding procedures motion that sets forth the process by which the Debtors are authorized to solicit proposals (i.e., bids) from third parties to acquire (in any form and employing any structure, whether taxable (in whole or in part) or tax-free) EFH Corp.'s indirect economic ownership interest in Oncor in accordance with the Bankruptcy Code. These bidding procedures contemplated that the Debtors select a stalking horse bid after a two-stage closed bidding process, and, after approval by the Bankruptcy Court of such stalking horse bid, the Debtors conduct a round of open bidding culminating in an auction intended to obtain a higher or otherwise best bid for a transaction. Initial bids were received in early March 2015 and second round bids were received in April 2015. Following receipt and negotiation of second round bids, the Debtors elected not to select a stalking horse bid. The Debtors continue to engage in discussions with various interested parties regarding the formal auction process as well as potential transactions in the context of modifications to, or alternatives to, the Plan of Reorganization. Certain of the potential transactions the Debtors are discussing with certain creditor constituencies would involve converting Oncor into a real estate investment trust (a REIT).

Overall Hedged Generation Position — Taking together forward wholesale and retail electricity sales with all hedging positions, at June 30, 2015 and December 31, 2014, we had effectively hedged an estimated 96% and 79%, respectively, of the price exposure, on a natural gas equivalent basis, related to our expected generation output for 2015 (assuming an 8.5 market heat rate). The majority of our third-party hedges are financial natural gas positions.


57

Commodity Price Sensitivities — 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 June 30, 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 2015
 
2016
$1.00/MMBtu change in natural gas price (a)(b)
$ ~8
 
$ ~65
0.1/MMBtu/MWh change in market heat rate (c)
$ ~1
 
$ ~10

___________
(a)
Balance of 2015 is from August 1, 2015 through December 31, 2015.
(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 June 30, 2015.

Impairment of Goodwill — In the three months ended March 31, 2015 and the years ended 2014, 2013 and 2012, we recorded $700 million, $1.6 billion, $1.0 billion and $1.2 billion, respectively, in noncash goodwill impairment charges (which were not deductible for income tax purposes). The write-offs reflected the effect of lower wholesale electricity prices in ERCOT, driven by the sustained decline in natural gas prices. Recorded goodwill totaled $1.652 billion at June 30, 2015. See Note 3 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 EFCH or its subsidiaries to be in default under any of their respective debt covenants or have a material impact on liquidity.

Impairment of Long-Lived Assets — EFCH records 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. During the three months ended March 31, 2015, continued decreases in forecasted wholesale electricity prices in ERCOT resulted in a $676 million noncash impairment charge recorded related to our Big Brown generation facility (see Note 5 to the Financial Statements for further discussion). 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.

Seasonal Suspension of Certain Generation Operations — In July 2015, we filed notice with ERCOT that we intend to seasonally suspend operations at a second of the three units at our Martin Lake generation facility. We also continue to seasonally suspend operations at two of the three units at our Monticello generation facility. We decided to take this action due to low wholesale electricity prices and other market conditions impacting these facilities. While the units are under seasonal suspension they will generally only run in the summer months, but after notification to ERCOT we can run them in other months. We will continue to monitor wholesale electricity prices and market conditions in determining whether to continue seasonal operations and/or return the units to service prior to peak demand months.

Environmental Matters — See Note 10 to Financial Statements for a discussion of the CSAPR and other EPA actions as well as related litigation.


58

Recent Global Climate Change Legislation — 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 2, 2011 - the first date that new motor vehicles were required to meet the new GHG standards. 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 proposed three rules to address greenhouse gas (GHG) emissions from new, modified and reconstructed, and existing electricity generation plants. In January 2014, the EPA proposed standards to regulate CO2 emissions from new electricity generation plants. Luminant filed comments on the proposed standards for new sources in May 2014. In June 2014, the EPA proposed two additional rules: 1) guidelines for states to develop standards that address CO2 emissions from existing electricity generation plants, and 2) proposed standards for modified and reconstructed electricity generation plants. The proposed guidelines for existing plants would establish state-specific emission rate goals to reduce nationwide CO2 emissions related to electricity generation by approximately 17% from 2012 emission levels by 2030. For Texas, the EPA would establish an interim emission rate goal for the electricity generation sector of 853 pounds CO2/MWh averaged between 2020-2029 and a final emission rate goal of 791 pounds CO2/MWh by 2030. The 2030 goal represents an approximate 40% reduction in the CO2 emission rate for Texas electricity generation using EPA's 2012 baseline and calculation methodology. The EPA developed this emission rate goal based on the application of a six percent efficiency improvement in converting fuel to electricity, an increase in the dispatch of natural gas combined cycle units, an increase in renewable electricity generation in the state and assumptions about improvement in demand side management of electricity use. In September 2014, the comment deadline on the proposed guidelines for existing electricity generation plants was extended 45 days to December 1, 2014. Luminant filed comments on the proposed guidelines for modified and reconstructed sources in October 2014. The EPA is expected to finalize the guidelines by summer 2015. Under the proposed guidelines, states will be required to submit to the EPA their program plans by June 2016, but may request an extension if certain commitments are met. While we cannot predict the outcome of this rulemaking on our results of operations, liquidity or financial condition, the impacts could be material.

Mercury and Air Toxics Standard (MATS) — In December 2011, the EPA finalized the MATS rule, which 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 as finalized would need to be installed within three years from the April 2012 effective date of the rule unless a one-year extension is granted. The TCEQ has granted one-year MATS compliance extensions for our Big Brown, Martin Lake, Monticello and Sandow 4 generation facilities.

In July 2014, certain parties petitioned the US Supreme Court to review the MATS rule. In November 2014, the US Supreme Court granted review of the MATS case on 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. In June 2015, the US Supreme Court reversed and remanded the MATS rule back to the D.C. Circuit Court for further consideration. The US Supreme Court held that the EPA must consider cost, including cost of compliance, before deciding whether regulation is appropriate and necessary. The MATS rule remains in effect, and generation units must continue to comply pending further action from the D.C. Circuit Court. 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.


59

Regional Haze — The Regional Haze Program of the Clean Air Act (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 NOX 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 CAIR or 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 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 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. The consolidated cases now in the D.C. Circuit Court are currently stayed. Following the US Supreme Court's ruling in the CSAPR litigation, the case remains stayed in the D.C. Circuit Court. In December 2014, the EPA filed an unopposed motion to continue to hold the case in abeyance pending a decision in the CSAPR litigation that is pending in the D.C. Circuit Court on remand from the US Supreme Court as described in Note 10 to the Financial Statements.

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 EPA proposed its rule in November 2014 and is currently scheduled to finalize the rule in December 2015.

In June 2014, the EPA issued requests for information under Section 114 of the CAA to Luminant and other generators in Texas. In November 2014, the EPA released a proposed rule approving in part and disapproving in part Texas' SIP for Regional Haze and proposing a FIP for Regional Haze. In the proposed 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. Consistent with how the EPA has applied Regional Haze rules to other states, the EPA's final rule confirms that Texas's compliance with the CSAPR will satisfy its obligations under the BART portion of the Regional Haze Program. However, 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 proposed rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the proposed FIP (if those limits are even possible to attain) would likely challenge the long-term viability of those units. Luminant, the State of Texas, and many others filed comments on the EPA's proposal in April 2015, and the rule is expected to be finalized in December 2015. As discussed in detail in these comments, we and others believe this proposed rule is unlawful and must be withdrawn. As proposed, the scrubber upgrades would be required three years after the rule is finalized, and the new scrubbers would be required five years after the rule is finalized. Assuming the proposed rule is finalized in December 2015, compliance would be required beginning in December 2018 and December 2020, respectively. While we cannot predict the outcome of the final rule, the result may have a material impact 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. We are in the process of reviewing the proposed rule and assessing the financial and operational impacts to our lignite mines.


60

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 against allegations of abuse of market power through economic withholding with respect to the specific behaviors addressed by the plan.



61

RESULTS OF OPERATIONS
Sales Volume and Customer Count Data

 
Three Months Ended June 30,
 
% Change
 
Six Months Ended June 30,
 
% Change
 
2015
 
2014
 
2015
 
2014
 
Sales volumes:
 
 
 
 
 
 
 
 
 
 
 
Retail electricity sales volumes – (GWh):
 
 
 
 
 
 
 
 
 
 
 
Residential
4,990

 
5,070

 
(1.6
)%
 
10,098

 
10,245

 
(1.4
)%
Small business (a)
1,491

 
1,393

 
7.0
 %
 
2,987

 
2,661

 
12.3
 %
Large business and other customers
3,307

 
2,650

 
24.8
 %
 
6,175

 
4,921

 
25.5
 %
Total retail electricity
9,788

 
9,113

 
7.4
 %
 
19,260

 
17,827

 
8.0
 %
Wholesale electricity sales volumes (b)
5,256

 
7,201

 
(27.0
)%
 
10,625

 
17,002

 
(37.5
)%
Total sales volumes
15,044

 
16,314

 
(7.8
)%
 
29,885

 
34,829

 
(14.2
)%
 
 
 
 
 
 
 
 
 
 
 
 
Average volume (kilowatt-hours) per residential customer (c)
3,330

 
3,361

 
(0.9
)%
 
6,745

 
6,768

 
(0.3
)%
 
 
 
 
 
 
 
 
 
 
 
 
Weather (North Texas average) – percent of normal (d):
 
 
 
 
 
 
 
 
 
 
 
Cooling degree days
86.1
%
 
100.1
%
 
(14.0
)%
 
87.1
%
 
98.8
%
 
(11.8
)%
Heating degree days
95.8
%
 
179.8
%
 
(46.7
)%
 
118.9
%
 
121.9
%
 
(2.5
)%
 
 
 
 
 
 
 
 
 
 
 
 
Customer counts:
 
 
 
 
 
 
 
 
 
 
 
Retail electricity customers (end of period, in thousands) (e):
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 
 
 
 
 
1,495

 
1,511

 
(1.1
)%
Small business (a)
 
 
 
 
 
 
177

 
177

 
—
 %
Large business and other customers
 
 
 
 
 
 
27

 
20

 
35.0
 %
Total retail electricity customers
 
 
 
 
 
 
1,699

 
1,708

 
(0.5
)%
____________
(a)
Customers with demand of less than 1 MW annually.
(b)
Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.
(c)
Calculated using average number of customers for the period.
(d)
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.
(e)
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.



62

Revenue and Commodity Hedging and Trading Activities

 
Three Months Ended June 30,
 
% Change
 
Six Months Ended June 30,
 
% Change
 
2015
 
2014
 
2015
 
2014
 
Operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Retail electricity revenues:
 
 
 
 
 
 
 
 
 
 
 
Residential
$
674

 
$
690

 
(2.3
)%
 
$
1,365

 
$
1,373

 
(0.6
)%
Small business (a)
168

 
168

 
—
 %
 
342

 
330

 
3.6
 %
Large business and other customers
209

 
187

 
11.8
 %
 
397

 
347

 
14.4
 %
Total retail electricity revenues
1,051

 
1,045

 
0.6
 %
 
2,104

 
2,050

 
2.6
 %
Wholesale electricity revenues (b)(c)
152

 
291

 
(47.8
)%
 
300

 
720

 
(58.3
)%
Amortization of intangibles (d)
6

 
6

 
—
 %
 
12

 
12

 
—
 %
Other operating revenues
47

 
64

 
(26.6
)%
 
111

 
142

 
(21.8
)%
Total operating revenues
$
1,256

 
$
1,406

 
(10.7
)%
 
$
2,527

 
$
2,924

 
(13.6
)%
 
 
 
 
 
 
 
 
 
 
 
 
Net gain (loss) from commodity hedging and trading activities:
 
 
 
 
 
 
 
 
 
 
 
Realized net gains
$
49

 
$
328

 
 
 
$
51

 
$
363

 
 
Unrealized net gains (losses)
(29
)
 
(301
)
 
 
 
72

 
(555
)
 
 
Total
$
20

 
$
27

 
 
 
$
123

 
$
(192
)
 
 
____________
(a)
Customers with demand of less than 1 MW annually.
(b)
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.
(c)
Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.
(d)
Represents amortization of the intangible net asset value of retail and wholesale electricity sales agreements resulting from purchase accounting.


63

Production, Purchased Power and Delivery Cost Data

 
Three Months Ended June 30,
 
% Change
 
Six Months Ended June 30,
 
% Change
 
2015
 
2014
 
2015
 
2014
 
Fuel, purchased power costs and delivery fees ($ millions):
 
 
 
 
 
 
 
 
 
 
 
Fuel for nuclear facilities
$
39

 
$
36

 
8.3
 %
 
$
78

 
$
79

 
(1.3
)%
Fuel for lignite/coal facilities
184

 
172

 
7.0
 %
 
324

 
385

 
(15.8
)%
Total nuclear and lignite/coal facilities
223

 
208

 
7.2
 %
 
402

 
464

 
(13.4
)%
Fuel for natural gas facilities and purchased power costs (a)
60

 
74

 
(18.9
)%
 
122

 
159

 
(23.3
)%
Amortization of intangibles (b)
—

 
11

 
—
 %
 
1

 
20

 
(95.0
)%
Other costs
36

 
53

 
(32.1
)%
 
77

 
125

 
(38.4
)%
Fuel and purchased power costs
319

 
346

 
(7.8
)%
 
602

 
768

 
(21.6
)%
Delivery fees
327

 
310

 
5.5
 %
 
657

 
620

 
6.0
 %
Total
$
646

 
$
656

 
(1.5
)%
 
$
1,259

 
$
1,388

 
(9.3
)%
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
 
 
 
 
 
 
 
 
 
 
 
Nuclear facilities
$
7.47

 
$
8.04

 
(7.1
)%
 
$
7.36

 
$
8.23

 
(10.6
)%
Lignite/coal facilities (c)
$
27.85

 
$
20.01

 
39.2
 %
 
$
24.26

 
$
20.57

 
17.9
 %
Natural gas facilities and purchased power (d)
$
50.34

 
$
46.58

 
8.1
 %
 
$
47.96

 
$
49.94

 
(4.0
)%
 
 
 
 
 
 
 
 
 
 
 
 
Delivery fees per MWh
$
33.21

 
$
33.92

 
(2.1
)%
 
$
33.95

 
$
34.64

 
(2.0
)%
 
 
 
 
 
 
 
 
 
 
 
 
Production and purchased power volumes (GWh):
 
 
 
 
 
 
 
 
 
 
 
Nuclear facilities
5,239

 
4,505

 
16.3
 %
 
10,521

 
9,571

 
9.9
 %
Lignite/coal facilities (e)
9,259

 
10,841

 
(14.6
)%
 
18,057

 
23,254

 
(22.3
)%
Total nuclear and lignite/coal facilities
14,498

 
15,346

 
(5.5
)%
 
28,578

 
32,825

 
(12.9
)%
Natural gas facilities
81

 
142

 
(43.0
)%
 
141

 
334

 
(57.8
)%
Purchased power (f)
465

 
826

 
(43.7
)%
 
1,166

 
1,670

 
(30.2
)%
Total energy supply volumes
15,044

 
16,314

 
(7.8
)%
 
29,885

 
34,829

 
(14.2
)%
 
 
 
 
 
 
 
 
 
 
 
 
Capacity factors:
 
 
 
 
 
 
 
 
 
 
 
Nuclear facilities
104.3
%
 
89.7
%
 
16.3
 %
 
105.3
%
 
95.8
%
 
9.9
 %
Lignite/coal facilities (e)
52.9
%
 
61.9
%
 
(14.5
)%
 
51.9
%
 
66.8
%
 
(22.3
)%
Total
64.3
%
 
68.1
%
 
(5.6
)%
 
63.8
%
 
73.3
%
 
(13.0
)%
____________
(a)
See note (b) to the Revenue and Commodity Hedging and Trading Activities table on previous page.
(b)
Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.
(c)
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 (b) to the Revenue and Commodity Hedging and Trading Activities table on the previous page.
(d)
Excludes volumes related to line loss and power imbalances and unrealized amounts referenced in footnote (d) immediately above.
(e)
Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal fueled units totaling 4,930 GWh and 4,550 GWh for the three months ended June 30, 2015 and 2014, respectively, and 12,090 GWh and 8,290 GWh for the six months ended June 30, 2015 and 2014, respectively.
(f)
Includes amounts related to line loss and power imbalances.


64

Financial Results — Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Operating revenues decreased $150 million, or 11%, to $1.256 billion in 2015.

Retail electricity revenues increased $6 million, or 1%, to $1.051 billion in 2015 primarily reflecting an increase in sales volumes related to business markets customers, partially offset by lower average retail prices for business markets customers.

Wholesale electricity revenues decreased $139 million, or 48%, to $152 million in 2015 reflecting a $79 million decrease in sales volumes and a $60 million decrease due to lower average wholesale electricity prices. A 27% decrease in wholesale sales volumes was driven by lower generation volumes that resulted from timing and scope of outages and increased economic backdown (including seasonal operations) at our generation facilities. The increased economic backdown of our generation facilities and the lower average wholesale electricity sales prices were primarily driven by a 35% decline in average wholesale electricity prices in the three months ended June 30, 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 $10 million, or 2%, to $646 million in 2015. Lignite/coal fuel costs increased $12 million reflecting higher lignite mining costs and more western coal in the fuel blend, partially offset by lower generation volumes. Fuel for natural gas facilities and purchased power costs decreased $14 million reflecting lower generation from natural gas generation units and a decrease in purchased power volumes. Amortization of intangibles decreased $11 million reflecting decreased amortization of favorable purchase contracts due to impairments recorded at the end of 2014. Other costs decreased $17 million largely due to a $13 million decrease in natural gas purchases for resale and a decrease of $3 million in ERCOT ancillary service fees, both driven by lower prices for natural gas in 2015. Delivery fees increased $17 million reflecting higher retail volumes, partially offset by lower delivery rates.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $20 million and $27 million in net gains for the three months ended June 30, 2015 and 2014, respectively, and included the natural gas hedging positions as well as other hedging positions.
 
Three Months Ended June 30, 2015
 
Net Realized
Gains
 
Net Unrealized
Losses
 
Total
Hedging positions
$
43

 
$
(20
)
 
$
23

Trading positions
6

 
(9
)
 
(3
)
Total
$
49

 
$
(29
)
 
$
20


 
Three Months Ended June 30, 2014
 
Net Realized
Gains
 
Net Unrealized
Gains (Losses)
 
Total
Hedging positions
$
328

 
$
(304
)
 
$
24

Trading positions
—

 
3

 
3

Total
$
328

 
$
(301
)
 
$
27



The $279 million decrease in realized gains on hedging and trading positions reflected the termination of our favorable natural gas hedging program in 2014, partially offset by realized gains on hedges due to declining market prices in 2015. The termination of our favorable natural gas hedging program in 2014 accelerated realized gains (offsetting the reversal of previously recognized unrealized gains as noted below).

The $272 million decrease in unrealized losses reflected the termination of our natural gas hedging program, partially offset by other unrealized losses. The termination in 2014 accelerated the reversal of previously recognized unrealized gains (offsetting the realized gains noted above). The other unrealized losses were driven by decreasing market prices in 2015, which resulted in the reversal of previously recognized unrealized gains.


65

Operating costs decreased $25 million, or 10%, to $217 million in 2015. The decrease was primarily driven by $34 million in lower nuclear maintenance costs reflecting a spring refueling outage in 2014, partially offset by $8 million in higher maintenance costs at lignite/coal fueled generation facilities.

Depreciation and amortization expenses decreased $110 million, or 33%, to $219 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 the first quarter of 2015.

SG&A expenses decreased $8 million, or 5%, to $161 million in 2015 primarily reflecting legal and other professional services costs associated with our debt restructuring activities prior to the Petition Date being reported in SG&A in 2014, compared to legal and professional service costs associated with the Chapter 11 Cases since the Petition Date being reported in reorganization items as discussed below.

In 2014, noncash impairments of certain long-lived assets totaling $21 million were recorded as discussed in Note 5 to the Financial Statements.

Interest expense and related charges decreased $125 million, or 28%, to $322 million in 2015. The decrease reflected:

•
$212 million in lower interest expense on pre-petition debt due to the discontinuance of interest due to the Chapter 11 Cases, and
•
$20 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

•
$96 million in higher expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of TCEH secured creditors in 2015 as compared to the post-petition period ended June 30, 2014, and
•
$10 million in higher interest expense on debtor-in-possession financing in 2015 as compared to the post-petition period ended June 30, 2014.

Reorganization items totaled $40 million and $423 million in the three months ended June 30, 2015 and the post-petition period ended June 30, 2014, respectively. Activity in 2015 included $24 million in legal advisory and representation services fees and $17 million in other professional consulting and advisory services fees. Activity in 2014 included a $277 million liability adjustment arising from termination of interest rate swap agreements and natural gas hedging positions (see Note 13 to Financial Statements), $92 million in fees associated with completion of the TCEH DIP Facility (discussed in Note 8to Financial Statements), $21 million in legal advisory and representation services fees and $32 million in other professional consulting and advisory services fees. See Note 7 to the Financial Statements for additional discussion.

Income tax benefit totaled $107 million and $269 million in 2015 and 2014, respectively. The effective income tax rate was 33.1% in 2015 and 31.5% in 2014. The increase in the effective income tax rate is driven primarily by lower state tax expense due to the Texas Margin Tax rate reduction, partially offset by higher nondeductible legal and other professional services costs related to the Chapter 11 Cases in 2015.

Net loss decreased $369 million to $216 million in 2015. The decrease primarily reflected the higher reorganization costs incurred in 2014, the decrease in interest expense and lower depreciation and amortization expense.


66

Financial Results — Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Operating revenues decreased $397 million, or 14%, to $2.527 billion in 2015.

Retail electricity revenues increased $54 million, or 3%, to $2.104 billion in 2015 reflecting an increase in business markets sales volumes, partially offset by lower average retail prices for business markets customers.

Wholesale electricity revenues decreased $420 million, or 58%, to $300 million in 2015 reflecting a $270 million decrease in sales volumes and $150 million decrease due to lower average wholesale electricity prices. A 38% decrease in wholesale sales volumes was driven by lower generation volumes that resulted from increased economic backdown (including seasonal operations) at our generation facilities. The increased economic backdown of our generation facilities and the lower average wholesale electricity sales prices were primarily driven by a 40% decline in average wholesale electricity prices in the six months ended June 30, 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 $129 million, or 9%, to $1.259 billion in 2015. Lignite/coal fuel costs decreased $61 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 $37 million reflecting lower generation from natural gas generation units and a 30% decrease in purchased power volumes. Amortization of intangibles decreased $19 million reflecting decreased amortization of favorable purchase contracts due to impairments recorded at the end of 2014. Other costs decreased $48 million largely reflecting a $29 million decrease in natural gas purchases for resale and an $18 million decrease in ERCOT ancillary service fees, both driven by lower natural gas prices in 2015. Delivery fees increased $37 million reflecting higher retail volumes, partially offset by lower delivery rates.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $123 million in net gains and $192 million in net losses for the six months ended June 30, 2015 and 2014, respectively, and included the natural gas hedging positions as well as other hedging positions.
 
Six Months Ended June 30, 2015
 
Net Realized
Gains
 
Net Unrealized
Gains
 
Total
Hedging positions
$
50

 
$
71

 
$
121

Trading positions
1

 
1

 
2

Total
$
51

 
$
72

 
$
123


 
Six Months Ended June 30, 2014
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Total
Hedging positions
$
368

 
$
(561
)
 
$
(193
)
Trading positions
(5
)
 
6

 
1

Total
$
363

 
$
(555
)
 
$
(192
)

Net realized gains on hedging and trading positions decreased by $312 million reflecting lower gains due to the termination of our favorable natural gas hedging program, partially offset by other realized gains from declining market prices in 2015. The impact of the natural gas hedging program includes accelerated realized gains resulting from the 2014 program termination (offsetting the reversal of previously unrealized gains as noted below), as well as realized gains from the program pricing.

The $627 million decrease in unrealized losses versus the prior year reflected the impact of our natural gas hedging program, partially offset by other unrealized losses. The impact of the natural gas hedging program included an acceleration of the reversal of previously recognized unrealized gains resulting from the 2014 termination (offsetting the realized gains as noted above), as well as the reversal of previously recorded unrealized gains from the program pricing. The other unrealized losses were driven by decreasing market prices, which resulted in the reversal of previously recognized unrealized gains.

Operating costs decreased $45 million, or 10%, to $410 million in 2015. The decrease was primarily driven by $45 million in lower nuclear maintenance costs reflecting a spring refueling outage in 2014.


67

Depreciation and amortization expenses decreased $222 million, or 34%, to $434 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 the first quarter of 2015.

SG&A expenses decreased $43 million, or 12%, to $321 million in 2015 reflecting $27 million in legal and other professional services costs associated with our debt restructuring activities prior to the Petition Date being reported in SG&A in 2014, compared to legal and professional services costs associated with the Chapter 11 Cases since the Petition Date being reported in reorganization items as discussed below. SG&A expenses in 2015 are also lower due to $10 million in lower employee compensation and benefits.

In 2015, a noncash impairment of goodwill totaling $700 million was recorded as discussed in Note 4 to the Financial Statements.

In 2015 and 2014, noncash impairments of certain long-lived assets totaling $676 million and $21 million, respectively, were recorded as discussed in Note 5 to the Financial Statements.

Other deductions totaled $61 million in 2015 and $3 million in 2014. Other deductions in 2015 included a $51 million impairment of emission allowances and an $8 million impairment of favorable purchase contracts (see Note 3 to the Financial Statements).

Interest expense and related charges decreased $473 million, or 43%, to $639 million in 2015. The decrease reflected:

•
$879 million in lower interest expense on pre-petition debt due to the discontinuance of interest due to the Chapter 11 Cases, and
•
$85 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

•
$398 million in higher expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of TCEH secured creditors in 2015 as compared to 2014;
•
$65 million in mark-to-market net gains on interest rate swaps in 2014, and
•
$25 million in higher interest expense on debtor-in-possession financing in 2015 as compared to 2014.

Reorganization items totaled $114 million and $423 million in the six months ended June 30, 2015 and the post-petition period ended June 30, 2014, respectively. Activity in 2015 included $50 million in legal advisory and representation services fees, $33 million in other professional consulting and advisory services fees and $28 million primarily related to contract claim adjustments. Activity in 2014 included a $277 million liability adjustment arising from termination of interest rate swap agreements and natural gas hedging positions (see Note 13 to Financial Statements), $92 million in fees associated with completion of the TCEH DIP Facility discussed in Note 8 to Financial Statements, $21 million in legal advisory and representation services fees and $32 million in other professional consulting and advisory services fees. See Note 7 to the Financial Statements for additional discussion.

Income tax benefit totaled $400 million and $553 million on pretax losses in 2015 and 2014, respectively. Excluding the nondeductible goodwill impairment charge in 2015, the effective tax rate was 31.9% in 2015 and 32.9% in 2014. The decrease 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 2015, partially offset by the difference in the forecasted effective tax rate and the statutory rate applied to long-lived and intangible asset impairment charges and lower state tax expense due to the Texas Margin Tax rate reduction in 2015.

Net loss increased $423 million to $1.553 billion in 2015. The increase primarily reflected the noncash impairment of goodwill and the noncash impairments of certain long-lived assets, partially offset by the decrease in interest expense, the improved results from hedging and trading activities, the higher reorganization costs incurred in 2014 and lower depreciation and amortization expense.

68

Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the six months ended June 30, 2015 and 2014. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $72 million in unrealized net gains in 2015 and $550 million in unrealized net losses in 2014 arising from mark-to-market accounting for positions in the commodity contract portfolio.
 
Six Months Ended June 30,
 
2015
 
2014
Commodity contract net asset at beginning of period
$
180

 
$
525

Settlements/termination of positions (a)
(79
)
 
(382
)
Changes in fair value of positions in the portfolio (b)
151

 
(168
)
Other activity (c)
(11
)
 
22

Commodity contract net asset (liability) at end of period
$
241

 
$
(3
)
____________
(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 June 30, 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 June 30, 2015
Source of fair value
 
Less than
1 year
 
1-3 years
 
Total
Prices actively quoted
 
$
115

 
$
17

 
$
132

Prices provided by other external sources
 
59

 
6

 
65

Prices based on models
 
37

 
7

 
44

Total
 
$
211

 
$
30

 
$
241




69

FINANCIAL CONDITION

Cash Flows — Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014 — Cash used in operating activities totaled $216 million and $46 million in 2015 and 2014, respectively. The increase in cash used of $170 million primarily reflected lower cash used in 2014 due to delayed payments on accounts payable and accrued liabilities following the Petition Date, partially offset by a decrease in cash used for margin deposits.

Depreciation and amortization expense reported in the condensed statements of consolidated cash flows exceeded the amount reported in the condensed statements of consolidated income (loss) by $73 million and $80 million for the six months ended June 30, 2015 and 2014, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the condensed statements of consolidated income (loss) consistent with industry practice, and amortization of intangible assets arising from purchase accounting that is reported in various other condensed statements of consolidated income (loss) line items including operating revenues and fuel and purchased power costs and delivery fees.

Cash used in financing activities totaled $11 million in 2015 compared to cash provided by financing activities of $1.122 billion in 2014. Activity in 2014 reflected $1.425 billion in borrowings from the TCEH DIP Facility, partially offset by $203 million of pollution control revenue bonds tendered and $92 million in payment for fees associated with completion of the TCEH DIP Facility.

Cash used in investing activities totaled $223 million in 2015 compared to cash provided by investing activities of $56 million in 2014. Cash used in 2015 reflected capital expenditures (including nuclear fuel purchases) totaling $220 million. Cash provided in 2014 reflected $363 million in restricted cash released from an escrow account when certain letters of credit were drawn, partially offset by capital expenditures (including nuclear fuel purchases) totaling $229 million and a $53 million increase in restricted cash supporting letters of credit issued under the TCEH DIP Facility.

Debt Activity — Debt activities during the six months ended June 30, 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 borrowings in the six months ended June 30, 2015.
 
Settlements
TCEH (a)
$
(8
)
EFCH
(3
)
Total
$
(11
)
____________
(a)
Settlements include $6 million of payments of principal at scheduled maturity dates and $2 million of payments of capital lease liabilities.

See Notes 8 and 9 to the Financial Statements for further detail of the TCEH DIP Facility and pre-petition debt.

Available Liquidity — The following table summarizes changes in available liquidity for the six months ended June 30, 2015:
 
Available Liquidity
 
June 30, 2015
 
December 31, 2014
 
Change
Cash and cash equivalents (a)
$
1,393

 
$
1,843

 
$
(450
)
TCEH DIP Revolving Credit Facility (b)
1,950

 
1,950

 
—

Total liquidity
$
3,343

 
$
3,793

 
$
(450
)
___________
(a)
Cash and cash equivalents at June 30, 2015 and December 31, 2014 exclude $905 million and $901 million, respectively, of restricted cash held for letter of credit support. The June 30, 2015 restricted cash balance includes $506 million under the TCEH pre-petition Letter of Credit Facility and $399 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.


70

The decrease in available liquidity of $450 million in the six months ended June 30, 2015 primarily reflected $220 million in capital expenditures (including nuclear fuel purchases) and $216 million of cash used in operating activities. 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 TCEH DIP Facility (see Note 8 to the Financial Statements). The TCEH DIP Facility provides for $3.375 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 TCEH DIP Facility, plus cash generated from operations, to fund our anticipated cash requirements through at least the June 2016 maturity date of the TCEH DIP Facility.

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.

Capital Expenditures — In our 2014 Form 10-K, we projected annual capital expenditures in 2015 to total approximately $650 million. We currently project total annual capital expenditures for 2015 to total approximately $525 million. The decrease primarily reflects cancelled or deferred mining and generation projects and lower nuclear fuel costs driven by lower estimated prices.

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 8 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 June 30, 2015, 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 June 30, 2015, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

•
Less than $1 million in cash has been posted with counterparties as compared to $9 million posted at December 31, 2014;
•
$64 million in cash has been received from counterparties as compared to $26 million received at December 31, 2014;
•
$226 million in letters of credit have been posted with counterparties, as compared to $329 million posted at December 31, 2014, and
•
$12 million in letters of credit have been received from counterparties, as compared to $3 million received at December 31, 2014.

Because certain agreements related to these activities 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. If the agreements are terminated, such cash and letter of credit postings may be used in the ultimate settlement of the positions. See Note 13 to the Financial Statements for discussion of agreements terminated subsequent to the Bankruptcy Filing.


71

Income Tax Matters — EFH Corp. files a US federal income tax return that includes the results of EFCH and TCEH. EFH Corp. (parent entity) is a corporate member of the EFH Corp. consolidated group, while each of EFCH and TCEH is classified as a disregarded entity for US federal income tax purposes. Prior to a restructuring transaction in April 2013 that resulted in EFCH being converted from a Texas corporation to a Delaware limited liability company, EFCH was a corporate member of the 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 and TCEH) 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.

On June 15, 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.

Income Tax Payments — In the next twelve months, income tax payments related to the Texas margin tax are expected to total approximately $20 million, and no payments or refunds of federal income taxes are expected. Income tax payments totaled $24 million and $28 million (all Texas margin tax) for the six months ended June 30, 2015 and 2014, respectively. In April 2014, EFH Corp. paid the IRS $3 million in interest, thus settling all contested issues related to the 1997 through 2002 open tax years.

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 June 30, 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 six and twelve months ended June 30, 2015 totaled $729 million and $1.718 billion, respectively. See Exhibit 99(b) for a reconciliation of TCEH's net income (loss) to Consolidated EBITDA.

See Note 8 to the Financial Statements for discussion of other covenants related to the TCEH DIP Facility.

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 June 30, 2015, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $22 million, with $9 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 June 30, 2015, TCEH posted letters of credit in the amount of $62 million, which are subject to adjustments.


72

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, predominantly in the form of letters of credit, totaling $85 million at June 30, 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.

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 $35 million in remaining lease payments at June 30, 2015 and terminates in 2017, 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 $36 million in remaining lease payments at June 30, 2015 and terminates in 2029, 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.

Guarantees — See Note 9 to the Financial Statements for discussion of guarantees.


OFF–BALANCE SHEET ARRANGEMENTS

See Notes 1 and 9 to the Financial Statements regarding VIEs and guarantees, respectively.


COMMITMENTS AND CONTINGENCIES

See Note 10 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.



73

Item 3.
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.

EFH Corp. has a corporate risk management organization that is headed by the EFH Corp. 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

Our 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.

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.


74

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.
 
June 30, 2015
 
December 31, 2014
Month-end average MtM VaR:
$
75

 
$
50

Month-end high MtM VaR:
$
97

 
$
129

Month-end low MtM VaR:
$
59

 
$
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.
 
June 30, 2015
 
December 31, 2014
Month-end average EaR:
$
37

 
$
27

Month-end high EaR:
$
46

 
$
60

Month-end low EaR:
$
26

 
$
4


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

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 $882 million at June 30, 2015. The components of this exposure are discussed in more detail below.

Assets subject to credit risk at June 30, 2015 include $521 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $53 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 June 30, 2015, the exposure to credit risk from these counterparties totaled $361 million consisting of accounts receivable of $111 million and net asset positions related to commodity contracts of $250 million, after taking into account the netting provisions of the master agreements described above but before taking into account $77 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $284 million increased $39 million in the six months ended June 30, 2015.

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Of this $284 million net exposure, 94% 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 June 30, 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 condensed 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 13 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
$
337

 
$
70

 
$
267

Below investment grade
24

 
7

 
17

Totals
$
361

 
$
77

 
$
284

Investment grade
93.4
%
 
 
 
94.0
%
Below investment grade
6.6
%
 
 
 
6.0
%

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 three counterparties, which represented 16%, 13% and 10% of the $284 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.


76

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 in our 2014 Form 10-K and the discussion under Item 2, 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 obtain the necessary votes from the required creditors and stakeholders and the approval from the Bankruptcy Court for the Plan of Reorganization, particularly prior to the expiration of the exclusivity period granted by the Bankruptcy Court;
•
the outcome of the court supervised bid process with respect to the restructuring of EFH Corp. and EFIH;
•
our ability to obtain Bankruptcy Court approval with respect to our motions in the Chapter 11 Cases, including such approvals not being overturned on appeal or being stayed for any extended period of time;
•
the terms and conditions of any Chapter 11 plan of reorganization that is ultimately approved by the Bankruptcy Court;
•
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 TCEH DIP Facility;
•
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 of the Chapter 11 Cases;
•
the actions and decisions of regulatory authorities relative to any Chapter 11 plan of reorganization;
•
restrictions on our operations due to the terms of our debt agreements, including the TCEH DIP Facility, and restrictions imposed by the Bankruptcy Court;
•
our ability to obtain any required regulatory consent necessary to implement any Chapter 11 plan of reorganization;
•
the outcome of current or potential litigation regarding whether holders are entitled to make-whole or redemption premiums and/or post-petition interest in connection with the treatment of their claims in bankruptcy;
•
the outcome of current or potential litigation regarding intercompany claims and/or derivative claims;
•
prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the US Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Texas Reliability Entity Inc., the PUCT, the RCT, the NRC, the EPA, the TCEQ, the US Mine Safety and Health Administration and the US Commodity Futures Trading Commission, with respect to, among other things:
◦
allowed prices;
◦
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;

77

◦
changes in tax laws and policies;
◦
changes in and compliance with environmental and safety laws and policies, including the CSAPR, the Mercury and Air Toxics Standard, 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;
•
legal and administrative proceedings and settlements, including the legal proceedings arising out of the bankruptcy;
•
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;
•
changes in business strategy, development plans or vendor relationships;
•
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 TCEH DIP Facility:
•
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;
•
changes in assumptions used to estimate future executive compensation payments;
•
hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;
•
significant changes in critical accounting policies, 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.


78

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.



79

Item 4.
CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect at the end of the current period included in this quarterly report on Form 10-Q. Based on the evaluation performed as of June 30, 2015, our principal executive officer and principal financial officer concluded that due to the material weakness in our internal control over financial reporting related to accounting for deferred income taxes, as previously disclosed in our 2014 Form 10-K, our disclosure controls and procedures were not effective as of June 30, 2015. In light of the material weakness in internal control over financial reporting, management completed substantive procedures, including validating the completeness and accuracy of the underlying data used for accounting for deferred income taxes, prior to filing this quarterly report on Form 10-Q.

These additional procedures have allowed us to conclude that, notwithstanding the material weakness in internal control over financial reporting related to accounting for deferred income taxes, the consolidated financial statements included in this report fairly present, in all material respects, our financial position, results of operations and cash flows for the periods presented in conformity with GAAP. Additionally, no restatement of our previously issued consolidated financial statements was required.

Previously Reported Material Weakness

As previously disclosed in our 2014 Form 10-K, our management concluded that our internal control over financial reporting and our disclosure controls and procedures were ineffective as of December 31, 2014 due to a material weakness in accounting for deferred income taxes. Pursuant to SEC rules and regulations, a material weakness is "a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the registrant's annual or interim financial statements will not be prevented or detected on a timely basis".

In response to the material weakness described above, during the six months ended June 30, 2015, we began implementing a plan of remediation to strengthen our overall internal control over accounting for deferred income taxes. The remediation plan includes 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

•
hiring key personnel in our tax department and further evaluating staffing levels to ensure the execution of timely and rigorous control procedures.

Management is currently implementing these steps. Specifically, during the six months ended June 30, 2015, we hired permanent and temporary resources to supplement our current staffing levels in our tax department and implemented additional oversight and monitoring controls. Once these steps and new controls are placed in operation for a sufficient period of time, we will subject these controls and procedures to appropriate tests in order to determine whether they are operating effectively.

We are committed to maintaining a strong internal control environment and believe that these remediation efforts will represent improvements in our controls.

Changes in Internal Control over Financial Reporting

With the oversight of senior management and our audit committee, we have continued to remediate the underlying causes of the material weakness. Other than with respect to the ongoing plan for remediation of the material weakness, there has been no change to our internal control over financial reporting during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.



80

PART II.   OTHER INFORMATION

Item 1.
LEGAL PROCEEDINGS

Reference is made to the discussion in Note 10 to the Financial Statements regarding legal proceedings.


Item 1A.
RISK FACTORS

There have been no material changes from the risk factors discussed in Part I, Item 1A. Risk Factors in our 2014 Form 10-K and Part II, Item 1A. Risk Factors in our Form 10-Q for the period ended March 31, 2015, except for the information disclosed elsewhere in this quarterly report on Form 10-Q that provides factual updates to risk factors contained in our 2014 Form 10-K and our Form 10-Q for the period ended March 31, 2015. The risks described in such reports are not the only risks facing our company.

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. The 12 mines include eight that are active, two that are in development and two that are currently idle. 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 quarterly report on Form 10-Q.



81

Item 6. EXHIBITS

(a)
Exhibits filed or furnished as part of Part II are:
Exhibits
  
Previously Filed
With File Number*
  
As
Exhibit
 
 
  
 
 
 
 
 
 
 
 
 
 
(2)
 
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
 
 
 
 
 
 
 
 
 
2(a)
 
001-34543 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)
 
2(a)
 
—
 
Plan of Conversion of Energy Future Competitive Holdings Company
 
 
 
 
 
 
 
 
 
(3(i))
  
Articles of Incorporation
 
 
 
 
 
 
 
 
 
3(a)
 
001-34543 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)
 
3(a)
 
—
 
Certificate of Formation of Energy Future Competitive Holdings Company LLC
 
 
 
 
 
 
 
 
 
(3(ii))
 
By-laws
 
 
 
 
 
 
 
 
 
3(b)
  
001-34543 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)
  
3(b)
 
—
  
Limited Liability Company Agreement Of Energy Future Competitive 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 Competitive Holdings Company LLC, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
 
31(b)
  
 
  
 
 
—
  
Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Company LLC, 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 Competitive Holdings Company LLC, 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 Competitive Holdings Company LLC, 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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
99(a)
  
 
  
 
 
—
  
Condensed Statement of Consolidated Income – Twelve Months Ended June 30, 2015.
 
 
 
 
 
 
 
 
 
99(b)
 
 
 
 
 
—
 
Texas Competitive Electric Holdings Company LLC Consolidated EBITDA reconciliation for the six and twelve months ended June 30, 2015 and 2014
 
 
 
 
 
 
 
 
 
 
  
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

82

*     Incorporated herein by reference



83

SIGNATURE

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

 
 
 
Energy Future Competitive Holdings Company LLC
 
 
 
 
 
 
 
By:
 
/s/ TERRY L. NUTT
 
 
Name:
 
Terry L. Nutt
 
 
Title:
 
Senior Vice President and Controller
 
 
 
 
(Principal Accounting Officer)
 

Date: July 31, 2015



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Energy Future Competitive Holdings Co LLC Reports