Energy Future Holdings Corp /TX/ - FORM 10-Q - August 2, 2016

Attached files

file filename
EX-31.A - CERTIFICATION OF JOHN F. YOUNG - Energy Future Holdings Corp /TX/efh-2016630xexhibit31a.htm
EX-99.B - CONSOLIDATED EBITDA RECONCILIATION TEXAS COMPETITIVE ELECTRIC HOLDINGS COMPANY - Energy Future Holdings Corp /TX/efh-2016630xexhibit99b.htm
EX-99.A - TWELVE MONTHS ENDED JUNE 30, 2016 STATEMENT OF INCOME - Energy Future Holdings Corp /TX/efh-2016630xexhibit99a.htm
EX-95.A - MINE SAFETY DISCLOSURES - Energy Future Holdings Corp /TX/efh-2016630xexhibit95a.htm
EX-32.B - CERTIFICATION OF PAUL M. KEGLEVIC - Energy Future Holdings Corp /TX/efh-2016630xexhibit32b.htm
EX-32.A - CERTIFICATION OF JOHN F. YOUNG - Energy Future Holdings Corp /TX/efh-2016630xexhibit32a.htm
EX-31.B - CERTIFICATION OF PAUL M. KEGLEVIC - Energy Future Holdings Corp /TX/efh-2016630xexhibit31b.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, 2016

— OR —

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


Commission File Number 1-12833


Energy Future Holdings Corp.

(Exact name of registrant as specified in its charter)

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

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 August 2, 2016, there were 1,669,861,379 shares of common stock, without par value, outstanding of Energy Future Holdings Corp. (substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.’s parent holding company, and none of which is publicly traded).
 


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 Holdings Corp.'s (EFH Corp.) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the EFH Corp. website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on EFH Corp.'s website shall not be deemed a part of, or incorporated by reference into, this quarterly report on Form 10-Q. The representations and warranties contained in any agreement that we have filed as an exhibit to this quarterly report on Form 10-Q, or that we have or may publicly file in the future, may contain representations and warranties made by and to the parties thereto 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 EFH Corp. and its subsidiaries occasionally make references to EFH Corp. (or "we," "our," "us" or "the Company"), EFCH, EFIH, TCEH, TXU Energy, Luminant, Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent company's financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.


i

GLOSSARY

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
2015 Form 10-K
 
EFH Corp.'s Annual Report on Form 10-K for the year ended December 31, 2015
 
 
 
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
 
 
 
Competitive Electric segment
 
the EFH Corp. business segment that consists principally of TCEH
 
 
 
Consolidated EBITDA
 
Consolidated EBITDA means TCEH EBITDA adjusted to exclude noncash items, unusual items and other adjustments allowable under the agreement governing the TCEH DIP Facility. See the definition of EBITDA below. Consolidated EBITDA and EBITDA are not recognized terms under US GAAP and, thus, are non-GAAP financial measures. We are providing Consolidated EBITDA in this Form 10-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
 
 
 
DIP Facilities
 
Refers, collectively, to the TCEH DIP Facility and the EFIH DIP Facility. See Note 10 to the Financial Statements.
 
 
 
Debtors
 
EFH Corp. and the majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities
 
 
 
Disclosure Statement
 
Disclosure Statement for the Debtors' Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code filed by the Debtors with the Bankruptcy Court in May 2016
 
 
 
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. and/or its subsidiaries, depending on context, whose major subsidiaries include TCEH and Oncor
 
 
 
EFH Debtors
 
EFH Corp. and its subsidiaries that are Debtors in the Chapter 11 Cases, excluding the TCEH Debtors
 
 
 
EFIH
 
Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings
 
 
 
EFIH Debtors
 
EFIH and EFIH Finance
 
 
 
EFIH DIP Facility
 
EFIH's and EFIH Finance's $5.4 billion debtor-in-possession financing facility. See Note 10 to the Financial Statements.

 
 
 
EFIH Finance
 
EFIH Finance Inc., a direct, wholly owned subsidiary of EFIH, formed for the sole purpose of serving as co-issuer with EFIH of certain debt securities
 
 
 
EFIH First Lien Notes
 
EFIH's and EFIH Finance's 6.875% Senior Secured First Lien Notes and 10.000% Senior Secured First Lien Notes exchanged or settled in June 2014 as discussed in Note 10 to the Financial Statements, collectively
 
 
 
 
 
 
EFIH PIK Notes
 
EFIH's and EFIH Finance's $1.530 billion principal amount of 11.25%/12.25% Senior Toggle Notes

ii

EFIH Second Lien Notes
 
EFIH's and EFIH Finance's $322 million principal amount of 11% Senior Secured Second Lien Notes and $1.389 billion principal amount of 11.75% Senior Secured Second Lien Notes, collectively
 
 
 
EPA
 
US Environmental Protection Agency
 
 
 
ERCOT
 
Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
 
 
 
ERISA
 
Employee Retirement Income Security Act of 1974, as amended
 
 
 
Federal and State Income Tax Allocation Agreements
 
EFH Corp. and certain of its subsidiaries (including EFCH, EFIH and TCEH, but not including Oncor Holdings and Oncor) are parties to a Federal and State Income Tax Allocation Agreement, executed in May 2012 but effective as of January 2010. EFH Corp., Oncor Holdings, Oncor, Texas Transmission, and Oncor Management Investment LLC are parties to a separate Federal and State Income Tax Allocation Agreement dated November 2008. See Note 6 to the Financial Statements and Management's Discussion and Analysis, under Financial Condition.
 
 
 
FERC
 
US Federal Energy Regulatory Commission
 
 
 
Fifth Circuit Court
 
US Court of Appeals for the Fifth Circuit
 
 
 
GAAP
 
generally accepted accounting principles
 
 
 
GHG
 
greenhouse gas
 
 
 
GWh
 
gigawatt-hours
 
 
 
ICE
 
the IntercontinentalExchange, an electronic commodity derivative exchange
 
 
 
IRS
 
US Internal Revenue Service
 
 
 
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
 
 
 
LSTC
 
liabilities subject to compromise
 
 
 
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, all largely in Texas
 
 
 
market heat rate
 
Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.
 
 
 
MATS
 
the Mercury and Air Toxics Standard established by the EPA
 
 
 
Merger
 
the transaction referred to in the Agreement and Plan of Merger 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
 
 
 

iii

Oncor
 
Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., 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 filed by the Debtors with the Bankruptcy Court in May 2016

 
 
 
Plan Support Agreement
 
Third Amendment to the Amended and Restated Plan Support Agreement, entered into in December 2015, amending and restating the Plan Support Agreement
 
 
 
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.
 
 
 
Regulated Delivery segment
 
the EFH Corp. business segment that consists primarily of our investment in Oncor
 
 
 
REP
 
retail electric provider
 
 
 
RCT
 
Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
 
 
 
S&P
 
Standard & Poor's Ratings (a credit rating agency)
 
 
 
SEC
 
US Securities and Exchange Commission
 
 
 
Securities Act
 
Securities Act of 1933, as amended
 
 
 
SG&A
 
selling, general and administrative
 
 
 
Settlement Agreement
 
Amended and Restated Settlement Agreement among the Debtors, the Sponsor Group, settling TCEH first lien creditors, settling TCEH second lien creditors, settling TCEH unsecured creditors and the official committee of unsecured creditors of TCEH (collectively, the Settling Parties), approved by the Bankruptcy Court in December 2015. See Note 2 to the Financial Statements.
 
 
 
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. See Note 10 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 Secured Facilities
 
Refers, collectively, to the TCEH First Lien Term Loan Facilities, TCEH First Lien Revolving Credit Facility and TCEH First Lien Letter of Credit Facility with a total principal amount of $22.616 billion.
 
 
 

iv

TCEH Senior Secured Notes
 
TCEH's and TCEH Finance's $1.750 billion principal amount of 11.5% First Lien Senior Secured Notes
 
 
 
TCEQ
 
Texas Commission on Environmental Quality
 
 
 
Terminated Plan
 
Sixth Amended Joint Plan of Reorganization filed by the Debtors in November 2015, as amended, confirmed by the Bankruptcy Court in December 2015, which became null and void in May 2016
 
 
 
Texas Holdings
 
Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group, that owns substantially all of the common stock of EFH Corp.
 
 
 
Texas Holdings Group
 
Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities
 
 
 
Texas Transmission
 
Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor and is not affiliated with EFH Corp., any of EFH Corp.'s subsidiaries or any member of the Sponsor Group
 
 
 
TXU Energy
 
TXU Energy Retail Company LLC, a direct, wholly owned subsidiary of TCEH that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
 
 
 
US
 
United States of America
 
 
 
VIE
 
variable interest entity


v

PART I. FINANCIAL INFORMATION

Item 1.
FINANCIAL STATEMENTS

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION
CONDENSED STATEMENTS OF CONSOLIDATED LOSS
(Unaudited)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(millions of dollars)
Operating revenues
$
1,233

 
$
1,256

 
$
2,283

 
$
2,527

Fuel, purchased power costs and delivery fees
(654
)
 
(646
)
 
(1,208
)
 
(1,259
)
Net gain (loss) from commodity hedging and trading activities
(118
)
 
20

 
(53
)
 
123

Operating costs
(255
)
 
(217
)
 
(474
)
 
(410
)
Depreciation and amortization
(166
)
 
(222
)
 
(307
)
 
(440
)
Selling, general and administrative expenses
(161
)
 
(177
)
 
(319
)
 
(355
)
Impairment of goodwill (Note 5)
—

 
—

 
—

 
(700
)
Impairment of long-lived assets (Note 7)
—

 
—

 
—

 
(676
)
Other income (Note 18)
16

 
12

 
21

 
19

Other deductions (Note 18)
(27
)
 
(2
)
 
(48
)
 
(61
)
Interest expense and related charges (Note 8)
(402
)
 
(380
)
 
(797
)
 
(988
)
Reorganization items (Note 9)
(52
)
 
(68
)
 
(122
)
 
(207
)
Loss before income taxes and equity in earnings of unconsolidated subsidiaries
(586
)
 
(424
)
 
(1,024
)
 
(2,427
)
Income tax benefit (Note 6)
171

 
137

 
298

 
537

Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 4)
85

 
75

 
147

 
151

Net loss
$
(330
)
 
$
(212
)
 
$
(579
)
 
$
(1,739
)

See Notes to the Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE LOSS
(Unaudited)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(millions of dollars)
Net loss
$
(330
)
 
$
(212
)
 
$
(579
)
 
$
(1,739
)
Other comprehensive income (loss), net of tax effects:
 
 
 
 
 
 
 
Effects related to pension and other retirement benefit obligations (net of tax benefit of $1, $—, $2 and $1)
(2
)
 
—

 
(3
)
 
(2
)
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

Net effects related to Oncor — reported in equity in earnings of unconsolidated subsidiaries (net of tax)
1

 
—

 
1

 
1

Total other comprehensive loss
—

 
—

 
(1
)
 
—

Comprehensive loss
$
(330
)
 
$
(212
)
 
$
(580
)
 
$
(1,739
)

See Notes to the Financial Statements.

1


ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
 
Six Months Ended June 30,
 
2016
 
2015
 
(millions of dollars)
Cash flows — operating activities:
 
 
 
Net loss
$
(579
)
 
$
(1,739
)
Adjustments to reconcile net loss to cash used in operating activities:
 
 
 
Depreciation and amortization
355

 
514

Deferred income tax benefit, net
(278
)
 
(410
)
Impairment of goodwill (Note 5)
—

 
700

Impairment of long-lived assets (Note 7)
—

 
676

Contract claims adjustments (Note 9)
3

 
28

Fees paid on EFIH Second Lien Notes repayment and EFIH DIP Facility (Notes 10 and 11)(reported as financing activities)
14

 
28

Unrealized net (gain) loss from mark-to-market valuations of commodity positions
253

 
(74
)
Equity in earnings of unconsolidated subsidiaries
(147
)
 
(151
)
Distributions of earnings from unconsolidated subsidiaries (Note 4)
86

 
120

Write-off of intangible and other assets (Note 18)
41

 
59

Other, net
32

 
27

Changes in operating assets and liabilities:
 
 
 
Margin deposits, net
(133
)
 
46

Payables due to unconsolidated subsidiary
(2
)
 
(89
)
Other operating assets and liabilities, including liabilities subject to compromise
(157
)
 
(307
)
Cash used in operating activities
(512
)
 
(572
)
Cash flows — financing activities:
 
 
 
Borrowings under TCEH DIP Revolving Credit Facility (Note 10)
1,115

 
—

Repayments/repurchases of debt (Note 10)
(13
)
 
(456
)
Fees paid on EFIH Second Lien Notes repayment and EFIH DIP Facility (Notes 10 and 11)
(14
)
 
(28
)
Cash provided by (used in) financing activities
1,088

 
(484
)
Cash flows — investing activities:
 
 
 
Capital expenditures
(169
)
 
(194
)
Nuclear fuel purchases
(11
)
 
(11
)
Lamar and Forney acquisition — net of cash acquired (Note 3)
(1,343
)
 
—

Changes in restricted cash
(9
)
 
(4
)
Proceeds from sales of nuclear decommissioning trust fund securities (Note 18)
155

 
73

Investments in nuclear decommissioning trust fund securities (Note 18)
(163
)
 
(81
)
Other, net
6

 
8

Cash used in investing activities
(1,534
)
 
(209
)
 
 
 
 
Net change in cash and cash equivalents
(958
)
 
(1,265
)
Cash and cash equivalents — beginning balance
2,286

 
3,428

Cash and cash equivalents — ending balance
$
1,328

 
$
2,163


See Notes to the Financial Statements.

2


ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
June 30,
2016
 
December 31,
2015
 
(millions of dollars)
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
1,328

 
$
2,286

Restricted cash (Note 18)
533

 
524

Trade accounts receivable — net (Note 18)
658

 
533

Inventories (Note 18)
420

 
428

Commodity and other derivative contractual assets (Note 15)
363

 
465

Margin deposits related to commodity contracts
23

 
6

Other current assets
85

 
81

Total current assets
3,410

 
4,323

Restricted cash (Note 18)
507

 
507

Investment in unconsolidated subsidiary (Note 4)
6,125

 
6,064

Other investments (Note 18)
1,032

 
984

Property, plant and equipment — net (Note 18)
10,537

 
9,430

Goodwill (Note 5)
152

 
152

Identifiable intangible assets — net (Note 5)
1,151

 
1,166

Commodity and other derivative contractual assets (Note 15)
15

 
10

Accumulated deferred income taxes
891

 
609

Other noncurrent assets
89

 
85

Total assets
$
23,909

 
$
23,330

LIABILITIES AND EQUITY
Current liabilities:
 
 
 
Borrowings under debtor-in-possession credit facilities (Note 10)
$
7,940

 
$
6,825

Long-term debt due currently (Note 10)
34

 
35

Trade accounts payable
417

 
413

Net payables due to unconsolidated subsidiary (Note 16)
202

 
204

Commodity and other derivative contractual liabilities (Note 15)
315

 
203

Margin deposits related to commodity contracts
36

 
152

Accrued taxes
115

 
134

Accrued interest
124

 
121

Other current liabilities
364

 
425

Total current liabilities
9,547

 
8,512

Long-term debt, less amounts due currently (Note 10)
52

 
60

Liabilities subject to compromise (Note 11)
37,788

 
37,786

Commodity and other derivative contractual liabilities (Note 15)
71

 
1

Other noncurrent liabilities and deferred credits (Note 18)
2,092

 
2,032

Total liabilities
49,550

 
48,391

Commitments and Contingencies (Note 12)


 


Total equity (Note 13)
(25,641
)
 
(25,061
)
Total liabilities and equity
$
23,909

 
$
23,330


See Notes to the Financial Statements.

3

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, 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 EFH Corp. and/or its subsidiaries, as apparent in the context. See Glossary for defined terms.

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

Various ring-fencing measures have been taken to enhance the credit quality of Oncor. Such measures include, among other things: the ownership of a 19.75% equity interest in Oncor by Texas Transmission; maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor's board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or contractual obligations of any member of the Texas Holdings Group. Oncor's operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.

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

We have two reportable segments: the Competitive Electric segment, consisting largely of TCEH, and the Regulated Delivery segment, consisting largely of our investment in Oncor. See Note 17 for further information concerning reportable business segments.

Bankruptcy Proceeding

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). See Note 2 for further discussion regarding the Chapter 11 Cases.


4

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 EFH Corp. 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 852, Reorganizations (ASC 852). 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 9 and 11 for discussion of these accounting and reporting changes.

Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method (see Note 4). 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 2015 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.

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 February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2016-2 (ASU 2016-02), Leases. The ASU amends previous GAAP to require the recognition of lease assets and liabilities for operating leases. The ASU will be effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Retrospective application to comparative periods presented will be required in the year of adoption. We are currently evaluating the impact of this ASU on our financial statements.

In March 2016, the FASB issued Accounting Standards Update 2016-08 (ASU 2016-08), Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). ASU 2016-08 clarifies the implementation guidance for principal versus agent considerations related to ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which provides the core principle and key steps in determining the recognition of revenue. The effective date for these updates has been deferred to fiscal years beginning after December 15, 2017. We are currently assessing the impact of these ASUs 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.

Plan of Reorganization

In May 2016, the Debtors filed the Plan of Reorganization and the Disclosure Statement with the Bankruptcy Court. In July 2016, in connection with the Merger Agreement (as described below), each of the EFH Debtors and NextEra Energy, Inc. (NEE) agreed to certain amendments to the Plan of Reorganization with respect to the EFH Debtors (the Amended Plan). Pursuant to the terms of the EFH Debtors Plan Support Agreement (as described below), it is expected that the Debtors will file the Amended Plan with the Bankruptcy Court and seek confirmation of the Amended Plan.

The Plan of Reorganization provides (and the Amended Plan will provide) that the confirmation and effective date of the Plan of Reorganization with respect to the TCEH Debtors may occur separate from, and independent of, the confirmation and effective date of the Plan of Reorganization with respect to the EFH Debtors.

With respect to the TCEH Debtors (and certain EFH Debtors that will become subsidiaries of Reorganized TCEH upon emergence of the TCEH Debtors from the Chapter 11 Cases (the Contributed EFH Debtors)), the Plan of Reorganization, subject to certain conditions, provides for, among other things, a tax-free spin-off from EFH Corp. (the Reorganized TCEH Spin-Off), including a transaction that will result in a step-up in the tax basis of certain TCEH assets contributed to a subsidiary of TCEH (Reorganized TCEH). With respect to the EFH Debtors, the Plan of Reorganization (as will be amended by the Amended Plan), subject to certain conditions and certain regulatory approvals, will provide for, among other things, the acquisition by NEE of the EFH Debtors (as reorganized) after the Reorganized TCEH Spin-Off pursuant to the Merger Agreement (as described below).

Information contained in the Plan of Reorganization (including when amended by the Amended Plan) and the Disclosure Statement is subject to change, whether as a result of amendments to such documents, requirements by the Bankruptcy Court, actions of third parties or otherwise.

Solely as it pertains to the TCEH Debtors and the Contributed EFH Debtors, the Disclosure Statement has been approved by the Bankruptcy Court, and the confirmation hearing for the Plan of Reorganization is scheduled to commence on August 17, 2016. There can be no assurance that the TCEH Debtors' stakeholders will vote to accept the Plan of Reorganization or that the Bankruptcy Court will confirm the Plan of Reorganization, in each case, as it relates to the TCEH Debtors. With respect to the EFH Debtors, no Disclosure Statement has been approved by the Bankruptcy Court, and no date to confirm the Plan of Reorganization has been scheduled. See Scheduling Matters below.

The EFH Debtors and the TCEH Debtors, respectively, will emerge from bankruptcy if and when, in each case, a plan of reorganization receives the requisite approval from the appropriate holders of claims, the Bankruptcy Court enters an order confirming such plan of reorganization and certain conditions to the effectiveness of such plan of reorganization are satisfied.

Plan Support Agreement and EFH Debtors Plan Support Agreement

In August 2015 (as amended in September 2015 and November 2015), in connection with the Terminated Plan, each of the Debtors entered into a Plan Support Agreement (Plan Support Agreement) with, among other parties, various of their respective creditors, the Sponsor Group and the official committee of TCEH unsecured creditors in order to effect an agreed upon restructuring of the Debtors pursuant to the Terminated Plan or, upon certain events, an Alternative Restructuring (as defined in the Plan Support Agreement) pursuant to another plan of reorganization. The Bankruptcy Court approved the Debtors' entry into the Plan Support Agreement in September 2015.


6

In May 2016, certain first lien creditors of TCEH (the Required TCEH First Lien Creditors) delivered a Plan Support Termination Notice to the Debtors and the other parties to the Plan Support Agreement notifying such parties of the occurrence of a Plan Support Termination Event pursuant to the Plan Support Agreement. The delivery of the Plan Support Termination Notice caused the Terminated Plan to become null and void. The delivery of the Plan Support Termination Notice did not, subject to certain conditions, terminate the obligations under the Plan Support Agreement of certain of the parties thereto to support an Alternative Restructuring pursuant to another plan of reorganization such as the Plan of Reorganization (including as to be amended by the Amended Plan).

The parties' obligations with respect to an Alternative Restructuring, which remain in effect (including with respect to the Plan of Reorganization (including as to be amended by the Amended Plan)), may be terminated upon the occurrence of certain events described in the Plan Support Agreement. In addition, under the Plan Support Agreement, the supporting parties have committed to support the inclusion of releases with respect to the claims described in the Settlement Agreement (described below) in the context of an alternative plan (which would become effective when a plan of reorganization contemplating an Alternative Restructuring, such as the Plan of Reorganization (including as to be amended by the Amended Plan), becomes effective).

In July 2016, the EFH Debtors and NEE entered into a plan support agreement (the EFH Debtors Plan Support Agreement) to effect an agreed upon restructuring of the EFH Debtors pursuant to the Amended Plan. The EFH Debtors Plan Support Agreement has not yet been approved by the Bankruptcy Court.

Settlement Agreement

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

Merger Agreement

In July 2016, EFH Corp. and EFIH entered into an Agreement and Plan of Merger (Merger Agreement) with NEE and a wholly-owned subsidiary of NEE (Merger Sub). Pursuant to the Merger Agreement, at the effective time of the Amended Plan, NEE will acquire the EFH Debtors (as reorganized) as a result of a merger (EFH Debtor Merger) between EFH Corp. and Merger Sub in which Merger Sub will survive as a wholly owned subsidiary of NEE. The consideration payable by NEE pursuant to the Merger Agreement consists primarily of cash paid to certain creditors. A portion of the consideration to be distributed to certain holders of allowed claims and interests in EFH Corp. and EFIH as set forth in the Amended Plan will consist of common stock of NEE.

The Merger Agreement contains representations and warranties and interim operating covenants that are customary for an agreement of this nature. The Merger Agreement also includes various conditions precedent to consummation of the transactions, including (a) a condition that certain approvals and rulings be obtained, including from the PUCT and the IRS and (b) a condition that the Reorganized TCEH Spin-Off shall have occurred. NEE will not be required to consummate the EFH Debtor Merger if, among other items, the PUCT approval is obtained but with conditions, commitments or requirements that impose a Burdensome Condition (as defined in the Merger Agreement). NEE's and Merger Sub's obligations under the Merger Agreement are not subject to any financing condition.

Prior to approval of the Merger Agreement by the Bankruptcy Court, EFH Corp. and EFIH may continue to solicit acquisition proposals with respect to the EFH Debtors. In addition, following approval of the Merger Agreement by the Bankruptcy Court and until confirmation of the Amended Plan by the Bankruptcy Court, EFH Corp. and EFIH may continue or have discussions or negotiations with respect to acquisition proposals for the EFH Debtors (a) with persons that were in active negotiation at the time of approval of the Merger Agreement by the Bankruptcy Court and (b) with persons that submit an unsolicited acquisition proposal that is, or is reasonably likely to lead to, a Superior Proposal (as defined in the Merger Agreement).

The Merger Agreement may be terminated upon certain events, including, among other things:

•
by either party, if the EFH Debtor Merger is not consummated by March 26, 2017, subject to a 90-day extension under certain conditions, or


7

•
by EFH Corp. or EFIH, until the entry of the confirmation order of the Amended Plan with respect to the EFH Debtors, if their respective board of directors or managers determines, after consultation with its independent financial advisors and outside legal counsel, and based on advice of such counsel, that the failure to terminate the Merger Agreement is inconsistent with its fiduciary duties; provided that a material breach of EFH Corp.'s or EFIH’s obligations under certain provisions of the Merger Agreement has not provided the basis for such determination.

Following approval of the Merger Agreement by the Bankruptcy Court, if the Merger Agreement is terminated for certain reasons set forth therein and an alternative transaction is consummated by EFH Corp. or EFIH in which neither NEE nor any of its affiliates obtains direct or indirect ownership of approximately 80% of Oncor, then EFH Corp. and EFIH will pay a termination fee of $275 million to NEE.

EFH Corp.'s and EFIH’s respective obligations under the Merger Agreement are subject in all respects to the prior approval of the Bankruptcy Court. Under the terms of the EFH Debtors Plan Support Agreement, the EFH Debtors will seek Bankruptcy Court approval of the Merger Agreement.

Regulatory Approvals

In May 2016, the TCEH Debtors received approval from the NRC with respect to the change of control application contemplated by the Plan of Reorganization as it relates to the emergence of the TCEH Debtors (and the EFH Contributed Debtors). In July 2016, the TCEH Debtors submitted an application to the RCT to request to substitute and replace the TCEH Debtors' existing mine reclamation performance collateral bond with a similar collateral bond in connection with the refinancing of the TCEH DIP Facility and the TCEH Debtors' proposed exit financing facility. We expect the RCT to complete its review and take action on the application in the third quarter of 2016.

The consummation of the transactions contemplated by the Merger Agreement with respect to the EFH Debtors requires the prior approval of, among others, the PUCT and the FERC.

Scheduling Matters

In May 2016, the Bankruptcy Court entered an order establishing a timeline for approval of a disclosure statement and a hearing to consider confirmation of the Plan of Reorganization as it applies to the TCEH Debtors and the Contributed EFH Debtors, and, separately, establishing a timeline for approval of a disclosure statement and a hearing to consider confirmation of the Plan of Reorganization as it applies to the remaining EFH Debtors. Pursuant to such scheduling order, solely as it pertains to the TCEH Debtors and the Contributed EFH Debtors, the Disclosure Statement has been approved by the Bankruptcy Court, and the confirmation hearing for the Plan of Reorganization is scheduled to commence on August 17, 2016. In June 2016, the Bankruptcy Court entered a supplement to its May 2016 order adjourning the schedule solely with respect to the EFH Debtors' schedule. We expect that the Bankruptcy Court will set a revised schedule relating to the EFH Debtors beginning in the third quarter of 2016.

The timelines set forth in the scheduling order are subject to further revision by the Bankruptcy Court and may change based on subsequent orders entered by the Bankruptcy Court (on its own, upon the motion of a party, or upon the Debtors' request).

Tax Matters

In June 2014, EFH Corp. filed a request with the IRS for a private letter ruling, which request has been supplemented from time to time in response to requests from the IRS for information or as required by changes in the contemplated transactions (as supplemented, the Private Letter Ruling). In July 2016, we received the Private Letter Ruling. It provides, among other things, for certain rulings regarding the qualification of (a) the transfer of certain assets and ordinary course operating liabilities to Reorganized TCEH and (b) the distribution of the equity of Reorganized TCEH, the cash proceeds from Reorganized TCEH debt, if any, the cash proceeds from the sale of preferred stock in a newly-formed entity, and the right to receive payments under a tax receivables agreement (if any), to holders of TCEH first lien claims, as a reorganization qualifying for tax-free treatment to the extent of the Reorganized TCEH stock received. In addition to the Private Letter Ruling, we are pursuing and expect to receive the required tax opinions that will supplement the Private Letter Ruling, as required by the Plan of Reorganization with respect to the TCEH Debtors.


8

The Merger Agreement provides that a closing condition to the EFH Debtor Merger is the receipt of a supplemental private letter ruling (the Supplemental Ruling) from the IRS regarding the impact of the EFH Debtor Merger on certain rulings received in the Private Letter Ruling. We expect to submit a request to the IRS for the Supplemental Ruling during 2016 as the transaction and bankruptcy process progresses. The Supplemental Ruling is only required for the consummation of the transactions contemplated by the EFH Debtor Merger and not for the emergence of the TCEH Debtors (and the Contributed EFH Debtors) as contemplated by the Plan of Reorganization.

Implications of the Chapter 11 Cases

Our ability to continue as a going concern is contingent upon, among other factors, our ability to comply with the financial and other covenants contained in the DIP Facilities described in Note 10, our ability to obtain new debtor in possession financing in the event the DIP Facilities were to expire during the pendency of the Chapter 11 Cases, our ability to complete a Chapter 11 plan of reorganization in a timely manner, including obtaining creditor and Bankruptcy Court approval of such plan, obtaining applicable regulatory approvals required for such plan and our ability to obtain 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.

Pre-Petition Claims

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

Since the Petition Date and prior to the applicable bar dates (which have expired), we have received approximately 41,300 filed pre-petition claims, including approximately 30,900 in filed asbestos claims. We have substantially completed the process of reconciling all non-asbestos claims that were filed and have recorded such claims at the expected allowed amount. As of August 2, 2016, approximately 5,700 of those claims have been settled, withdrawn or expunged. We continue to work with creditors regarding certain non-asbestos claims to determine the ultimate amount of the allowed claims. Differences between those final allowed claims and the liabilities recorded in the condensed consolidated balance sheets will be recognized as reorganization items in our condensed statements of consolidated loss as they are resolved. The resolution of such claims could result in material adjustments to our financial statements.

Certain claims filed or reflected in our schedules of assets and liabilities will be resolved on the applicable effective date of the applicable plan of reorganization, including certain claims filed by holders of funded debt and contract counterparties. Claims that remain unresolved or unreconciled through the filing of this report have been estimated based upon management's best estimate of the likely claim amounts that the Bankruptcy Court will ultimately allow.

Separation of the EFH Debtors and the TCEH Debtors

Upon the effective date of the Plan of Reorganization as it relates to the TCEH Debtors (and the EFH Contributed Debtors), the EFH Debtors and the TCEH Debtors (together with the EFH Contributed Debtors) will be separated and no longer be affiliated companies. In addition to the plan of reorganization, the separation will be effectuated by a separation agreement, a transition services agreement and a tax matters agreement. A proposed form of each of these agreements was filed with the Bankruptcy Court by the Debtors in July 2016. These agreements must be approved by the Bankruptcy Court and, as a result, are subject to change.

Unaudited Condensed Combined Debtor Financial Statements

The condensed combined financial statements presented below represent the financial statements of the Debtors. EFH Corp.'s non-Debtor subsidiaries, excluding the Oncor Ring-Fenced Entities, which are substantively comprised of the recently acquired Lamar and Forney generation assets, are accounted for as non-consolidated subsidiaries in these financial statements, and their net income is included in equity in earnings of non-debtor entities (net of tax) in these condensed statements of combined loss and investment in non-debtor entities in these condensed combined balance sheets. Intercompany items and transactions among the Debtors have been eliminated in consolidation in these financial statements.


9

Condensed statements of combined loss of the Debtors for the three and six months ended June 30, 2016 and 2015 are presented below:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Operating revenues
$
1,234

 
$
1,256

 
$
2,283

 
$
2,527

Fuel, purchased power costs and delivery fees
(677
)
 
(646
)
 
(1,230
)
 
(1,259
)
Net gain (loss) from commodity hedging and trading activities
(117
)
 
20

 
(53
)
 
123

Operating costs
(239
)
 
(223
)
 
(462
)
 
(421
)
Depreciation and amortization
(137
)
 
(219
)
 
(274
)
 
(433
)
Selling, general and administrative expenses
(156
)
 
(175
)
 
(312
)
 
(352
)
Impairment of goodwill
—

 
—

 
—

 
(700
)
Impairment of long-lived assets
—

 
—

 
—

 
(676
)
Other income (deductions) and interest income
(13
)
 
2

 
(29
)
 
(52
)
Interest expense and related charges
(401
)
 
(379
)
 
(798
)
 
(987
)
Reorganization items
(52
)
 
(68
)
 
(122
)
 
(207
)
Loss before income taxes and equity in earnings of non-debtor entities
(558
)
 
(432
)
 
(997
)
 
(2,437
)
Income tax benefit
161

 
140

 
289

 
545

Equity in earnings of non-debtor entities (net of tax)
67

 
80

 
129

 
153

Net loss
$
(330
)
 
$
(212
)
 
$
(579
)
 
$
(1,739
)

Condensed statements of combined comprehensive loss of the Debtors for the three and six months ended June 30, 2016 and 2015 are presented below:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Net loss
$
(330
)
 
$
(212
)
 
$
(579
)
 
$
(1,739
)
Other comprehensive loss (net of tax)
—

 
—

 
(1
)
 
—

Comprehensive loss
$
(330
)
 
$
(212
)
 
$
(580
)
 
$
(1,739
)


10

Condensed statements of combined cash flows of the Debtors for the six months ended June 30, 2016 and 2015 are presented below:
 
Six Months Ended June 30,
 
2016
 
2015
Cash used in operating activities
$
(545
)
 
$
(574
)
Cash flows — financing activities:
 
 
 
Borrowings under TCEH DIP Revolving Credit Facility
1,115

 
—

Repayments/repurchases of debt
(10
)
 
(451
)
Fees paid on EFIH Second Lien Notes repayment and EFIH DIP Facility
(14
)
 
(28
)
Cash provided by (used in) financing activities
1,091

 
(479
)
Cash flows — investing activities:
 
 
 
Advances to non-debtor affiliates
(12
)
 
(6
)
Investment in non-debtor affiliates
(1,338
)
 
—

Capital expenditures
(136
)
 
(195
)
Nuclear fuel purchases
(11
)
 
(11
)
Proceeds from sales of nuclear decommissioning trust fund securities
155

 
73

Investments in nuclear decommissioning trust fund securities
(163
)
 
(81
)
Other, net
(4
)
 
(5
)
Cash used in investing activities
(1,509
)
 
(225
)
Net change in cash and cash equivalents
(963
)
 
(1,278
)
Cash and cash equivalents — beginning balance
2,258

 
3,417

Cash and cash equivalents — ending balance
$
1,295

 
$
2,139


Condensed combined balance sheets of the Debtors at June 30, 2016 and December 31, 2015 are presented below:
 
June 30,
2016
 
December 31,
2015
ASSETS
Total current assets
$
3,491

 
$
4,443

Restricted cash
507

 
507

Advances to non-debtor entities
115

 
115

Investment in non-debtor entities
7,529

 
6,147

Other investments
1,032

 
984

Property, plant and equipment — net
9,080

 
9,287

Goodwill
152

 
152

Identifiable intangible assets — net
1,146

 
1,170

Commodity and other derivative contractual assets
12

 
10

Accumulated deferred income taxes
702

 
424

Other noncurrent assets
48

 
39

Total assets
$
23,814

 
$
23,278

LIABILITIES AND EQUITY
Total current liabilities
$
9,537

 
$
8,496

Long-term debt, less amounts due currently
19

 
23

Liabilities subject to compromise
37,788

 
37,786

Commodity and other derivative contractual liabilities
20

 
1

Other noncurrent liabilities and deferred credits
2,091

 
2,033

Total liabilities
49,455

 
48,339

Total equity
(25,641
)
 
(25,061
)
Total liabilities and equity
$
23,814

 
$
23,278



11


3.
LAMAR AND FORNEY ACQUISITION

In April 2016, Luminant purchased all of the membership interests in La Frontera Holdings, LLC (La Frontera), the indirect owner of two combined-cycle gas turbine (CCGT) natural gas fueled generation facilities representing nearly 3,000 MW of capacity located in ERCOT, from a subsidiary of NextEra Energy, Inc. (the Lamar and Forney Acquisition). The facility in Forney, Texas has a capacity of 1,912 MW and the facility in Paris, Texas has a capacity of 1,076 MW. The acquisition continues to diversify our fuel mix and increases the dispatch flexibility in our fleet. The aggregate purchase price was approximately $1.313 billion, which included the repayment of approximately $950 million of existing project financing indebtedness of La Frontera at closing, plus approximately $240 million for cash and net working capital subject to final settlement. The purchase price was funded by cash-on-hand and additional borrowings under the TCEH DIP Facility totaling $1.1 billion. After completing the acquisition, we repaid approximately $230 million of borrowings under the TCEH DIP Revolving Credit Facility primarily utilizing cash acquired in the transaction. La Frontera and its subsidiaries are subsidiary guarantors under the TCEH DIP Facility.

Purchase Accounting

The Lamar and Forney Acquisition has been accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The related purchase agreement contains a traditional working capital adjustment that is still being finalized, and as a result our purchase price allocation is not yet complete and is considered to be provisional at this time. The provisional amounts recognized are subject to revision until our valuations are completed, not to exceed one year, and any material adjustments identified that existed as of the acquisition date will be recognized in the current period. We expect the working capital adjustment to be finalized in the third quarter of 2016.

To fair value the acquired property, plant and equipment, we used a discounted cash flow analysis, classified as Level 3 within the fair value hierarchy levels (see Note 14). This discounted cash flow model was created for each generation facility based on its remaining useful life. The discounted cash flow model included gross margin forecasts for each power generation facility determined using forward commodity market prices obtained from long-term forecasts. We also used management's forecasts of generation output, operations and maintenance expense, SG&A and capital expenditures. The resulting cash flows, estimated based upon the age of the assets, efficiency, location and useful life, were then discounted using plant specific discount rates of approximately 9%.

The following table summarizes the consideration paid and the preliminary allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Lamar and Forney Acquisition as of the acquisition date. The purchase price allocation is subject to change based on final working capital adjustments.
Cash paid to seller at close
 
$
603

Preliminary net working capital adjustments
 
(8
)
Consideration paid to seller
 
595

Cash paid to repay project financing at close
 
950

Total cash paid related to acquisition
 
$
1,545

Cash and cash equivalents
 
$
210

Property, plant and equipment — net
 
1,316

Commodity and other derivative contractual assets
 
47

Other assets
 
44

Total assets acquired
 
1,617

Commodity and other derivative contractual liabilities
 
53

Trade accounts payable and other liabilities
 
19

Total liabilities assumed
 
72

Identifiable net assets acquired
 
$
1,545


The Lamar and Forney Acquisition did not result in the recording of goodwill since the purchase price did not exceed the fair value of the net assets acquired.


12

Unaudited Pro Forma Financial Information

The following unaudited pro forma financial information for the six months ended June 30, 2016 and 2015 assumes that the Lamar and Forney Acquisition occurred on January 1, 2015. The unaudited pro forma financial information is provided for information purposes only and is not necessarily indicative of the results of operations that would have occurred had the Lamar and Forney Acquisition been completed on January 1, 2015, nor are they indicative of future results of operations.
 
Six Months Ended June 30,
 
2016
 
2015
Revenues
$
2,425

 
$
3,044

Net income (loss)
$
(594
)
 
$
(1,651
)

The unaudited pro forma financial information includes adjustments for incremental depreciation as a result of the fair value determination of the net assets acquired and interest expense on borrowings under the TCEH DIP Facility in lieu of interest expense incurred prior to the acquisition.


13


4.
VARIABLE INTEREST ENTITIES

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

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

Non-Consolidation of Oncor and Oncor Holdings

Our investment in unconsolidated subsidiary as presented in the condensed consolidated balance sheets totaled $6.125 billion and $6.064 billion at June 30, 2016 and December 31, 2015, respectively, and consists almost entirely of our interest in Oncor Holdings, which we account for under the equity method as described above. Oncor provides services, principally electricity distribution, to TCEH's retail operations, and the related revenues represented 23% and 24% of Oncor Holdings' consolidated operating revenues for the six months ended June 30, 2016 and 2015, respectively.

See Note 16 for discussion of Oncor Holdings' and Oncor's transactions with EFH Corp. and its other subsidiaries.

Distributions from Oncor Holdings and Related Considerations — Oncor Holdings' distributions of earnings to us totaled $86 million and $120 million for the six months ended June 30, 2016 and 2015, respectively. Distributions may not be paid except to the extent Oncor maintains a required regulatory capital structure as discussed below. At June 30, 2016, $98 million was eligible to be distributed to Oncor's members after taking into account the regulatory capital structure limit, of which approximately 80% relates to our ownership interest in Oncor. The boards of directors of each of Oncor and Oncor Holdings can withhold distributions to the extent the applicable board determines in good faith that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings.

Oncor's distributions are limited by its regulatory capital structure, which is required to be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. At June 30, 2016, Oncor's regulatory capitalization ratio was 59.4% debt to 40.6% equity. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of accounting for the Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization).

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


14

Oncor Holdings Financial Statements — Condensed statements of consolidated income of Oncor Holdings and its subsidiaries for the three and six months ended June 30, 2016 and 2015 are presented below:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Operating revenues
$
948

 
$
938

 
$
1,891

 
$
1,884

Operation and maintenance expenses
(389
)
 
(367
)
 
(791
)
 
(746
)
Depreciation and amortization
(193
)
 
(220
)
 
(403
)
 
(437
)
Taxes other than income taxes
(107
)
 
(108
)
 
(220
)
 
(220
)
Other income and (deductions) — net
(3
)
 
(6
)
 
(8
)
 
(7
)
Interest expense and related charges
(84
)
 
(84
)
 
(168
)
 
(165
)
Income before income taxes
172

 
153

 
301

 
309

Income tax expense
(65
)
 
(58
)
 
(116
)
 
(119
)
Net income
107

 
95

 
185

 
190

Net income attributable to noncontrolling interests
(22
)
 
(20
)
 
(38
)
 
(39
)
Net income attributable to Oncor Holdings
$
85

 
$
75

 
$
147

 
$
151


Assets and liabilities of Oncor Holdings at June 30, 2016 and December 31, 2015 are presented below:
 
June 30,
2016
 
December 31,
2015
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
2

 
$
26

Restricted cash
—

 
38

Trade accounts receivable — net
407

 
388

Trade accounts and other receivables from affiliates
124

 
118

Income taxes receivable from EFH Corp.
90

 
107

Inventories
95

 
82

Prepayments and other current assets
98

 
88

Total current assets
816

 
847

Other investments
99

 
97

Property, plant and equipment — net
13,439

 
13,024

Goodwill
4,064

 
4,064

Regulatory assets — net
1,184

 
1,194

Other noncurrent assets
45

 
31

Total assets
$
19,647

 
$
19,257

LIABILITIES
 
 
 
Current liabilities:
 
 
 
Short-term borrowings
$
1,133

 
$
840

Long-term debt due currently
—

 
41

Trade accounts payable — nonaffiliates
213

 
150

Income taxes payable to EFH Corp.
11

 
20

Accrued taxes other than income
106

 
181

Accrued interest
82

 
82

Other current liabilities
117

 
144

Total current liabilities
1,662

 
1,458

Accumulated deferred income taxes
2,039

 
1,985

Long-term debt, less amounts due currently
5,650

 
5,646

Other noncurrent liabilities and deferred credits
2,326

 
2,306

Total liabilities
$
11,677

 
$
11,395



15


5.
GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides information regarding our goodwill balance, all of which relates to the Competitive Electric segment and arose in connection with accounting for the Merger. None of the goodwill is being deducted for tax purposes.
Goodwill before impairment charges
$
18,342

Accumulated noncash impairment charges
(18,190
)
Balance at June 30, 2016 and December 31, 2015
152


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.

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. Our testing of goodwill for impairment as of March 31, 2015 resulted in an impairment charge totaling $700 million, which we reported in the Competitive Electric segment results.

Identifiable Intangible Assets

Identifiable intangible assets, including amounts that arose in connection with accounting for the Merger, are comprised of the following:
 
 
June 30, 2016
 
December 31, 2015
Identifiable Intangible Asset
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
Retail customer relationship
 
$
463

 
$
448

 
$
15

 
$
463

 
$
442

 
$
21

Capitalized in-service software
 
378

 
237

 
141

 
362

 
214

 
148

Other identifiable intangible assets (a)
 
53

 
18

 
35

 
72

 
35

 
37

Total identifiable intangible assets subject to amortization
 
$
894

 
$
703

 
191

 
$
897

 
$
691

 
206

Retail trade name (not subject to amortization)
 
 
 
 
 
955

 
 
 
 
 
955

Mineral interests (not currently subject to amortization)
 
 
 
 
 
5

 
 
 
 
 
5

Total identifiable intangible assets
 
 
 
 
 
$
1,151

 
 
 
 
 
$
1,166

____________
(a)
Includes favorable purchase and sales contracts, environmental allowances and credits and mining development costs. See discussion below regarding impairment charges recorded in the six months ended June 30, 2015 related to other identifiable intangible assets.

At June 30, 2016 and December 31, 2015, 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.


16

Amortization expense related to finite-lived identifiable intangible assets (including the condensed statements of consolidated loss line item) consisted of:
Identifiable Intangible Asset
 
Condensed Statements of Consolidated Loss Line
 
Segment
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
 
2016
 
2015
 
2016
 
2015
Retail customer relationship
 
Depreciation and amortization
 
Competitive Electric
 
$
3

 
$
4

 
$
6

 
$
9

Capitalized in-service software
 
Depreciation and amortization
 
Competitive Electric and Corporate and Other
 
12

 
11

 
25

 
22

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

 
7

 
3

 
12

Total amortization expense (a)
 
 
 
$
15

 
$
22

 
$
34

 
$
43

____________
(a)
Amounts recorded in depreciation and amortization totaled $17 million and $18 million for the three months ended June 30, 2016 and 2015, respectively, and $34 million and $33 million for the six months ended June 30, 2016 and 2015, respectively.

Intangible Impairments

The impairments of our generation facilities in March 2015 (see Note 7) resulted in the impairment of the SO2 allowances under the Clean Air Act's acid rain cap-and-trade program that are associated with those facilities to the extent they are not projected to be used at other sites. The fair market values of the SO2 allowances were estimated to be de minimis based on Level 3 fair value estimates (see Note 14). Accordingly, in the three months ended March 31, 2015, we recorded noncash impairment charges of $51 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions (see Note 18) related to our existing environmental allowances and credits intangible asset.

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 (REC) prices in ERCOT. As a result of the analysis, we recorded a noncash impairment charge of $8 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions (see Note 18).

Estimated Amortization of Identifiable Intangible Assets

The estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as follows:
Year
 
Estimated Amortization Expense
2016
 
$
74

2017
 
$
53

2018
 
$
33

2019
 
$
16

2020
 
$
9



17


6.
INCOME TAXES

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

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

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

The calculation of our effective tax rate is as follows:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Loss before income taxes and equity in earnings of unconsolidated subsidiaries
$
(586
)
 
$
(424
)
 
$
(1,024
)
 
$
(2,427
)
Income tax benefit
$
171

 
$
137

 
$
298

 
$
537

Effective tax rate
29.2
%
 
32.3
%
 
29.1
%
 
22.1
%

For the three months ended June 30, 2016, the effective tax rate of 29.2% 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 three months ended June 30, 2015, the effective tax rate of 32.3% 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, partially offset by the tax benefit recognized due to the Texas margin tax rate reduction in 2015.

For the six months ended June 30, 2016, the effective tax rate of 29.1% 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, partially offset by the difference in the forecasted effective tax rate and the statutory rate applied to unrealized losses from mark-to-market hedging activities. For the six months ended June 30, 2015, the effective tax rate of 22.1% 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 5) 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 5 and 7) and the Texas margin tax rate reduction in 2015.

Liability for Uncertain Tax Positions

In June 2016, we received a final agreed Revenue Agent Report (RAR) from the IRS and associated documentation for the 2010 through 2013 tax years. The RAR was signed in July 2016. As a result of the final RAR, we reduced the liability for uncertain tax positions by $1 million, resulting in a reclassification to the accumulated deferred income tax liability. Total cash payment to be assessed by the IRS for tax years 2010 through 2013, but not expected to be paid during the pendency of the Chapter 11 Cases, is approximately $15 million, plus any interest that may be assessed.


18

In March 2016, we signed a final agreed RAR with the IRS for the 2014 tax year. No material financial statement impacts resulted from the signing of the 2014 RAR.

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


7.
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 the continued decline in forecasted wholesale electricity prices in ERCOT. Our evaluation concluded that an impairment existed, and the carrying value at our Big Brown generation 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 14). 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.

Additional material impairments may occur in the future for our other generation facilities if forward wholesale electricity prices continue to decline or forecasted costs of producing electricity at our generation facilities increase, including increased costs of compliance with proposed environmental regulations.


8.
INTEREST EXPENSE AND RELATED CHARGES

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Interest paid/accrued on debtor-in-possession financing
$
80

 
$
74

 
$
154

 
$
146

Adequate protection amounts paid/accrued
324

 
306

 
646

 
609

Interest paid/accrued on pre-petition debt (a)
1

 
3

 
3

 
239

Capitalized interest
(3
)
 
(3
)
 
(6
)
 
(6
)
Total interest expense and related charges
$
402

 
$
380

 
$
797

 
$
988

____________
(a)
For the six months ended June 30, 2015, amount includes $235 million in post-petition interest related to the EFIH Second Lien Notes (see Note 11). For the three and six months ended June 30, 2016 and 2015, includes interest paid/accrued on long-term debt not subject to compromise.

Interest expense for the three and six months ended June 30, 2016 and 2015 reflects interest paid and accrued on debtor-in-possession financing (see Note 10), adequate protection amounts paid and accrued, as approved by the Bankruptcy Court in June 2014 for the benefit of secured creditors of (a) $22.616 billion principal amount of outstanding borrowings from the TCEH Senior Secured Facilities, (b) $1.750 billion principal amount of outstanding TCEH Senior Secured Notes and (c) the $1.243 billion net liability related to the TCEH first lien interest rate swaps and natural gas hedging positions terminated shortly after the Bankruptcy Filing (see Note 15), in exchange for their consent to the senior secured, super-priority liens contained in the TCEH DIP Facility and any diminution in value of their interests in the pre-petition collateral from the Petition Date, and interest paid on the EFIH Second Lien Notes as approved by the Bankruptcy Court in March 2015 (see Note 11). The interest rate applicable to the adequate protection amounts paid/accrued for the six months ended June 30, 2016 was 4.93% (one-month LIBOR plus 4.50%). 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 with respect to the TCEH Debtors by the Bankruptcy Court. In addition, upon completion of the Plan of Reorganization with respect to the TCEH Debtors, amounts of adequate protection payments may be re-characterized as payments of principal.


19

The Bankruptcy Code generally restricts payment of interest on pre-petition debt, subject to certain exceptions. The Bankruptcy Court approved post-petition interest payments on the EFIH Second Lien Notes in March 2015 as discussed in Note 11. Additional interest payments may also be made upon approval by the Bankruptcy Court (see Note 12). Other than amounts ordered or approved by the Bankruptcy Court, effective on the Petition Date, we discontinued recording interest expense on outstanding pre-petition debt classified as 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 loss does not include contractual interest on pre-petition debt classified as LSTC totaling $317 million and $328 million for the three months ended June 30, 2016 and 2015, respectively, and $652 million and $616 million for the six months ended June 30, 2016 and 2015, respectively, which has been stayed by the Bankruptcy Court effective on the Petition Date. Adequate protection paid/accrued presented below excludes interest paid/accrued on the TCEH first-lien interest rate and commodity hedge claims (see Note 15) totaling $16 million and $15 million for the three months ended June 30, 2016 and 2015, respectively, and $31 million and $29 million for the six months ended June 30, 2016 and 2015, respectively, as such amounts are not included in contractual interest amounts below.
 
 
Three Months Ended June 30, 2016
 
Three Months Ended June 30, 2015
Entity:
 
Contractual Interest on
Debt Classified as LSTC
 
Adequate Protection
Paid/Accrued
 
Approved Interest Paid/Accrued
 
Contractual Interest on
Debt Classified as LSTC Not
Paid/Accrued
 
Contractual Interest on
Debt Classified as LSTC
 
Adequate Protection
Paid/Accrued
 
Approved Interest Paid/Accrued
 
Contractual Interest on
Debt Classified as LSTC Not
Paid/Accrued
EFH Corp.
 
$
11

 
$
—

 
$
—

 
$
11

 
$
31

 
$
—

 
$
—

 
$
31

EFIH
 
101

 
—

 
—

 
101

 
101

 
—

 
—

 
101

EFCH
 
—

 
—

 
—

 
—

 
2

 
—

 
—

 
2

TCEH
 
513

 
308

 
—

 
205

 
516

 
291

 
—

 
225

Eliminations (b)
 
—

 
—

 
—

 
—

 
(31
)
 
—

 
—

 
(31
)
Total
 
$
625

 
$
308

 
$
—

 
$
317

 
$
619

 
$
291

 
$
—

 
$
328


 
 
Six Months Ended June 30, 2016
 
Six Months Ended June 30, 2015
Entity:
 
Contractual Interest on
Debt Classified as LSTC
 
Adequate Protection
Paid/Accrued
 
Approved Interest Paid/Accrued
 
Contractual Interest on
Debt Classified as LSTC Not
Paid/Accrued
 
Contractual Interest on
Debt Classified as LSTC
 
Adequate Protection
Paid/Accrued
 
Approved Interest Paid/Accrued (a)
 
Contractual Interest on
Debt Classified as LSTC Not
Paid/Accrued
EFH Corp.
 
$
22

 
$
—

 
$
—

 
$
22

 
$
63

 
$
—

 
$
—

 
$
63

EFIH
 
202

 
—

 
—

 
202

 
213

 
—

 
50

 
163

EFCH
 
—

 
—

 
—

 
—

 
3

 
—

 
—

 
3

TCEH
 
1,043

 
615

 
—

 
428

 
1,029

 
580

 
—

 
449

Eliminations (b)
 
—

 
—

 
—

 
—

 
(62
)
 
—

 
—

 
(62
)
Total
 
$
1,267

 
$
615

 
$
—

 
$
652

 
$
1,246

 
$
580

 
$
50

 
$
616

___________
(a)
For the six months ended June 30, 2015 represents portion of interest related to the EFIH Second Lien Notes that was repaid based on the approval of the Bankruptcy Court; however, excludes $185 million of post-petition interest paid in 2015 that contractually related to 2014 and default interest (see Note 11).
(b)
Represents contractual interest on affiliate debt held by EFH Corp. and EFIH that is classified as LSTC.



20

9.
REORGANIZATION ITEMS

Expenses and income directly associated with the Chapter 11 Cases are reported separately in the condensed statements of consolidated loss as reorganization items as required by ASC 852, Reorganizations. Reorganization items also include adjustments to reflect the carrying value of 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, 2016 and 2015 as reported in the condensed statements of consolidated loss:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Expenses related to legal advisory and representation services
$
29

 
$
52

 
$
60

 
$
102

Expenses related to other professional consulting and advisory services
21

 
17

 
44

 
46

Contract claims adjustments
2

 
(2
)
 
3

 
28

Fees associated with extension of EFIH DIP Facility
—

 
—

 
14

 
—

Fees associated with repayment of EFIH Second Lien Notes (Note 11)
—

 
—

 
—

 
28

Other
—

 
1

 
1

 
3

Total reorganization items
$
52

 
$
68

 
$
122

 
$
207



10.
DEBTOR-IN-POSSESSION BORROWING FACILITIES AND LONG-TERM DEBT NOT SUBJECT TO COMPROMISE

TCEH DIP Facility — The Bankruptcy Court approved the TCEH DIP Facility in June 2014. The TCEH DIP Facility currently provides for up to $3.375 billion in senior secured, super-priority financing consisting of a revolving credit facility of up to $1.950 billion (TCEH DIP Revolving Credit Facility) and a term loan facility of up to $1.425 billion (TCEH DIP Term Loan Facility). 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, 2016 are presented below. In the June 30, 2016 condensed consolidated balance sheet, the borrowings under the TCEH DIP Facility are reported as current liabilities. The maturity date of the TCEH DIP Facility is the earlier of (a) November 2016 or (b) the effective date of any plan of reorganization of TCEH. In June 2016, the TCEH Debtors extended their use of cash collateral to September 30, 2016, provided that the TCEH Debtors do not otherwise cause an event of default under the cash collateral order. The TCEH DIP Facility must be repaid in full prior to the TCEH Debtors' emergence from the Chapter 11 Cases.
 
 
June 30, 2016
TCEH DIP Facility
 
Facility
Limit
 
Available Cash
Borrowing Capacity
 
Available Letter of Credit Capacity
TCEH DIP Revolving Credit Facility (a)
 
$
1,950

 
$
835

 
$
—

TCEH DIP Term Loan Facility (b)
 
1,425

 
—

 
272

Total TCEH DIP Facility
 
$
3,375

 
$
835

 
$
272

___________
(a)
Facility used for general corporate purposes. 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.


21

At June 30, 2016, $1.115 billion of the TCEH DIP Revolving Credit Facility has been borrowed. As discussed in Note 3, the Lamar and Forney Acquisition in April 2016 was funded by cash-on-hand and $1.1 billion in additional cash borrowings under the TCEH DIP Revolving Credit Facility. After completing the acquisition, we repaid approximately $230 million of borrowings under the TCEH DIP Revolving Credit Facility primarily utilizing cash acquired in the transaction. At December 31, 2015, no amounts were borrowed under the TCEH DIP Revolving Credit Facility.

At both June 30, 2016 and December 31, 2015, 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, 2016, $272 million is reported as cash and cash equivalents and $528 million is reported as restricted cash, which represents the amount of outstanding letters of credit.

Amounts borrowed under the TCEH DIP Revolving Credit Facility bear interest based on applicable LIBOR rates, plus 2.50%, and the weighted average interest rate on outstanding borrowings was 2.98% at June 30, 2016. Amounts borrowed under the TCEH DIP Term Loan Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 3%, and the interest rate on outstanding borrowings was 3.75% at both June 30, 2016 and December 31, 2015. The TCEH DIP Facility also provides for certain additional fees payable to the agents and lenders, as well as availability fees payable with respect to any unused portions of the available TCEH DIP Facility.

The TCEH Debtors' obligations under the TCEH DIP Facility are secured by a lien covering substantially all of the TCEH Debtors' assets, rights and properties (including the assets acquired in the Lamar and Forney Acquisition), 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 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.

The RCT agreed to accept a collateral bond from TCEH of up to $1.1 billion 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. Consolidated Superpriority Secured Net Debt consists of outstanding term loans and revolving credit exposure under the TCEH DIP Facility less unrestricted cash. As of June 30, 2016, we are in compliance with this financial covenant. 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.


22

EFIH DIP Facility, EFIH First Lien Notes Settlement and EFIH Second Lien Notes Repayment — The Bankruptcy Court approved the EFIH DIP Facility in June 2014. The EFIH DIP Facility provides for a $5.4 billion first-lien debtor-in-possession financing facility. In March 2015, $750 million of cash borrowings were used to repay $445 million principal amount of EFIH Second Lien Notes (including accrued and unpaid pre-petition interest of $55 million and post-petition interest of $235 million) and certain fees (see Note 11).

As of June 30, 2016, remaining cash on hand from borrowings under the EFIH DIP Facility, net of fees, totaled approximately $275 million, which was held as cash and cash equivalents. In the June 30, 2016 condensed consolidated balance sheet, the borrowings under the EFIH DIP Facility are reported as current liabilities. In January 2016, the EFIH Debtors paid a $14 million extension fee to extend the maturity date of the EFIH DIP Facility to December 2016. The terms of the EFIH DIP Facility were otherwise unchanged. The EFIH DIP Facility must be repaid in full prior to the EFIH Debtors emergence from the Chapter 11 Cases.

The principal amounts outstanding under the EFIH DIP Facility bear interest based on applicable LIBOR rates, subject to a 1% floor, plus 3.25%. At both June 30, 2016 and December 31, 2015, outstanding borrowings under the EFIH DIP Facility totaled $5.4 billion at an annual interest rate of 4.25%. The EFIH DIP Facility is a non-amortizing loan that may, subject to certain limitations, be voluntarily prepaid by the EFIH Debtors, in whole or in part, without any premium or penalty.

The EFIH DIP Facility will mature on the earlier of (a) the effective date of any plan of reorganization, (b) upon the event of the sale of substantially all of EFIH's assets or (c) December 2016.

EFIH's obligations under the EFIH DIP Facility are secured by a first lien covering substantially all of EFIH's assets, rights and properties, subject to certain exceptions set forth in the EFIH DIP Facility. The EFIH DIP Facility provides that all obligations thereunder constitute administrative expenses in the Chapter 11 Cases, with administrative priority and senior secured status under the Bankruptcy Code and, subject to certain exceptions set forth in the EFIH DIP Facility, will have priority over any and all administrative expense claims, unsecured claims and costs and expenses in the Chapter 11 Cases.

The EFIH DIP Facility provides for affirmative and negative covenants applicable to EFIH and EFIH Finance, including affirmative covenants requiring EFIH and EFIH Finance to provide financial information, budgets and other information to the agents under the EFIH DIP Facility, and negative covenants restricting EFIH's and EFIH Finance's ability to incur additional indebtedness, grant liens, dispose of assets, pay dividends or take certain other actions, in each case except as permitted in the EFIH DIP Facility. The EFIH DIP Facility also includes a minimum liquidity covenant pursuant to which EFIH cannot allow the amount of its unrestricted cash (as defined in the EFIH DIP Facility) to be less than $150 million. As of June 30, 2016, EFIH was in compliance with this minimum liquidity covenant. The Oncor Ring-Fenced Entities are not restricted subsidiaries for purposes of the EFIH DIP Facility.

The EFIH DIP Facility provides for certain customary events of default, including events of default resulting from non-payment of principal, interest or other amounts when due, material breaches of representations and warranties, material breaches of covenants in the EFIH DIP Facility or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against EFIH. Upon the existence of an event of default, the EFIH DIP Facility provides that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

The EFIH DIP Facility permits, subject to certain terms, conditions and limitations set forth in the EFIH DIP Facility, EFIH to incur incremental junior lien subordinated debt in an aggregate amount not to exceed $3 billion.


23

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,
2016
 
December 31,
2015
EFH Corp. (parent entity)
 
 
 
8.82% Non-Debtor Building Financing due semiannually through February 11, 2022
$
33

 
$
35

Unamortized fair value premium (a)
5

 
6

Total EFH Corp.
38

 
41

EFCH
 
 
 
9.58% Fixed Notes due in annual installments through December 4, 2019 (b)
13

 
13

8.254% Fixed Notes due in quarterly installments through December 31, 2021 (b)
21

 
24

Unamortized fair value discount (a)
(2
)
 
(2
)
Total EFCH
32

 
35

TCEH
 
 
 
7.48% Fixed Secured Facility Bonds with amortizing payments through January 2017 (c)
10

 
13

Capital lease obligations
4

 
5

Other
2

 
2

Unamortized discount
—

 
(1
)
Total TCEH
16

 
19

Total EFH Corp. consolidated
86

 
95

Less amounts due currently
(34
)
 
(35
)
Total long-term debt not subject to compromise
$
52

 
$
60

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


24


11.
LIABILITIES SUBJECT TO COMPROMISE (LSTC)

The amounts classified as 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. 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, 2016 and December 31, 2015:
 
June 30,
2016
 
December 31,
2015
Notes, loans and other debt per the following table
$
35,560

 
$
35,560

Accrued interest on notes, loans and other debt
745

 
745

Net liability under terminated TCEH interest rate swap and natural gas hedging agreements (Note 15)
1,243

 
1,243

Trade accounts payable and other expected allowed claims
240

 
238

Total liabilities subject to compromise
$
37,788

 
$
37,786


Pre-Petition Notes, Loans and Other Debt Reported as LSTC

Amounts presented below represent principal amounts of pre-petition notes, loans and other debt reported as LSTC.
 
June 30,
2016
 
December 31,
2015
EFH Corp. (parent entity)
 
 
 
9.75% Fixed Senior Notes due October 15, 2019
$
2

 
$
2

10% Fixed Senior Notes due January 15, 2020
3

 
3

10.875% Fixed Senior Notes due November 1, 2017
33

 
33

11.25% / 12.00% Senior Toggle Notes due November 1, 2017
27

 
27

5.55% Fixed Series P Senior Notes due November 15, 2014
89

 
89

6.50% Fixed Series Q Senior Notes due November 15, 2024
198

 
198

6.55% Fixed Series R Senior Notes due November 15, 2034
288

 
288

Total EFH Corp.
640

 
640

EFIH
 
 
 
11% Fixed Senior Secured Second Lien Notes due October 1, 2021
322

 
322

11.75% Fixed Senior Secured Second Lien Notes due March 1, 2022
1,389

 
1,389

11.25% / 12.25% Senior Toggle Notes due December 1, 2018
1,530

 
1,530

9.75% Fixed Senior Notes due October 15, 2019
2

 
2

Total EFIH
3,243

 
3,243

EFCH
 
 
 
Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037
1

 
1

8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037
8

 
8

Total EFCH
9

 
9

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
15,691

 
15,691

TCEH Floating Rate Letter of Credit Facility due October 10, 2017
1,020

 
1,020

11.5% Fixed Senior Secured Notes due October 1, 2020
1,750

 
1,750

15% Fixed Senior Secured Second Lien Notes due April 1, 2021
336

 
336

15% Fixed Senior Secured Second Lien Notes due April 1, 2021, Series B
1,235

 
1,235

10.25% Fixed Senior Notes due November 1, 2015
1,833

 
1,833


25

 
June 30,
2016
 
December 31,
2015
10.25% Fixed Senior Notes due November 1, 2015, Series B
$
1,292

 
$
1,292

10.50% / 11.25% Senior Toggle Notes due November 1, 2016
1,749

 
1,749

Pollution Control Revenue Bonds:
 
 
 
Brazos River Authority:
 
 
 
5.40% Fixed Series 1994A due May 1, 2029
39

 
39

7.70% Fixed Series 1999A due April 1, 2033
111

 
111

7.70% Fixed Series 1999C due March 1, 2032
50

 
50

8.25% Fixed Series 2001A due October 1, 2030
71

 
71

8.25% Fixed Series 2001D-1 due May 1, 2033
171

 
171

6.30% Fixed Series 2003B due July 1, 2032
39

 
39

6.75% Fixed Series 2003C due October 1, 2038
52

 
52

5.40% Fixed Series 2003D due October 1, 2029
31

 
31

5.00% Fixed Series 2006 due March 1, 2041
100

 
100

Sabine River Authority of Texas:
 
 
 
6.45% Fixed Series 2000A due June 1, 2021
51

 
51

5.20% Fixed Series 2001C due May 1, 2028
70

 
70

5.80% Fixed Series 2003A due July 1, 2022
12

 
12

6.15% Fixed Series 2003B due August 1, 2022
45

 
45

Trinity River Authority of Texas:
 
 
 
6.25% Fixed Series 2000A due May 1, 2028
14

 
14

Other
1

 
1

Total TCEH
31,668

 
31,668

Total EFH Corp. consolidated notes, loans and other debt
$
35,560

 
$
35,560


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 both June 30, 2016 and December 31, 2015, the restricted cash related to the pre-petition TCEH Letter of Credit Facility totaled $507 million, and there were no outstanding letters of credit related to the pre-petition TCEH Letter of Credit Facility. Due to the default under the pre-petition TCEH Senior Secured Facilities, the letter of credit capacity is no longer available.

Repayment of EFIH Notes

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

Information Regarding Significant Pre-Petition Debt

See Note 13 to the Financial Statements in our 2015 Form 10-K for information regarding our pre-petition debt. There have been no changes in pre-petition debt since December 31, 2015.


26


12.
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 10 and 11 for discussion of guarantees and security for certain of our post-petition and pre-petition debt.

Letters of Credit

At June 30, 2016, TCEH had outstanding letters of credit under the TCEH DIP Facility totaling $528 million as follows:

•
$386 million to support commodity risk management and trading collateral requirements in the normal course of business, including over-the-counter and exchange-traded hedging transactions and collateral postings with ERCOT;
•
$63 million to support executory contracts and insurance agreements;
•
$55 million to support TCEH's REP financial requirements with the PUCT, and
•
$24 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.

Litigation

Aurelius Derivative Claim — Aurelius Capital Master, Ltd. and ACP Master, Ltd. (Aurelius) filed a lawsuit in March 2013, amended in May 2013, in the US District Court for the Northern District of Texas (Dallas Division) against EFCH as a nominal defendant and each of the current directors and a former director of EFCH. In the lawsuit, Aurelius, as a creditor under the TCEH Senior Secured Facilities and certain TCEH secured bonds, both of which are guaranteed by EFCH, filed a derivative claim against EFCH and its directors. Aurelius alleged that the directors of EFCH breached their fiduciary duties to EFCH and its creditors, including Aurelius, by permitting TCEH to make certain loans "without collecting fair and reasonably equivalent value." The lawsuit sought recovery for the benefit of EFCH. In January 2014, the district court granted EFCH's and the directors' motion to dismiss and in February 2014 dismissed the lawsuit. Aurelius has appealed the district court's judgment to the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court). The appeal was automatically stayed as a result of the Bankruptcy Filing. We cannot predict the outcome of this proceeding, including the financial effects, if any.

Make-whole Claims — In May 2014, the indenture trustee for the EFIH 10% First Lien Notes initiated litigation in the Bankruptcy Court seeking, among other things, a declaratory judgment that EFIH is obligated to pay a make-whole premium in connection with the cash repayment of the EFIH First Lien Notes and that such make-whole premium is an allowed secured claim, or in the alternative, an allowed secured or unsecured claim for breach of contract (EFIH First Lien Make-whole Claims). The indenture trustee has alleged that the EFIH First Lien Make-whole Claims are valued at approximately $432 million plus reimbursement of expenses. In separate rulings in March and July 2015, the Bankruptcy Court found that no make-whole premium is due with respect to the EFIH 10% First Lien Notes. In February 2016, the US District Court for the District of Delaware affirmed the Bankruptcy Court's rulings. In February 2016, the Indenture Trustee appealed the District Court's ruling to the US Court of Appeals for the Third Circuit. Oral argument has been scheduled for September 27, 2016. The EFIH Debtors intend to vigorously defend against this appeal. We cannot predict the outcome of this appeal.


27

In June 2014, the indenture trustee for the EFIH Second Lien Notes initiated litigation in the Bankruptcy Court seeking similar relief as the trustee of the EFIH 10% First Lien Notes with respect to the EFIH Second Lien Notes, including among other things, that EFIH is obligated to pay a make-whole premium in connection with any repayment of the EFIH Second Lien Notes and that such make-whole premium would be an allowed secured claim, or in the alternative, an allowed secured or unsecured claim for breach of contract (the EFIH Second Lien Make-whole Claims). If, as of June 30, 2016, the EFIH Second Lien Make-whole Claims were allowed, the amount of such claims would have been approximately $317 million plus reimbursement of expenses. In October 2015, the Bankruptcy Court issued a finding that no make-whole premium is due with respect to the EFIH Second Lien Notes. In April 2016, the US District Court for the District of Delaware issued a ruling and order affirming the Bankruptcy Court's decision. The indenture trustee has appealed that decision to the US Court of Appeals for the Third Circuit, and that court has consolidated the appeal with the appeal filed by the indenture trustee for the EFIH 10% First Lien Notes described above for the purposes of oral argument and final disposition. Oral argument has been scheduled for September 27, 2016. The EFIH Debtors intend to vigorously defend against this appeal. We cannot predict the outcome of this appeal.

In July 2015, the EFIH Debtors filed a claim objection with the Bankruptcy Court regarding the EFIH PIK noteholders' claims for a redemption or make-whole premium and post-petition interest at the contract rate under the EFIH PIK Notes. In October 2015, the Bankruptcy Court issued opinions in favor of the EFIH Debtors. One opinion found that no make-whole premium is due with respect to the EFIH PIK Notes. The second opinion found that the EFIH PIK noteholders' allowed claim does not, as a matter of law, include post-petition interest whether at the contract rate or the Federal Judgment Rate. This opinion did find, however, that, in connection with the confirmation of a plan of reorganization, the Bankruptcy Court could, at its discretion, grant post-petition interest as part of the EFIH PIK noteholders' allowed claim under general principals of equity and that such grant could be at the contract rate, the Federal Judgment Rate or any other amount that the Bankruptcy Court determines to be equitable. The EFIH PIK Noteholders have appealed both rulings to the US District Court for the District of Delaware. With respect to the make-whole premium dispute, the parties have agreed to a briefing schedule that will conclude in August 2016. The appeal of the post-petition interest ruling has been stayed by the US District Court for the District of Delaware pending an equitable proceeding suggested by the Bankruptcy Court's second opinion. No briefing schedule has been set for that equitable proceeding. The EFIH Debtors intend to vigorously defend against the appeals and the award of post-petition interest at a rate higher than the Federal Judgment Rate. We cannot predict the outcome of either of these appeals or any equitable proceeding seeking the award of post-petition interest.

In October 2015, EFH Corp. filed a claim objection with the Bankruptcy Court with respect to the EFH Corp. Series P, Q and R Senior Notes (collectively, the EFH Legacy Notes) noteholders' claims for, among other things, make-whole premiums and post-petition interest. If, as of June 30, 2016, a make-whole claim and a post-petition interest claim were allowed, such claims would be $265 million and $87 million, respectively. In October 2015, the indenture trustee for the EFH Legacy Notes filed a response to this claim objection. No argument date has been set by the Bankruptcy Court regarding the EFH Legacy Notes claim objection. EFH Corp. intends to vigorously pursue its claim objection. We cannot predict the outcome of this proceeding.

In October 2015, EFH Corp. filed a claim objection with the Bankruptcy Court with respect to the EFH Corp. 10.875% Senior Notes and 11.25%/12% Senior Toggle Notes (collectively, the EFH LBO Notes) noteholders' claims for, among other things, optional redemption payment and post-petition interest. If, as of June 30, 2016, a redemption claim and a post-petition interest claim were allowed, such claims would be zero and $17 million, respectively. The indenture trustee for the EFH LBO Notes has not yet filed a response to this claim objection. No argument date has been set by the Bankruptcy Court regarding the EFH LBO Notes claim objection. EFH Corp. intends to vigorously pursue its claim objection. We cannot predict the outcome of this proceeding.

In addition, creditors may make additional claims in the Chapter 11 Cases for make-whole or redemption premiums in connection with repayments or settlement of other pre-petition debt. These claims could be material. There can be no assurance regarding the outcome of any of the litigation regarding the validity or, if deemed valid, the amount of these make-whole or redemption claims.

Adversary Complaint against Texas Transmission — In October 2015, EFH Corp. filed with the Bankruptcy Court an adversary complaint against Texas Transmission seeking a judgment from the Bankruptcy Court regarding the obligations of Texas Transmission under an investor rights agreement to participate in a sale of EFH Corp.'s interests in Oncor. In April 2016, the Bankruptcy Court announced it would approve EFH Corp.'s motion for summary judgment in full and denied Texas Transmission's motion for a determination that the court lacks authority to enter a final judgment or order in the proceeding. In May 2016, the Bankruptcy Court entered an order dismissing the proceeding as no longer relevant as a result of the termination of the merger agreement relating to the proposed sale of EFH Corp.'s ownership in Oncor.


28

Litigation Related to EPA Reviews — In June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of the Clean Air Act (CAA). The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. In April 2013, we received an additional information request from the EPA under Section 114 related to the Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to the Sandow 4 generation facility.

In July 2012, the EPA sent us a notice of violation alleging noncompliance with the CAA's New Source Review Standards and the air permits at our Martin Lake and Big Brown generation facilities. In July 2013, the EPA sent us a second notice of violation alleging noncompliance with the CAA's New Source Review Standards at our Martin Lake and Big Brown generation facilities, which the EPA said "superseded" its July 2012 notice. In August 2013, the US Department of Justice, acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant Generation Company LLC and Big Brown Power Company LLC in federal district court in Dallas, alleging violations of the CAA at our Big Brown and Martin Lake generation facilities. In August 2015, the district court issued its ruling on our motion to dismiss and granted the motion as to seven of the nine claims asserted by the EPA in the lawsuit. Two claims remain before the district court, and those are currently scheduled for trial in October 2017. We believe that we have complied with all requirements of the CAA and intend to vigorously defend against the remaining allegations. The lawsuit requests the maximum civil penalties available under the CAA to the government of up to $32,500 to $37,500 per day for each alleged violation, depending on the date of the alleged violation, and injunctive relief, including an order requiring the installation of best available control technology at the affected units. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. We cannot predict the outcome of these proceedings, including the financial effects, if any.

Greenhouse Gas Emissions

In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from new, modified and reconstructed units, and existing electricity generation plants. The rule for existing facilities would establish state-specific emissions rate goals to reduce nationwide carbon dioxide emissions related to affected electricity generation units by over 30% from 2012 emission levels by 2030. A number of parties, including Luminant, filed petitions for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) for the rule for new, modified and reconstructed plants. In addition, a number of petitions for review of the rule for existing plants were filed in the D.C. Circuit Court by various parties and groups, including challenges from twenty-seven different states opposed to the rule as well as those from, among others, certain power generating companies, various business groups and some labor unions. Luminant also filed its own petition for review. In January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the US Supreme Court asking that the court stay the rule while the court reviews the legality of the rule for existing plants. In February 2016, the US Supreme Court stayed the rule pending the conclusion of legal challenges on the rule before the D.C. Circuit Court and until the US Supreme Court disposes of any subsequent petition for review. Oral argument on the merits of the legal challenges to the rule is scheduled for September 2016 before the entire D.C. Circuit Court. While we cannot predict the outcome of this rulemaking and legal proceedings on our results of operations, liquidity or financial condition, the impacts could be material.

In August 2015, the EPA proposed model rules and federal plan requirements for states to consider as they develop state plans to comply with the rules for GHG emissions. A federal plan would then be finalized for a state if a state fails to submit a state plan by the deadlines established in the CAA for existing plants or if the EPA disapproves a submitted state plan. We filed comments on the federal plan proposal in January 2016. While we cannot predict the timing or outcome of this rulemaking and legal proceedings on our results of operations, liquidity or financial condition, the impacts could be material.

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).


29

The CSAPR became effective January 1, 2015. In July 2015, following a remand of the case from the US Supreme Court to consider further legal challenges, the D.C. Circuit Court unanimously ruled in favor of us and other petitioners, holding that the CSAPR emissions budgets over-controlled Texas and other states. The D.C. Circuit Court remanded those states' budgets to the EPA for prompt reconsideration. While we planned to participate in the EPA's reconsideration process to develop increased budgets that do not over-control Texas, the EPA instead responded to the remand by updating the NOX ozone season budget for the 2008 ozone standard with a new rulemaking without explicitly addressing the issues of over-control of the 1997 standard. Comments on the EPA's proposal were submitted by Luminant in February 2016. In June 2016, the EPA issued a memorandum describing the EPA's proposed approach for responding to the D.C. Circuit Court's remand for reconsideration of the CSAPR SO2 emission budgets for Texas and three other states that had been remanded to the EPA by the D.C. Circuit Court. In the memorandum, the EPA stated that those four states could either voluntarily participate in the CSAPR by submitting a SIP revision adopting the SO2 budgets that had been previously held invalid by the D.C. Circuit Court and the current annual NOx budgets or, if the state chooses not to participate in the CSAPR, the EPA could withdraw the CSAPR FIPs by the fall of 2016 for those states and address any interstate transport and regional haze obligations on a state-by-state basis. While we cannot predict the outcome of future proceedings related to the CSAPR, including the EPA's recent actions concerning the CSAPR annual emissions budgets for affected states and participating in the CSAPR program, based upon our current operating plans we do not believe that the CSAPR will cause any material operational, financial or compliance issues. We are currently evaluating the EPA's recent proposed actions regarding SO2 budgets for Texas.

Regional Haze

The Regional Haze Program of the CAA establishes "as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I federal areas, like national parks, which impairment results from man-made pollution." There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. Second, electricity generation units built between 1962 and 1977 are subject to best available retrofit technology (BART) standards designed to improve visibility. BART reductions of SO2 and 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 CSAPR. In February 2009, the TCEQ submitted a State Implementation Plan (SIP) concerning regional haze (Regional Haze SIP) to the EPA. In December 2011, the EPA proposed a limited disapproval of the Regional Haze SIP due to its reliance on the Clean Air Interstate Rule (CAIR) instead of the EPA's replacement CSAPR program. In August 2012, we filed a petition for review in the Fifth Circuit Court challenging the EPA's limited disapproval of the Regional Haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court's decision in the CSAPR litigation. In September 2012, we filed a petition to intervene in a case filed by industry groups and other states and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance of a Federal Implementation Plan (FIP) regarding the regional haze BART program. The Fifth Circuit Court case has since been transferred to the D.C. Circuit Court and consolidated with other pending BART program regional haze appeals. Briefing in the D.C. Circuit Court is scheduled to be completed by March 2017.

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


30

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

State Implementation Plan (SIP)

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

In June 2014, the Sierra Club filed a petition in the D.C. Circuit Court seeking review of several EPA regulations containing affirmative defenses for malfunctions, including the Mercury and Air Toxics Standard (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. In March 2016, the EPA finalized the MATS technical corrections, including the removal of affirmative defense for malfunctions. Except as set forth above, we cannot predict the timing or outcome of future proceedings related to this petition, the petition for administrative reconsideration that is pending before the EPA or the financial effects of these proceedings, if any.

Other Matters

We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.


31


13.
EQUITY

EFH Corp. has not declared or paid any dividends since the Merger. The agreement governing the TCEH DIP Facility generally restricts TCEH's ability to make distributions or loans to any of its parent companies or their subsidiaries unless such distributions or loans are expressly permitted under the agreement governing such facility. The agreement governing the EFIH DIP Facility generally restricts EFIH's ability to make distributions or loans to any of its parent companies or their subsidiaries unless such distributions or loans are expressly permitted under the agreement governing such facility.

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

Equity

The following table presents the changes to equity for the six months ended June 30, 2016:
 
EFH Corp. Shareholders’ Equity
 
 
 
Common Stock (a)
 
Additional Paid-in Capital
 
Retained Earnings (Deficit)
 
Accumulated Other Comprehensive Loss
 
Total Equity
Balance at December 31, 2015
$
2

 
$
7,968

 
$
(32,905
)
 
$
(126
)
 
$
(25,061
)
Net loss
—

 
—

 
(579
)
 
—

 
(579
)
Change in unrecognized losses related to pension and OPEB plans
—

 
—

 
—

 
(3
)
 
(3
)
Net effects of cash flow hedges
—

 
—

 
—

 
1

 
1

Net effects related to Oncor
—

 
—

 
—

 
1

 
1

Balance at June 30, 2016
$
2

 
$
7,968

 
$
(33,484
)
 
$
(127
)
 
$
(25,641
)
________________
(a)
Authorized shares totaled 2,000,000,000 at June 30, 2016. Outstanding shares totaled 1,669,861,379 at both June 30, 2016 and December 31, 2015.

The following table presents the changes to equity for the six months ended June 30, 2015:
 
EFH Corp. Shareholders’ Equity
 
 
 
Common Stock (a)
 
Additional Paid-in Capital
 
Retained Earnings (Deficit)
 
Accumulated Other Comprehensive Loss
 
Total Equity
Balance at December 31, 2014
$
2

 
$
7,968

 
$
(27,563
)
 
$
(130
)
 
$
(19,723
)
Net loss
—

 
—

 
(1,739
)
 
—

 
(1,739
)
Change in unrecognized losses related to pension and OPEB plans
—

 
—

 
—

 
(2
)
 
(2
)
Net effects of cash flow hedges
—

 
—

 
—

 
1

 
1

Net effects related to Oncor
—

 
—

 
—

 
1

 
1

Balance at June 30, 2015
$
2

 
$
7,968

 
$
(29,302
)
 
$
(130
)
 
$
(21,462
)
________________
(a)
Authorized shares totaled 2,000,000,000 at June 30, 2015. Outstanding shares totaled 1,669,861,379 at both June 30, 2015 and December 31, 2014.


32

Accumulated Other Comprehensive Loss

The following table presents the changes to accumulated other comprehensive income (loss) for the six months ended June 30, 2016. There was no other comprehensive income (loss) before reclassification for the period.
 
Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 15)
 
Pension and Other Postretirement Employee Benefit Liabilities Adjustments
 
Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2015
$
(50
)
 
$
(76
)
 
$
(126
)
Amounts reclassified from accumulated other comprehensive loss and reported in:
 
 
 
 
 
Operating costs
—

 
(2
)
 
(2
)
Depreciation and amortization
1

 
—

 
1

Selling, general and administrative expenses
—

 
(3
)
 
(3
)
Income tax benefit
—

 
2

 
2

Equity in earnings of unconsolidated subsidiaries (net of tax)
1

 
—

 
1

Total amount reclassified from accumulated other comprehensive loss during the period
2

 
(3
)
 
(1
)
Balance at June 30, 2016
$
(48
)
 
$
(79
)
 
$
(127
)

The following table presents the changes to accumulated other comprehensive income (loss) for the six months ended June 30, 2015. There was no other comprehensive income (loss) before reclassification for the period.
 
Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 15)
 
Pension and Other Postretirement Employee Benefit Liabilities Adjustments
 
Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2014
$
(53
)
 
$
(77
)
 
$
(130
)
Amounts reclassified from accumulated other comprehensive loss and reported in:
 
 
 
 
 
Operating costs
—

 
(1
)
 
(1
)
Depreciation and amortization
1

 
—

 
1

Selling, general and administrative expenses
—

 
(2
)
 
(2
)
Income tax benefit
—

 
1

 
1

Equity in earnings of unconsolidated subsidiaries (net of tax)
1

 
—

 
1

Total amount reclassified from accumulated other comprehensive loss during the period
2

 
(2
)
 
—

Balance at June 30, 2015
$
(51
)
 
$
(79
)
 
$
(130
)


14.
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.


33

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

•
Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange-traded commodity contracts. For example, some of our derivatives are NYMEX or ICE futures and swaps transacted through clearing brokers for which prices are actively quoted.

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

•
Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives with values derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means. See further discussion below.

Our valuation policies and procedures are developed, maintained and validated by a centralized risk management group that reports to the Chief Financial Officer, who also functions as the Chief Risk Officer. Risk management functions include commodity price reporting and validation, valuation model validation, risk analytics, risk control, credit risk management and risk reporting.

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.

In utilizing broker quotes, we attempt to obtain multiple quotes from brokers (generally non-binding) that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other factors.

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 15 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.

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.


34

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, 2016
 
Level 1
 
Level 2
 
Level 3 (a)
 
Reclassification (b)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
239

 
$
50

 
$
74

 
$
15

 
$
378

Nuclear decommissioning trust –
equity securities (c)
396

 
—

 
—

 
—

 
396

Nuclear decommissioning trust –
debt securities (c)
—

 
342

 
—

 
—

 
342

Sub-total
$
635

 
$
392

 
$
74

 
$
15

 
1,116

Assets measured at net asset value (d):
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trust –
equity securities (c)
 
 
 
 
 
 
 
 
228

Total assets
 
 
 
 
 
 
 
 
$
1,344

Liabilities:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
168

 
$
120

 
$
83

 
$
15

 
$
386

Total liabilities
$
168

 
$
120

 
$
83

 
$
15

 
$
386


December 31, 2015
 
Level 1
 
Level 2
 
Level 3 (a)
 
Reclassification (b)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
385

 
$
41

 
$
49

 
$
—

 
$
475

Nuclear decommissioning trust –
equity securities (c)
380

 
219

 
—

 
—

 
599

Nuclear decommissioning trust –
debt securities (c)
—

 
319

 
—

 
—

 
319

Total assets
$
765

 
$
579

 
$
49

 
$
—

 
$
1,393

Liabilities:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
128

 
$
64

 
$
12

 
$
—

 
$
204

Total liabilities
$
128

 
$
64

 
$
12

 
$
—

 
$
204

____________
(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 other investments line in the condensed consolidated balance sheets. See Note 18.
(d)
Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. This presentation is only allowed for periods beginning after December 15, 2015. The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the condensed consolidated balance sheets.

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 15 for further discussion regarding derivative instruments.


35

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facility. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at June 30, 2016 and December 31, 2015:
June 30, 2016
 
 
Fair Value
 
 
 
 
 
 
Contract Type (a)
 
Assets
 
Liabilities
 
Total
 
Valuation Technique
 
Significant Unobservable Input
 
Range (b)
Electricity purchases and sales
 
$
3

 
$
(33
)
 
$
(30
)
 
Valuation Model
 
Hourly price curve shape (d)
 
$0 to $35/ MWh
 
 
 
 
 
 
 
 
 
 
Illiquid delivery periods for ERCOT hub power prices and heat rates (e)
 
$30 to $60/ MWh
Electricity spread options
 
32

 
(45
)
 
(13
)
 
Option Pricing Model
 
Gas to power correlation (f)
 
50% to 100%
 
 
 
 
 
 
 
 
 
 
Power volatility (g)
 
10% to 45%
Electricity congestion revenue rights
 
34

 
(4
)
 
30

 
Market Approach (h)
 
Illiquid price differences between settlement points (i)
 
$0 to $10/MWh
Other (j)
 
5

 
(1
)
 
4

 
 
 
 
 
 
Total
 
$
74

 
$
(83
)
 
$
(9
)
 
 
 
 
 
 

December 31, 2015
 
 
Fair Value
 
 
 
 
 
 
Contract Type (a)
 
Assets
 
Liabilities
 
Total
 
Valuation Technique
 
Significant Unobservable Input
 
Range (b)
Electricity purchases and sales
 
$
1

 
$
(1
)
 
$
—

 
Valuation Model
 
Illiquid pricing locations (c)
 
$15 to $35/ MWh
 
 
 
 
 
 
 
 
 
 
Hourly price curve shape (d)
 
$15 to $45/ MWh
Electricity spread options
 
2

 
(7
)
 
(5
)
 
Option Pricing Model
 
Gas to power correlation (f)
 
35% to 80%
 
 
 
 
 
 
 
 
 
 
Power volatility (g)
 
10% to 35%
Electricity congestion revenue rights
 
39

 
(4
)
 
35

 
Market Approach (h)
 
Illiquid price differences between settlement points (i)
 
$0 to $10/MWh
Other (j)
 
7

 
—

 
7

 
 
 
 
 
 
Total
 
$
49

 
$
(12
)
 
$
37

 
 
 
 
 
 
____________
(a)
Electricity purchase and sales contracts include power and heat rate hedging positions in the ERCOT regions. Electricity spread options contracts consist of physical electricity call options. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT.
(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)
Based on historical forward ERCOT power price and heat rate variability.
(f)
Estimate of the historical range based on forward natural gas and on-peak power prices for the ERCOT hubs most relevant to our spread options.
(g)
Based on historical forward price changes.
(h)
While we use the market approach, there is insufficient market data to consider the valuation liquid.
(i)
Based on the historical price differences between settlement points within the ERCOT hubs and load zones.

36

(j)
Other includes contracts for ancillary services, natural gas, power options, coal and coal options.

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, 2016 and 2015. 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, 2016 and 2015. During the three months ended June 30, 2016, in conjunction with the Lamar and Forney Acquisition, we assumed certain electricity spread options that are classified in Level 3 of the fair value hierarchy.

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, 2016 and 2015.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Net asset balance at beginning of period
$
25

 
$
60

 
$
37

 
$
35

Total unrealized valuation gains (losses)
1

 
(2
)
 
(4
)
 
14

Purchases, issuances and settlements (a):
 
 
 
 
 
 
 
Purchases
12

 
13

 
26

 
32

Issuances
(4
)
 
(2
)
 
(16
)
 
(5
)
Settlements
(17
)
 
(17
)
 
(27
)
 
(25
)
Transfers into Level 3 (b)
1

 
—

 
1

 
—

Transfers out of Level 3 (b)
—

 
(8
)
 
1

 
(7
)
Net liabilities assumed in the Lamar and Forney Acquisition (Note 3)
(27
)
 
—

 
(27
)
 
—

Net change (c)
(34
)
 
(16
)
 
(46
)
 
9

Net asset (liability) balance at end of period
$
(9
)
 
$
44

 
$
(9
)
 
$
44

Unrealized valuation gains (losses) relating to instruments held at end of period
$
(5
)
 
$
1

 
$
(8
)
 
$
9

____________
(a)
Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received.
(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 (excluding net liabilities assumed in the Lamar and Forney Acquisition) are reported in the condensed statements of consolidated 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.


15.
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. See Note 14 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 from our lignite/coal and nuclear fueled generation. In ERCOT, the wholesale price of electricity has generally moved with the price of natural gas. 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 loss in net gain (loss) from commodity hedging and trading activities.


37

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 total net liability of $1.243 billion is subject to the terms of settlement of TCEH's first-lien claims ultimately approved by the Bankruptcy Court and is reported in the 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 8).

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 derivative contractual assets and liabilities as reported in the condensed consolidated balance sheets at June 30, 2016 and December 31, 2015. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract. All amounts relate to commodity contracts.
 
June 30, 2016
 
December 31, 2015
 
Derivative
Assets
 
Derivative Liabilities
 
Total
 
Derivative
Assets
 
Derivative Liabilities
 
Total
Current assets
$
355

 
$
8

 
$
363

 
$
465

 
$
—

 
$
465

Noncurrent assets
15

 
—

 
15

 
10

 
—

 
10

Current liabilities
—

 
(315
)
 
(315
)
 
—

 
(203
)
 
(203
)
Noncurrent liabilities
(7
)
 
(64
)
 
(71
)
 
—

 
(1
)
 
(1
)
Net assets (liabilities)
$
363

 
$
(371
)
 
$
(8
)
 
$
475

 
$
(204
)
 
$
271


At June 30, 2016 and December 31, 2015, there were no derivative positions accounted for as cash flow or fair value hedges.

The pretax effect of derivatives on net income (loss), including realized and unrealized effects, totaled $100 million in net losses and $26 million in net gains in the three months ended June 30, 2016 and 2015, respectively, and $45 million in net losses and $151 million in net gains in the six months ended June 30, 2016 and 2015, respectively, all of which related to commodity contracts reported in net gain (loss) from commodity hedging and trading activities in the condensed statements of consolidated loss. Amounts represent 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.

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, 2016 and 2015. There were no amounts recognized in OCI for the three and six months ended June 30, 2016 and 2015.

Accumulated other comprehensive income related to cash flow hedges (excluding Oncor's interest rate hedges) at June 30, 2016 and December 31, 2015 totaled $33 million and $34 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, 2016 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

Balance Sheet Presentation of Derivatives

Consistent with elections under US GAAP to present amounts on a gross basis, we report derivative assets and liabilities in the 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.


38

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 general corporate purposes or, if there are restrictions on the use of cash, amounts are deposited in a separate restricted cash account. At June 30, 2016 and December 31, 2015, essentially 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. These agreements 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, 2016
 
 
Amounts Presented in Balance Sheet
 
Offsetting Instruments (a)
 
Financial Collateral (Received) Pledged (b)
 
Net Amounts
Derivative assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
378

 
$
(249
)
 
$
(32
)
 
$
97

Derivative liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
(386
)
 
249

 
—

 
(137
)
Net amounts
 
$
(8
)
 
$
—

 
$
(32
)
 
$
(40
)

December 31, 2015
 
 
Amounts Presented in Balance Sheet
 
Offsetting Instruments (a)
 
Financial Collateral (Received) Pledged (b)
 
Net Amounts
Derivative assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
475

 
$
(145
)
 
$
(147
)
 
$
183

Derivative liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
(204
)
 
145

 
6

 
(53
)
Net amounts
 
$
271

 
$
—

 
$
(141
)
 
$
130

____________
(a)
Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.
(b)
Financial collateral consists entirely of cash margin deposits.

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at June 30, 2016 and December 31, 2015:
 
 
June 30, 2016
 
December 31, 2015
 
 
Derivative type
 
Notional Volume
 
Unit of Measure
Natural gas (a)
 
1,773

 
1,489

 
Million MMBtu
Electricity
 
95,732

 
58,022

 
GWh
Congestion Revenue Rights (b)
 
121,748

 
106,260

 
GWh
Coal
 
5

 
10

 
Million US tons
Fuel oil
 
21

 
35

 
Million gallons
Uranium
 
375

 
75

 
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.


39

Credit Risk-Related Contingent Features of Derivatives

The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies; however, due to the Chapter 11 Cases, substantially all of such collateral posting requirements have already been effective.

At June 30, 2016 and December 31, 2015, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully collateralized totaled $121 million and $58 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with counterparties totaling $43 million and $31 million at June 30, 2016 and December 31, 2015, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross-default provisions, the remaining liquidity requirements would be immaterial at both June 30, 2016 and December 31, 2015.

In addition, certain derivative agreements include cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. At June 30, 2016 and December 31, 2015, the fair value of derivative liabilities subject to such cross-default provisions totaled $42 million and $1 million, respectively. At both June 30, 2016 and December 31, 2015, no cash collateral or letters of credit were posted with these counterparties, and there was no liquidity exposure associated with these liabilities.

As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $163 million and $59 million at June 30, 2016 and December 31, 2015, respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets subject to related liens.

Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.

Concentrations of Credit Risk Related to Derivatives

We have concentrations of credit risk with the counterparties to our derivative contracts. At June 30, 2016, total credit risk exposure to all counterparties related to derivative contracts totaled $474 million (including associated accounts receivable). The net exposure to those counterparties totaled $132 million at June 30, 2016 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $46 million. At June 30, 2016, the credit risk exposure to the banking and financial sector represented 74% of the total credit risk exposure and 49% of the net exposure.

Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.

We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.


40


16.
RELATED PARTY TRANSACTIONS

The following represent our significant related-party transactions.

•
Previously, we accrued a management fee payable to the Sponsor Group under the terms of a management agreement. Related amounts expensed and reported as SG&A expense totaled $10 million and $20 million for the three and six months ended June 30, 2015, respectively. No payments were made in the three and six months ended June 30, 2016 and 2015. We had previously paid these fees on a quarterly basis; however, beginning with the quarterly management fee due December 31, 2013, the Sponsor Group, while reserving the right to receive the fees, directed EFH Corp. to suspend payments of the management fees for an indefinite period. Effective with the Petition Date, EFH Corp. suspended allocations of such fees to TCEH and EFIH. Fees accrued as of the Petition Date were reclassified to LSTC, and fees accrued after the Petition Date were reported in other noncurrent liabilities and deferred credits. Pursuant to the Settlement Agreement approved by the Bankruptcy Court in December 2015, the Sponsor Group has agreed to forego any and all claims under the management agreement in exchange for releases of alleged liabilities against the Debtors.

•
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.

•
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 $216 million and $224 million for the three months ended June 30, 2016 and 2015, respectively, and $436 million and $460 million for the six months ended June 30, 2016 and 2015, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The condensed consolidated balance sheets at June 30, 2016 and December 31, 2015 reflect amounts due currently to Oncor totaling $124 million and $118 million, respectively (included in net payables due to unconsolidated subsidiary), largely related to these electricity delivery fees. Also see discussion below regarding receivables from Oncor under a Federal and State Income Tax Allocation Agreement.

•
A subsidiary of EFH Corp. bills Oncor for financial and other administrative services and shared facilities at cost. Such amounts reduced reported SG&A expense by less than $1 million and $5 million for the three months ended June 30, 2016 and 2015, respectively, and $1 million and $10 million for the six months ended June 30, 2016 and 2015, respectively.

•
A subsidiary of EFH Corp. bills TCEH subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges totaled $46 million and $47 million for the three months ended June 30, 2016 and 2015, respectively, and $106 million and $98 million for the six months ended June 30, 2016 and 2015, respectively.

•
For the three months ended March 31, 2016, TCEH settled a $2 million payable related to information technology assets purchased from a subsidiary of EFH Corp. in December 2015. For 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. For the three months ended June 30, 2015, TCEH purchased and settled $12 million of additional assets. The assets are substantially for the use of TCEH and its subsidiaries.


41

•
Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility is funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to TCEH for contribution to the trust fund with the intent that the trust fund assets, reported in other investments in our condensed consolidated balance sheets, will ultimately be sufficient to fund the future decommissioning liability, reported in noncurrent liabilities in our condensed consolidated balance sheets. The delivery fee surcharges remitted to TCEH totaled $4 million for both the three months ended June 30, 2016 and 2015 and $8 million for both the six months ended June 30, 2016 and 2015. 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, 2016 and December 31, 2015, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $443 million and $409 million, respectively, and is reported in noncurrent liabilities.

•
We file a consolidated federal income tax return that includes Oncor Holdings' results. Oncor is not a member of our consolidated tax group, but our consolidated federal income tax return includes our portion of Oncor's results due to our equity ownership in Oncor. We also file a consolidated Texas state margin tax return that includes all of Oncor Holdings' and Oncor's results. However, under a Federal and State Income Tax Allocation Agreement, Oncor Holdings' and Oncor's federal income tax and Texas margin tax expense and related balance sheet amounts, including our income taxes receivable from or payable to Oncor Holdings and Oncor, are recorded as if Oncor Holdings and Oncor file their own corporate income tax returns.

At June 30, 2016, our net current amount payable to Oncor Holdings related to federal and state income taxes (reported in net payables due to unconsolidated subsidiary) totaled $79 million, $84 million of which related to Oncor. The $84 million net payable to Oncor included a $95 million federal income tax payable and an $11 million state margin tax receivable. Additionally, at June 30, 2016, we had a noncurrent tax payable to Oncor of $65 million recorded in other noncurrent liabilities and deferred credits and a noncurrent tax receivable from Oncor Holdings of $2 million recorded in other noncurrent assets. At December 31, 2015, our net current amount payable to Oncor Holdings related to federal and state income taxes totaled $87 million, $89 million of which related to Oncor. The $89 million net payable to Oncor included a $109 million federal income tax payable offset by a $20 million state margin tax receivable. Additionally, at December 31, 2015, we had a noncurrent tax payable to Oncor of $65 million recorded in other noncurrent liabilities and deferred credits and a noncurrent tax receivable from Oncor Holdings of $2 million recorded in other noncurrent assets.

For the six months ended June 30, 2016, EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $10 million and $18 million, respectively. For the six months ended June 30, 2015, EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $12 million and $22 million, respectively.

•
Oncor collected transition surcharges from its customers to recover the payment obligations related to its securitization (transition) bonds issued to recover generation-related regulatory assets. As of June 30, 2016, Oncor had over-collected transition charges of approximately $2 million that is expected to be refunded to TCEH upon PUCT approval.

•
Oncor had requirements in place to assure adequate creditworthiness to support TCEH's obligation to collect securitization bond-related (transition) charges on its behalf. Under these requirements, as a result of TCEH's credit rating being below investment grade, TCEH was required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, at December 31, 2015, TCEH had posted letters of credit and/or cash in the amount of $6 million for the benefit of Oncor. In May 2016, the last series of Oncor's securitization bonds matured and the letters of credit were released.

•
In December 2012, Oncor became the sponsor of a new pension plan (the Oncor Plan), the participants in which consist of all of Oncor's active employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Oncor had previously contractually agreed to assume responsibility for pension liabilities that are recoverable by Oncor under regulatory rate-setting provisions. As part of the pension plan actions, EFH Corp. fully funded the non-recoverable pension liabilities under the Oncor Plan. After the pension plan actions, participants remaining in the EFH Corp. pension plan consist of active employees under collective bargaining agreements (union employees). Oncor continues to be responsible for the recoverable portion of pension obligations to these union employees. Under ERISA, EFH Corp. and Oncor remain jointly and severally liable for the funding of the EFH Corp. and Oncor pension plans.


42

•
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.


17.
SEGMENT INFORMATION

Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity operations for residential and business customers, all largely in the ERCOT market. These activities are conducted by TCEH.

The Regulated Delivery segment consists largely of our investment in Oncor. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary. See Note 4 for discussion of the reporting of Oncor Holdings and, accordingly, the Regulated Delivery segment, as an equity method investment. See Note 16 for discussion of material transactions with Oncor, including payment to Oncor of electricity delivery fees, which are based on rates regulated by the PUCT.

Corporate and Other represents the remaining non-segment operations consisting primarily of discontinued businesses, general corporate expenses and interest and other expenses related to EFH Corp., EFIH and EFCH.

The business segment results reflect the application of ASC 852, Reorganizations. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 to the Financial Statements in our 2015 Form 10-K. Our chief operating decision maker uses more than one measure to assess segment performance, including reported segment net income (loss), which is the measure most comparable to consolidated net loss prepared based on GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices or regulated rates. Certain shared services costs are allocated to the segments.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Operating revenues (all Competitive Electric)
$
1,233

 
$
1,256

 
$
2,283

 
$
2,527

Equity in earnings of unconsolidated subsidiaries (net of tax) — Regulated Delivery (net of noncontrolling interests of $22, $20, $38 and $39)
$
85

 
$
75

 
$
147

 
$
151

Net income (loss):
 
 
 
 
 
 

Competitive Electric
$
(500
)
 
$
(214
)
 
$
(843
)
 
$
(1,551
)
Regulated Delivery
85

 
75

 
147

 
151

Corporate and Other
85

 
(73
)
 
117

 
(339
)
Consolidated net loss
$
(330
)
 
$
(212
)
 
$
(579
)
 
$
(1,739
)

43


18.
SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Other income:
 
 
 
 
 
 
 
Office space rental income (a)
$
3

 
$
3

 
$
6

 
$
6

Insurance settlement (b)
9

 
—

 
9

 
—

Sale of land (b)
—

 
6

 
—

 
6

All other
4

 
3

 
6

 
7

Total other income
$
16

 
$
12

 
$
21

 
$
19

Other deductions:
 
 
 
 
 
 
 
Write-off of generation equipment (b)
$
21

 
$
—

 
$
41

 
$
—

Impairment of favorable purchase contracts (Note 5) (b)
—

 
—

 
—

 
8

Impairment of emission allowances (Note 5) (b)
—

 
—

 
—

 
51

All other
6

 
2

 
7

 
2

Total other deductions
$
27

 
$
2

 
$
48

 
$
61

____________
(a)
Reported in Corporate and Other.
(b)
Reported in Competitive Electric segment.

Restricted Cash
 
June 30, 2016
 
December 31, 2015
 
Current
Assets
 
Noncurrent Assets
 
Current
Assets
 
Noncurrent Assets
Amounts related to TCEH's DIP Facility (Note 10)
$
528

 
$
—

 
$
519

 
$
—

Amounts related to TCEH's pre-petition Letter of Credit
Facility (Note 11)
—

 
507

 
—

 
507

Other
5

 
—

 
5

 
—

Total restricted cash
$
533

 
$
507

 
$
524

 
$
507


Trade Accounts Receivable
 
June 30,
2016
 
December 31,
2015
Wholesale and retail trade accounts receivable
$
665

 
$
542

Allowance for uncollectible accounts
(7
)
 
(9
)
Trade accounts receivable — net
$
658

 
$
533


Gross trade accounts receivable at June 30, 2016 and December 31, 2015 included unbilled revenues of $263 million and $231 million, respectively.

Allowance for Uncollectible Accounts Receivable
 
Six Months Ended June 30,
 
2016
 
2015
Allowance for uncollectible accounts receivable at beginning of period
$
9

 
$
15

Increase for bad debt expense
10

 
16

Decrease for account write-offs
(12
)
 
(19
)
Allowance for uncollectible accounts receivable at end of period
$
7

 
$
12



44

Inventories by Major Category
 
June 30,
2016
 
December 31,
2015
Materials and supplies
$
232

 
$
226

Fuel stock
162

 
170

Natural gas in storage
26

 
32

Total inventories
$
420

 
$
428


Other Investments
 
June 30,
2016
 
December 31,
2015
Nuclear plant decommissioning trust
$
966

 
$
918

Land
36

 
36

Miscellaneous other
30

 
30

Total other investments
$
1,032

 
$
984


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 16). The nuclear decommissioning trust fund is not a debtor under the Chapter 11 Cases. A summary of investments in the fund follows:
 
June 30, 2016
 
Cost (a)
 
Unrealized gain
 
Unrealized loss
 
Fair market
value
Debt securities (b)
$
320

 
$
23

 
$
(1
)
 
$
342

Equity securities (c)
302

 
330

 
(8
)
 
624

Total
$
622

 
$
353

 
$
(9
)
 
$
966


 
December 31, 2015
 
Cost (a)
 
Unrealized gain
 
Unrealized loss
 
Fair market
value
Debt securities (b)
$
310

 
$
11

 
$
(2
)
 
$
319

Equity securities (c)
291

 
315

 
(7
)
 
599

Total
$
601

 
$
326

 
$
(9
)
 
$
918

____________
(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 3.57% and 3.68% at June 30, 2016 and December 31, 2015, respectively, and an average maturity of 8 years at both June 30, 2016 and December 31, 2015.
(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, 2016 mature as follows: $133 million in one to five years, $69 million in five to ten years and $140 million after ten years.


45

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,
 
2016
 
2015
 
2016
 
2015
Realized gains
$
(1
)
 
$
1

 
$
—

 
$
1

Realized losses
$
1

 
$
—

 
$
—

 
$
(1
)
Proceeds from sales of securities
$
88

 
$
50

 
$
155

 
$
73

Investments in securities
$
(92
)
 
$
(54
)
 
$
(163
)
 
$
(81
)

Property, Plant and Equipment

At June 30, 2016 and December 31, 2015, property, plant and equipment of $10.537 billion and $9.430 billion, respectively, is stated net of accumulated depreciation and amortization of $4.456 billion and $4.151 billion, respectively.

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.

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, 2016:
 
Nuclear Plant Decommissioning
 
Mining Land Reclamation
 
Other
 
Total
Liability at December 31, 2015
$
508

 
$
215

 
$
107

 
$
830

Additions:
 
 
 
 
 
 
 
Accretion
15

 
11

 
3

 
29

Incremental reclamation costs
—

 
14

 
12

 
26

Reductions:
 
 
 
 
 
 
 
Payments
—

 
(27
)
 
—

 
(27
)
Liability at June 30, 2016
523

 
213

 
122

 
858

Less amounts due currently
—

 
(55
)
 
(1
)
 
(56
)
Noncurrent liability at June 30, 2016
$
523

 
$
158

 
$
121

 
$
802


Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:
 
June 30,
2016
 
December 31,
2015
Uncertain tax positions, including accrued interest
$
39

 
$
40

Retirement plan and other employee benefits
171

 
169

Asset retirement and mining reclamation obligations
802

 
764

Unfavorable purchase and sales contracts
531

 
543

Nuclear decommissioning fund excess over asset retirement obligation (Note 16)
443

 
409

Other
106

 
107

Total other noncurrent liabilities and deferred credits
$
2,092

 
$
2,032


Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $6 million for both the three months ended June 30, 2016 and 2015 and $12 million for both the six months ended June 30, 2016 and 2015. See Note 5 for intangible assets related to favorable purchase and sales contracts.


46

The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:
Year
 
Amount
2016
 
$
24

2017
 
$
24

2018
 
$
24

2019
 
$
24

2020
 
$
24


Fair Value of Debt
 
 
June 30, 2016
 
December 31, 2015
Debt:
 
Carrying Amount
 
Fair
Value
 
Carrying Amount
 
Fair
Value
Borrowings under debtor-in-possession credit facilities (Note 10)
 
$
7,940

 
$
7,906

 
$
6,825

 
$
6,804

Long-term debt not subject to compromise, excluding capital lease obligations (Note 10)
 
$
82

 
$
78

 
$
90

 
$
89


We determine fair value in accordance with accounting standards as discussed in Note 14, and at June 30, 2016, our debt fair value represents Level 2 valuations. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg. The fair value estimates of our pre-petition notes, loans and other debt reported as liabilities subject to compromise have been excluded from the table above. As a result of our ongoing Chapter 11 Cases, obtaining the fair value estimates of our pre-petition debt subject to compromise is impractical, and the fair values will ultimately be decided through the Chapter 11 Cases.

Supplemental Cash Flow Information
 
Six Months Ended June 30,
 
2016
 
2015
Cash payments related to:
 
 
 
Interest paid (a)
$
800

 
$
1,052

Capitalized interest
(6
)
 
(6
)
Interest paid (net of capitalized interest) (a)
$
794

 
$
1,046

Income taxes
$
34

 
$
46

Reorganization items (b)
$
130

 
$
155

Noncash investing and financing activities:
 
 
 
Construction expenditures (c)
$
66

 
$
59

____________
(a)
This amount includes amounts paid for adequate protection.
(b)
Represents cash payments for legal and other consulting services, including amounts paid on behalf of third parties pursuant to contractual obligations approved by the Bankruptcy Court.
(c)
Represents end-of-period accruals for ongoing construction projects.



47

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, 2016 and 2015 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements. Results are impacted by the effects of the Bankruptcy Filing and the application of Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, Reorganizations.

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

Business

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

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


Operating Segments

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

See Note 17 to the Financial Statements for further information regarding reportable business segments.

Significant Activities and Events and Items Influencing Future Performance

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

For additional discussion of the Bankruptcy Filing and its effects, see Note 2 to the Financial Statements.


48

Lamar and Forney Acquisition — In April 2016, Luminant purchased all of the membership interests in La Frontera Holdings, LLC, the indirect owner of two natural gas fueled generation facilities representing nearly 3,000 MW of capacity located in ERCOT, from a subsidiary of NextEra Energy, Inc. The facility in Forney, Texas has a capacity of 1,912 MW and the facility in Paris, Texas has a capacity of 1,076 MW. The aggregate purchase price was approximately $1.313 billion, which included the repayment of approximately $950 million of existing project financing indebtedness, plus approximately $240 million for cash and net working capital subject to final settlement. The purchase price was funded by cash-on-hand and additional borrowings under the TCEH DIP Facility totaling $1.1 billion. After completing the acquisition, we repaid approximately $230 million of borrowings under the TCEH DIP Revolving Credit Facility primarily utilizing cash acquired in the transaction. See Note 3 to the Financial Statements for further discussion of the acquisition.

TCEH Debt Commitment Letter — TCEH has executed a debt commitment letter (the Debt Commitment Letter), dated May 31, 2016, with Deutsche Bank AG New York Branch (DBNY) and Deutsche Bank Securities Inc. (DBSI and, together with DBNY, DB), Barclays Bank PLC (Barclays), Citigroup Global Markets Inc., Citibank N.A., Citicorp USA, Inc., Citicorp North America, Inc. (and any of its affiliates it deems appropriate, Citi), Credit Suisse AG (acting through such of its affiliates and branches it deems appropriate, CS) and Credit Suisse Securities (USA) LLC (acting through such of its affiliates and branches it deems appropriate, CS Securities and together with CS and their respective affiliates, Credit Suisse), Royal Bank of Canada (Royal Bank) and RBC Capital Markets (RBCCM and, together with Royal Bank, RBC), UBS AG, Stamford Branch (UBS Stamford) and UBS Securities LLC (UBSS and, together with UBS Stamford, UBS), and Natixis, New York Branch (Natixis NY and, together with DB, Barclays, Citi, Credit Suisse, RBC and UBS, the Commitment Parties), pursuant to which, subject to the conditions set forth therein, the Commitment Parties committed to provide secured financing consisting of either (1) a senior secured first lien credit facility in an aggregate principal amount of $750 million (the Senior Revolving Credit Facility), a senior secured term loan facility in an aggregate principal amount of $2.85 billion (the Senior Term Loan B Facility) and a senior secured term loan facility in an aggregate principal amount of $650 million (the Senior Term Loan C Facility, and together with the Senior Revolving Credit Facility and Senior Term Loan B Facility, the Senior Facilities), or (2) a senior secured superpriority debtor-in-possession and exit credit agreement consisting of a superpriority senior secured first lien revolving credit facility in an aggregate principal amount of $750 million (the DIP Roll Revolving Credit Facility), a superpriority senior secured term loan facility in an aggregate principal amount of $2.85 billion (the DIP Roll Term Loan B Facility), and a superpriority senior secured term loan facility in an aggregate principal amount of $650 million (the DIP Roll Term Loan C Facility, and together with the DIP Roll Revolving Credit Facility and the DIP Roll Term Loan B Facility, the DIP Roll Facilities), which DIP Roll Facilities will, subject to the conditions set forth in the Debt Commitment Letter, convert to longer term facilities on the Conversion Date (as defined in the Debt Commitment Letter). There can be no assurances that such conditions will be satisfied or waived (if applicable).

The commitments of the Commitment Parties to provide the Senior Facilities or the DIP Roll Facilities, as applicable, are subject to certain conditions set forth in the Debt Commitment Letter. There can be no assurances that such conditions will be satisfied or waived (if applicable).

Extension of EFIH DIP Facility — In January 2016, the EFIH Debtors paid a $14 million extension fee and extended the maturity date of the EFIH DIP Facility to the earlier of (a) December 2016 or (b) the effective date of any reorganization plan of EFIH. The terms of the facility were otherwise unchanged by the extension. We expect to extend or refinance the EFIH DIP Facility before its maturity in December 2016; however, we cannot predict whether any such extension or refinancing would be successful or on favorable terms. See Note 10 to the Financial Statements for discussion of the DIP Facilities.

Overall Hedged Generation Position — Taking together forward wholesale and retail electricity sales with all hedging positions, at June 30, 2016 we had effectively hedged an estimated 94% and 72%, respectively, of the price exposure, on a natural gas equivalent basis, related to our expected generation output for the remainder of 2016 and 2017 (assuming an 8.5 market heat rate), as compared to 94% and 18%, respectively, at December 31, 2015.


49

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, 2016, which for natural gas reflects estimates of electricity generation less amounts under existing wholesale and retail sales contracts and amounts related to hedging positions. On a rolling basis, generally twelve-months, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.
 
Balance 2016
 
2017
$1.00/MMBtu change in natural gas price (a)(b)
$ ~12
 
$ ~115
0.1/MMBtu/MWh change in market heat rate (c)
$ ~1
 
$ ~10
___________
(a)
Balance of 2016 is from August 1, 2016 through December 31, 2016.
(b)
Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally being on the margin 70% to 90% of the time in the ERCOT market (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated). Excludes the impact of economic backdown.
(c)
Based on Houston Ship Channel natural gas prices at June 30, 2016.

Environmental Matters — See Note 12 to Financial Statements for a discussion of greenhouse gas emissions, the CSAPR, regional haze, state-implementation plan and other recent EPA actions as well as related litigation.

Oncor 2008 Rate Review Filing (PUCT Docket No. 35717) — Oncor filed a petition for review with the Texas Supreme Court in February 2015 regarding previous opinions issued by the Texas Third Court of Appeals (Austin Court of Appeals) related to Oncor's June 2008 rate review filing. The issues in the appeal pertain to the Austin Court of Appeals affirming the PUCT's disallowance of certain franchise fees, affirming the PUCT's decision that the Texas Public Utility Regulatory Act (PURA) no longer requires imposition of a rate discount for state colleges and universities and remanding to the PUCT the calculation of the consolidated tax savings adjustment arising out of EFH Corp.'s ability to offset Oncor's taxable income against losses from other investments. The Texas Supreme Court granted the petition for review, and the date for oral arguments has been set for September 2016. There is no deadline for the court to act. If Oncor's appeals efforts are unsuccessful and the proposed consolidated tax savings adjustment is implemented, Oncor estimates that on remand the impact on earnings of the consolidated tax savings adjustment's value could range from zero, as originally determined by the PUCT in Docket No. 35717, to a $135 million loss (after-tax) including interest. Interest accrues at the PUCT approved rate for over-collections, which is 0.18% for 2016. Oncor does not believe that any of the other issues ruled upon by the Austin Court of Appeals would result in a material impact to its results of operations or financial condition.


50


RESULTS OF OPERATIONS

Consolidated Financial Results — Three and Six Months Ended June 30, 2016 Compared to Three and Six Months Ended June 30, 2015

Net loss before income taxes and equity in earnings of unconsolidated subsidiaries by segment for the three and six months ended June 30, 2016 and 2015 are presented below:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
$ Change
 
2016
 
2015
 
$ Change
Competitive Electric segment
$
(501
)
 
$
(321
)
 
$
(180
)
 
$
(837
)
 
$
(1,950
)
 
$
1,113

Corporate and Other
(85
)
 
(103
)
 
18

 
(187
)
 
(477
)
 
290

Net loss before income taxes and equity in earnings of unconsolidated subsidiaries
(586
)
 
(424
)
 
(162
)
 
(1,024
)
 
(2,427
)
 
1,403

Income tax benefit
171

 
137

 
34

 
298

 
537

 
(239
)
Equity in earnings of unconsolidated subsidiaries (net of tax) (Regulated Delivery segment)
85

 
75

 
10

 
147

 
151

 
(4
)
Net loss
$
(330
)
 
$
(212
)
 
$
(118
)
 
$
(579
)
 
$
(1,739
)
 
$
1,160


Consolidated net loss before income taxes and equity in earnings of unconsolidated subsidiaries for EFH Corp. increased by $162 million to $586 million in the three months ended June 30, 2016 compared to the three months ended June 30, 2015. The increase primarily reflected net losses in commodity hedging and trading activities, lower operating revenues and an increase in operating costs, partially offset by lower depreciation and amortization expenses.

Consolidated net loss before income taxes and equity in earnings of unconsolidated subsidiaries for EFH Corp. decreased by $1.403 billion to $1.024 billion in the six months ended June 30, 2016 compared to the six months ended June 30, 2015. The decrease primarily reflected a $700 million noncash impairment of goodwill in 2015, $676 million in noncash impairments of certain long-lived assets in 2015 and a $191 million decrease in interest expense reflecting the payment of post-petition interest related to the EFIH Second Lien Notes in 2015.

See Competitive Electric Segment – Financial Results below for a discussion of significant variances in financial results for the three and six months ended June 30, 2016 when compared to the three and six months ended June 30, 2015. See Note 18 to the Financial Statements for details of other income and deductions. See Note 8 to the Financial Statements for details of interest expense and related charges. See Note 9 to the Financial Statements for details of reorganization items. See Note 6 to the Financial Statements for reconciliation of comparable effective tax rates to the US federal statutory rate.

Non-GAAP Earnings Measures

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


51

Competitive Electric Segment
Revenue, Sales Volume and Customer Count Data
 
Three Months Ended June 30,
 
% Change
 
Six Months Ended June 30,
 
% Change
 
2016
 
2015
 
2016
 
2015
 
Operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Retail electricity revenues:
 
 
 
 
 
 
 
 
 
 
 
Residential
$
628

 
$
674

 
(6.8
)%
 
$
1,181

 
$
1,365

 
(13.5
)%
Business markets
350

 
377

 
(7.2
)%
 
674

 
739

 
(8.8
)%
Total retail electricity revenues
978

 
1,051

 
(6.9
)%
 
1,855

 
2,104

 
(11.8
)%
Wholesale electricity revenues (a)(b)
204

 
152

 
34.2
 %
 
323

 
300

 
7.7
 %
Other operating revenues
51

 
53

 
(3.8
)%
 
105

 
123

 
(14.6
)%
Total operating revenues
$
1,233

 
$
1,256

 
(1.8
)%
 
$
2,283

 
$
2,527

 
(9.7
)%
 
 
 
 
 
 
 
 
 
 
 
 
Sales volumes:
 
 
 
 
 
 
 
 
 
 
 
Retail electricity sales volumes – (GWh):
 
 
 
 
 
 
 
 
 
 
 
Residential
5,033

 
4,990

 
0.9
 %
 
9,261

 
10,098

 
(8.3
)%
Business markets
4,748

 
4,798

 
(1.0
)%
 
8,969

 
9,162

 
(2.1
)%
Total retail electricity
9,781

 
9,788

 
(0.1
)%
 
18,230

 
19,260

 
(5.3
)%
Wholesale electricity sales volumes (b)
8,049

 
5,256

 
53.1
 %
 
13,504

 
10,625

 
27.1
 %
Total sales volumes
17,830

 
15,044

 
18.5
 %
 
31,734

 
29,885

 
6.2
 %
 
 
 
 
 
 
 
 
 
 
 
 
Weather (North Texas average) – percent of normal (c):
 
 
 
 
 
 
 
 
 
 
 
Cooling degree days
95.0
%
 
86.1
%
 
10.3
 %
 
96.1
%
 
87.1
%
 
10.3
 %
Heating degree days
87.9
%
 
95.8
%
 
(8.2
)%
 
81.9
%
 
118.9
%
 
(31.1
)%
 
 
 
 
 
 
 
 
 
 
 
 
Retail customer counts:
 
 
 
 
 
 
 
 
 
 
 
Retail electricity customers (end of period, in thousands) (d):
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 
 
 
 
 
1,483

 
1,495

 
(0.8
)%
Business markets
 
 
 
 
 
 
196

 
204

 
(3.9
)%
Total retail electricity customers
 
 
 
 
 
 
1,679

 
1,699

 
(1.2
)%
____________
(a)
Upon settlement, 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.
(b)
Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.
(c)
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.
(d)
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.


52

Competitive Electric Segment
Production, Purchased Power and Delivery Cost Data
 
Three Months Ended June 30,
 
% Change
 
Six Months Ended June 30,
 
% Change
 
2016
 
2015
 
2016
 
2015
 
Fuel, purchased power costs and delivery fees ($ millions):
 
 
 
 
 
 
 
 
 
 
 
Fuel for nuclear facilities
$
26

 
$
39

 
(33.3
)%
 
$
61

 
$
78

 
(21.8
)%
Fuel for lignite/coal facilities
171

 
184

 
(7.1
)%
 
312

 
324

 
(3.7
)%
Total nuclear and lignite/coal facilities (a)
197

 
223

 
(11.7
)%
 
373

 
402

 
(7.2
)%
Fuel for natural gas facilities and purchased power costs (a)
112

 
60

 
86.7
 %
 
159

 
122

 
30.3
 %
Other costs
32

 
36

 
(11.1
)%
 
68

 
78

 
(12.8
)%
Fuel and purchased power costs
341

 
319

 
6.9
 %
 
600

 
602

 
(0.3
)%
Delivery fees
313

 
327

 
(4.3
)%
 
608

 
657

 
(7.5
)%
Total
$
654

 
$
646

 
1.2
 %
 
$
1,208

 
$
1,259

 
(4.1
)%
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
 
 
 
 
 
 
 
 
 
 
 
Nuclear facilities
$
6.07

 
$
7.47

 
(18.7
)%
 
$
6.29

 
$
7.36

 
(14.5
)%
Lignite/coal facilities (b)
$
20.61

 
$
27.85

 
(26.0
)%
 
$
20.54

 
$
24.26

 
(15.3
)%
Natural gas facilities and purchased power (c)
$
22.92

 
$
50.34

 
(54.5
)%
 
$
26.53

 
$
47.96

 
(44.7
)%
 
 
 
 
 
 
 
 
 
 
 
 
Delivery fees per MWh
$
31.88

 
$
33.21

 
(4.0
)%
 
$
33.19

 
$
33.95

 
(2.2
)%
 
 
 
 
 
 
 
 
 
 
 
 
Production and purchased power volumes (GWh):
 
 
 
 
 
 
 
 
 
 
 
Nuclear facilities
4,373

 
5,239

 
(16.5
)%
 
9,695

 
10,521

 
(7.9
)%
Lignite/coal facilities (d)
9,253

 
9,259

 
(0.1
)%
 
17,235

 
18,057

 
(4.6
)%
Total nuclear and lignite/coal facilities
13,626

 
14,498

 
(6.0
)%
 
26,930

 
28,578

 
(5.8
)%
Natural gas facilities (e)
4,059

 
81

 
—
 %
 
4,086

 
141

 
—
 %
Purchased power (f)
145

 
465

 
(68.8
)%
 
718

 
1,166

 
(38.4
)%
Total energy supply volumes
17,830

 
15,044

 
18.5
 %
 
31,734

 
29,885

 
6.2
 %
 
 
 
 
 
 
 
 
 
 
 
 
Capacity factors:
 
 
 
 
 
 
 
 
 
 
 
Nuclear facilities
87.1
%
 
104.3
%
 
(16.5
)%
 
96.5
%
 
105.3
%
 
(8.4
)%
Lignite/coal facilities (d)
52.8
%
 
52.9
%
 
(0.2
)%
 
49.2
%
 
51.9
%
 
(5.2
)%
Total
60.5
%
 
64.3
%
 
(5.9
)%
 
59.8
%
 
63.8
%
 
(6.3
)%
____________
(a)
See note (a) to the Revenue, Sales Volume and Customer Count Data table on previous page.
(b)
Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs and excludes unrealized amounts as discussed in footnote (a) to the Revenue, Sales Volume and Customer Count Data table on the previous page.
(c)
Excludes volumes related to line loss and power imbalances and unrealized amounts referenced in footnote (a) to the Revenue, Sales Volume and Customer Count Data table on previous page.
(d)
Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal fueled units totaling 5,310 GWh and 4,930 GWh for the three months ended June 30, 2016 and 2015, respectively and 12,030 GWh and 12,090 GWh for the six months ended June 30, 2016 and 2015, respectively.
(e)
The percent changes between the periods presented have been excluded because they are not meaningful.
(f)
Includes amounts related to line loss and power imbalances.


53

Competitive Electric Segment — Financial Results — Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015

The overall $180 million increase in loss before income taxes primarily reflected net losses in commodity hedging and trading activities, lower operating revenues and an increase in operating costs, partially offset by lower depreciation and amortization expenses.

Operating revenues decreased $23 million driven by decreases in retail electricity revenues, partially offset by an increase in wholesale electricity revenues. Retail electricity revenues decreased $73 million driven by a 7% overall average price decline in residential and business markets. Wholesale electricity revenues increased $52 million due to a 2,793 GWh increase in volumes driven by the Lamar and Forney Acquisition in April 2016.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities. Results are primarily related to natural gas and power hedging activity.
 
Three Months Ended June 30,
Net gain (loss) from commodity hedging and trading activities
2016
 
2015
 
Change
Realized net gains
$
95

 
$
49

 
$
46

Unrealized net losses
(213
)
 
(29
)
 
(184
)
Total
$
(118
)
 
$
20

 
$
(138
)

Decreases in operating revenues were offset by a $46 million increase in realized gains during 2016 which reflected higher settled gains due to declining market prices. These gains were primarily related to natural gas positions.

The $184 million increase in unrealized net losses reflected a larger reversal of previously recorded unrealized net gains on settled positions in 2016 and higher unrealized net losses recorded in 2016 due to an increase in forward natural gas and power prices on hedge positions.

The $38 million increase in operating costs reflected higher nuclear maintenance costs due to a spring nuclear outage in 2016 as compared to a fall outage in 2015 and incremental maintenance costs associated with the Lamar and Forney Acquisition.

Depreciation and amortization expenses decreased $55 million, driven by the effect of noncash impairments of certain long-lived assets recorded in 2015, partially offset by incremental depreciation associated with the Lamar and Forney Acquisition.

For the three months ended June 30, 2016, results include $16 million of severance expense, primarily reported in fuel, purchased power and delivery fees and operating costs, associated with certain actions taken to reduce costs related to our mining and lignite/coal generation operations.

Competitive Electric Segment — Financial Results — Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

The overall $1.113 billion decrease in loss before income taxes primarily reflected the noncash impairment of goodwill and the noncash impairments of certain long-lived assets in 2015, partially offset by lower operating revenues. In 2015, a noncash impairment of goodwill totaling $700 million and noncash impairments of certain long-lived assets totaling $676 million were recorded as discussed in Notes 5 and 7 to the Financial Statements.

Operating revenues decreased $244 million driven by decreases in retail electricity revenues. Retail electricity revenues decreased $249 million in 2016 due to a 7% overall average price decline in residential and business markets and a 5% reduction in retail electricity volumes reflecting the effect of milder weather. Wholesale electricity revenues increased $23 million due to a 2,879 GWh increase in volumes driven by the Lamar and Forney Acquisition in April 2016, partially offset by lower average wholesale electricity prices.


54

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities. Results are primarily related to natural gas and power hedging activity.
 
Six Months Ended June 30,
Net gain (loss) from commodity hedging and trading activities
2016
 
2015
 
Change
Realized net gains (losses)
$
200

 
$
51

 
$
149

Unrealized net gains (losses)
(253
)
 
72

 
(325
)
Total
$
(53
)
 
$
123

 
$
(176
)

Decreases in operating revenues were partially offset by a $149 million increase in realized net gains during 2016 which reflected settled gains due to declining market prices. These gains were primarily related to natural gas positions.

The $325 million decrease in net unrealized gains reflected a larger reversal of previously recorded unrealized net gains on settled positions in 2016 and higher unrealized net losses recorded in 2016 due to an increase in forward natural gas and power prices on hedge positions.

The $51 million decrease in fuel, purchased power costs and delivery fees in 2016 was driven by a $49 million decrease in delivery fees and $29 million in lower nuclear and lignite/coal facilities fuel costs, partially offset by a $37 million increase in fuel costs for natural gas facilities, which reflected the Lamar and Forney Acquisition.

The $64 million increase in operating costs reflected higher nuclear maintenance costs due to a spring nuclear outage in 2016 compared to a fall outage in 2015 and incremental maintenance costs associated with the Lamar and Forney Acquisition.

Depreciation and amortization expenses decreased $132 million, driven by the effect of noncash impairments of certain long-lived assets recorded in 2015, partially offset by incremental expense associated with the Lamar and Forney Acquisition.

For the six months ended June 30, 2016, results include $25 million of severance expense, primarily reported in fuel, purchased power and delivery fees and operating costs, associated with certain actions taken to reduce costs related to our mining and lignite/coal generation operations.

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

The table below summarizes the changes in commodity contract assets and liabilities for the six months ended June 30, 2016 and 2015. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $253 million in unrealized net losses in 2016 and $72 million in unrealized net gains in 2015 arising from mark-to-market accounting for positions in the commodity contract portfolio.
 
Six Months Ended June 30,
 
2016
 
2015
Commodity contract net asset at beginning of period
$
271

 
$
180

Settlements/termination of positions (a)
(208
)
 
(79
)
Changes in fair value of positions in the portfolio (b)
(45
)
 
151

Other activity (c)
(26
)
 
(11
)
Commodity contract net asset (liability) at end of period
$
(8
)
 
$
241

____________
(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 fair value of acquired commodity contracts as of the date of the Lamar and Forney Acquisition (see Note 3 to the Financial Statements). Also includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold.


55

Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at June 30, 2016, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
 
 
Maturity dates of unrealized commodity contract net liability at
June 30, 2016
Source of fair value
 
Less than
1 year
 
1-3 years
 
4-5 years
 
Total
Prices actively quoted
 
$
80

 
$
(10
)
 
$
1

 
$
71

Prices provided by other external sources
 
(52
)
 
(18
)
 
—

 
(70
)
Prices based on models
 
29

 
(16
)
 
(22
)
 
(9
)
Total
 
$
57

 
$
(44
)
 
$
(21
)
 
$
(8
)

Regulated Delivery Segment — Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015

Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) increased $10 million to $85 million in 2016. The increase in equity earnings of Oncor primarily reflected higher distribution base revenues driven by warmer weather conditions and higher transmission base revenues due to increased investment, partially offset by higher income taxes. See Note 4 to the Financial Statements.

Regulated Delivery Segment — Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) decreased $4 million to $147 million in 2016. The decrease in equity earnings of Oncor primarily reflected lower distribution base revenues and higher depreciation and amortization expense, partially offset by higher transmission base revenues. See Note 4 to the Financial Statements.

Corporate and Other Activity — Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015

Net loss before income taxes and equity in earnings of unconsolidated subsidiaries from Corporate and Other activities decreased $18 million in 2016 to $85 million. The change primarily reflects:

•
a $9 million decrease in SG&A expenses primarily due to Sponsor Group management fees accrued in 2015 (see Note 16 to the Financial Statements), and
•
a $6 million decrease in the Corporate and Other portion of reorganization items in 2016.

Corporate and Other Activity — Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

Net loss before income taxes and equity in earnings of unconsolidated subsidiaries from Corporate and Other activities decreased $290 million in 2016 to $187 million. The change primarily reflects:

•
a $235 million decrease in interest expense reflecting the payment of post-petition interest related to the EFIH Second Lien Notes in 2015 (see Note 11 to the Financial Statements);
•
a $33 million decrease in SG&A expenses primarily due to Sponsor Group management fees accrued in 2015 (see Note 16 to the Financial Statements) and lower technology costs and functional costs for support groups, and
•
a $23 million decrease in the Corporate and Other portion of reorganization items in 2016.


56


FINANCIAL CONDITION

Cash Flows — Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015 — Cash used in operating activities totaled $512 million and $572 million in 2016 and 2015, respectively. The decrease in cash used of $60 million was primarily driven by $252 million in lower cash interest payments as a result of the repayment of certain EFIH Second Lien Notes in 2015 (see Note 11 to the Financial Statements), partially offset by a $179 million decrease in cash provided by 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 loss by $48 million and $74 million for the six months ended June 30, 2016 and 2015, respectively. The difference primarily represents amortization of nuclear fuel, which is reported as fuel costs in the condensed statements of consolidated loss consistent with industry practice.

Cash provided by financing activities totaled $1.088 billion in 2016 compared to cash used in financing activities of $484 million in 2015. Activity in 2016 reflected $1.115 billion in net borrowings under the TCEH DIP Facility, including $870 million in net borrowings to fund the Lamar and Forney Acquisition (see Note 3 to the Financial Statements). Activity in 2016 also reflected $14 million in fees related to the extension of the EFIH DIP Facility and $13 million in debt repayments. Activity in 2015 reflected the repayment of $445 million principal amount of EFIH Second Lien Notes and $28 million in fees related to the repayment (see Note 11 to the Financial Statements).

Cash used in investing activities totaled $1.534 billion and $209 million in 2016 and 2015, respectively. Cash used in 2016 reflected payments of $1.343 billion related to the Lamar and Forney Acquisition net of cash acquired (see Note 3 to the Financial Statements).

Debt Activity — See Notes 10 and 11 to the Financial Statements for details of debtor-in-possession borrowing facilities and pre-petition debt.

Available Liquidity — The following table summarizes changes in available liquidity for the six months ended June 30, 2016:
 
Available Liquidity
 
June 30, 2016
 
December 31, 2015
 
Change
Cash and cash equivalents – EFH Corp. and other
$
488

 
$
532

 
$
(44
)
Cash and cash equivalents – EFIH
275

 
354

 
(79
)
Cash and cash equivalents – TCEH (a)
565

 
1,400

 
(835
)
Total cash and cash equivalents
1,328

 
2,286

 
(958
)
TCEH DIP Revolving Credit Facility (b)
835

 
1,950

 
(1,115
)
Total liquidity (b)
$
2,163

 
$
4,236

 
$
(2,073
)
___________
(a)
Cash and cash equivalents at June 30, 2016 and December 31, 2015 exclude $1.035 billion and $1.026 billion, respectively, of restricted cash held for letter of credit support. The June 30, 2016 restricted cash balance includes $507 million under the TCEH pre-petition Letter of Credit Facility and $528 million under the TCEH DIP Facility.
(b)
Pursuant to an order of the Bankruptcy Court, the TCEH Debtors may not have more than $1.650 billion of cash borrowings outstanding under the TCEH DIP Revolving Credit Facility without written consent of the TCEH committee of unsecured creditors and the ad hoc group of TCEH unsecured noteholders or further order of the Bankruptcy Court.

The decrease in available liquidity of $2.073 billion in the six months ended June 30, 2016 compared to December 31, 2015 was primarily driven by $1.115 billion in net borrowings under the TCEH DIP Facility, including $870 million in net borrowings to fund the Lamar and Forney Acquisition (see Note 3 to the Financial Statements), $800 million in cash interest payments (including adequate protection payments), $180 million in capital expenditures (including nuclear fuel purchases) and $130 million of cash used to pay for reorganization expenses, partially offset by $86 million of cash received in distributions from Oncor Holdings.

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


57

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

Distributions of Earnings from Oncor Holdings and Related Considerations — Oncor Holdings' distributions of earnings to us totaled $86 million and $120 million for the six months ended June 30, 2016 and 2015, respectively. In July 2016, Oncor Holdings' board of directors declared a cash distribution expected to be up to approximately $49 million with the exact amount to be determined by Oncor's management. See Note 4 to the Financial Statements for discussion of limitations on amounts Oncor can distribute to its members.

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

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 10 to the Financial Statements for discussion of the TCEH DIP Facility.

At June 30, 2016, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

•
$23 million in cash has been posted with counterparties as compared to $6 million posted at December 31, 2015;
•
$36 million in cash has been received from counterparties as compared to $152 million received at December 31, 2015;
•
$386 million in letters of credit have been posted with counterparties as compared to $230 million posted at December 31, 2015, and
•
$6 million in letters of credit have been received from counterparties as compared to $3 million received at December 31, 2015.

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

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

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

Income Tax Payments — In the next twelve months, income tax payments related to Texas margin tax are expected to total approximately $35 million, and no payments or refunds of federal income taxes are expected. Income tax payments totaled $34 million and $46 million (all of which related to Texas Margin tax) for the six months ended June 30, 2016 and 2015, respectively.


58

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. The ratio was 1.79 to 1.00 at June 30, 2016, 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, 2016 totaled $699 million and $1.712 billion, respectively. See Exhibit 99(b) for a reconciliation of TCEH's net income (loss) to Consolidated EBITDA. The EFIH DIP Facility also includes a minimum liquidity covenant pursuant to which EFIH cannot allow unrestricted cash (as defined in the EFIH DIP Facility) to be less than $150 million. EFIH is in compliance with this covenant. Based on the current and projected liquidity requirements of EFIH, EFIH's liquidity may fall beneath the amount required by the minimum liquidity covenant in the EFIH DIP Facility, and if this were to occur, it would be in default of the EFIH DIP Facility unless it obtains a waiver from the required lenders under such facility. However, such a default would not constitute a cross default under the TCEH DIP Facility.

See Note 10 to the Financial Statements for discussion of other covenants related to the DIP Facilities.

Collateral Support Obligations — The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In June 2014, the RCT agreed to a collateral bond from TCEH of up to $1.1 billion to support its 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 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.

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, 2016, TCEH posted letters of credit in the amount of $55 million, which is subject to adjustments.

ERCOT has rules in place to assure adequate creditworthiness of parties that participate in the day-ahead, real-time and congestion revenue rights markets operated by ERCOT. Under these rules, TCEH has posted collateral support, in the form of letters of credit, totaling $85 million at June 30, 2016 (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.

Guarantees — See Note 12 to the Financial Statements for discussion of guarantees.


OFF–BALANCE SHEET ARRANGEMENTS

See Notes 4 and 12 to the Financial Statements regarding VIEs and guarantees, respectively.



59

COMMITMENTS AND CONTINGENCIES

See Note 12 to the Financial Statements for discussion of commitments and contingencies.


CHANGES IN ACCOUNTING STANDARDS

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


Item 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.

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

Commodity Price Risk

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

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

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


60

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

VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income, based on a 95% confidence level and an assumed holding period of 60 days.
 
June 30, 2016
 
December 31, 2015
Month-end average MtM VaR:
$
63

 
$
68

Month-end high MtM VaR:
$
118

 
$
97

Month-end low MtM VaR:
$
30

 
$
49


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 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, based on a 95% confidence level and an assumed holding period of 60 days.
 
June 30, 2016
 
December 31, 2015
Month-end average EaR:
$
39

 
$
45

Month-end high EaR:
$
92

 
$
92

Month-end low EaR:
$
7

 
$
26


The increase in the month-end high MtM VaR risk measure reflected increased commodity positions, higher natural gas prices and increased price volatility during the second quarter of 2016.

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 collateral) arising from commodity contracts and hedging and trading activities totaled $629 million at June 30, 2016. The components of this exposure are discussed in more detail below.

Assets subject to credit risk at June 30, 2016 include $461 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $52 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.


61

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 marketing companies. At June 30, 2016, the exposure to credit risk from these counterparties totaled $168 million consisting of accounts receivable of $82 million and net asset positions related to commodity contracts of $86 million, after taking into account the netting provisions of the master agreements described above, but before taking into account $34 million in collateral (cash, letters of credit and other credit support). The net exposure (after collateral) of $134 million decreased $80 million in the six months ended June 30, 2016.

Of this $134 million net exposure, 93% 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. 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, 2016. This credit exposure largely represents wholesale trade accounts receivable and net asset positions related to commodity contracts and hedging and trading activities 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 15 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
$
157

 
$
33

 
$
124

Below investment grade or no rating
11

 
1

 
10

Totals
$
168

 
$
34

 
$
134

Investment grade
93.5
%
 
 
 
92.5
%
Below investment grade or no rating
6.5
%
 
 
 
7.5
%

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 34%, 29% and 17% of the $134 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.


62

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 2015 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:

•
the fact that the TCEH Debtors (and the Contributed EFH Debtors) are likely to emerge from the Chapter 11 Cases prior to the EFH Debtors emerging from the Chapter 11 Cases, and, as a result, the companies will no longer be affiliated entities;
•
our ability to obtain the requisite vote from the applicable stakeholders confirming acceptance of the plan of reorganization and the Bankruptcy Court confirming the plan of reorganization;
•
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;
•
our ability to consummate the transactions contemplated by the Merger Agreement, including obtaining the applicable regulatory approvals contemplated thereunder;
•
the filing of an alternative plan of reorganization by one or more creditors of the Debtors;
•
the breach by one or more of our counterparties under the Plan Support Agreement;
•
the effectiveness of the overall restructuring activities pursuant to the Chapter 11 Cases, including the Plan of Reorganization, and any additional strategies we employ to address our liquidity and capital resources;
•
the extent to which the Chapter 11 Cases cause customers, suppliers and others with whom we have commercial relationships to lose confidence in us, which may make it more difficult for us to obtain and maintain such commercial relationships on competitive terms;
•
difficulties we may face in retaining and motivating our key employees through the bankruptcy process, and difficulties we may face in attracting new employees;
•
the significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations;
•
our ability to remain in compliance with the requirements of the DIP Facilities, particularly the liquidity covenant contained in the EFIH 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 and related costs of the Chapter 11 Cases;
•
the actions and decisions of regulatory authorities relative to any plan of reorganization;
•
restrictions on our operations due to the terms of our debt agreements, including the DIP Facilities, and restrictions imposed by the Bankruptcy Court;
•
our ability to obtain any required regulatory consent necessary to implement any Chapter 11 plan of reorganization;
•
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;
•
prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the FERC, 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;
◦
allowed rates of return;
◦
permitted capital structure;
◦
industry, market and rate structure;
◦
purchased power and recovery of investments;

63

◦
operations of nuclear generation facilities;
◦
operations of fossil fueled generation facilities;
◦
operations of mines;
◦
self-bonding requirements;
◦
acquisition and disposal of assets and facilities;
◦
development, construction and operation of facilities;
◦
decommissioning costs;
◦
present or prospective wholesale and retail competition;
◦
changes in tax laws and policies;
◦
changes in and compliance with environmental and safety laws and policies, including the CSAPR, the MATS, regional haze program implementation and greenhouse gas and other climate change initiatives, and
◦
clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith;
•
legal and administrative proceedings and settlements, including the legal proceedings arising out of the Chapter 11 Cases;
•
general industry trends;
•
economic conditions, including the impact of an economic downturn;
•
our ability to collect trade receivables from counterparties;
•
our ability to attract and retain profitable customers;
•
our ability to profitably serve our customers;
•
restrictions on competitive retail pricing;
•
changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;
•
changes in prices of transportation of natural gas, coal, fuel oil and other refined products;
•
changes in the ability of vendors to provide or deliver commodities as needed;
•
changes in market heat rates in the ERCOT electricity market;
•
our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;
•
weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, wars or terrorist or cyber security threats or activities;
•
population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT;
•
access to adequate transmission facilities to meet changing demands;
•
changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;
•
changes in operating expenses, liquidity needs and capital expenditures;
•
commercial bank market and capital market conditions and the potential impact of disruptions in US and international credit markets;
•
access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets;
•
our ability to generate sufficient cash flow to make interest or adequate protection payments, or refinance, our debt instruments, including the DIP Facilities;
•
competition for new energy development and other business opportunities;
•
inability of various counterparties to meet their obligations with respect to our financial instruments;
•
changes in technology (including large scale electricity storage) used by and services offered by us;
•
changes in electricity transmission that allow additional electricity generation to compete with our generation assets;
•
significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur;
•
changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure under ERISA;
•
hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards, and
•
actions by credit rating agencies.

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


64

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.


Item 4.
CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect at the end of the current period included in this quarterly report on Form 10-Q. Based on the evaluation performed, our principal executive officer and principal financial officer concluded that the disclosure controls and procedures were effective. During the most recent fiscal quarter covered by this quarterly report, there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


65


PART II. OTHER INFORMATION

Item 1.
LEGAL PROCEEDINGS

Reference is made to the discussion in Note 12 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 2015 Form 10-K and Part II, Item 1A. Risk Factors in our Form 10-Q for the period ended March 31, 2016, except for the information disclosed elsewhere in this quarterly report on Form 10-Q that provides factual updates to risk factors contained in our 2015 Form 10-K and our Form 10-Q for the period ended March 31, 2016. 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. 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.


Item 6.
EXHIBITS

(a)
Exhibits filed or furnished as part of Part II are:
Exhibits
 
Previously Filed With File Number*
 
As
Exhibit
 
 
 
 
 
 
 
 
 
 
 
 
 
(2)
 
Merger Agreement
 
 
 
 
 
 
 
 
 
2(a)
 
1-12833
Form 8-K (filed
July 29, 2016)
 
10(b)
 
—
 
Merger Agreement
 
 
 
 
 
 
 
 
 
(3(i))
 
Articles of Incorporation
 
 
 
 
 
 
 
 
 
3(a)
 
1-12833
Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)
 
3(a)
 
—
 
Restated Certificate of Formation of Energy Future Holdings Corp.
 
 
 
 
 
 
 
 
 
(3(ii))
 
By-laws
 
 
 
 
 
 
 
 
 
3(b)
 
1-12833
Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)
 
3(b)
 
—
 
Amended and Restated Bylaws of Energy Future Holdings Corp.
 
 
 
 
 
 
 
 
 
(10)
 
Material Contracts
 
 
 
 
 
 
 
 
 
10 (a)
 
1-12833
Form 8-K (filed
July 29, 2016)
 
10(a)
 
—
 
Plan Support Agreement
 
 
 
 
 
 
 
 
 

66

Exhibits
 
Previously Filed With File Number*
 
As
Exhibit
 
 
 
 
(31)
 
Rule 13a - 14(a)/15d-14(a) Certifications
 
 
 
 
 
 
 
 
 
31(a)
 
 
 
 
 
—
 
Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
 
31(b)
 
 
 
 
 
—
 
Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
 
(32)
 
Section 1350 Certifications
 
 
 
 
 
 
 
 
 
32(a)
 
 
 
 
 
—
 
Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
 
32(b)
 
 
 
 
 
—
 
Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
 
(95)
 
Mine Safety Disclosures
 
 
 
 
 
 
 
 
 
95(a)
 
 
 
 
 
—
 
Mine Safety Disclosures
 
 
 
 
 
 
 
 
 
(99)
 
Additional Exhibits
 
 
 
 
 
 
 
 
 
99(a)
 
 
 
 
 
—
 
Condensed Statement of Consolidated Loss – Twelve Months Ended June 30, 2016.
 
 
 
 
 
 
 
 
 
99(b)
 
 
 
 
 
—
 
Texas Competitive Electric Holdings Company LLC Consolidated EBITDA reconciliation for the six and twelve months ended June 30, 2016 and 2015
99(c)
 
1-12833
Form 8-K (filed
May 11, 2016)
 
99.1
 
—
 
Plan of Reorganization
 
 
 
 
 
 
 
 
 
99(d)
 
1-12833
Form 8-K (filed
May 11, 2016)
 
99.2
 
—
 
Disclosure Statement
 
 
 
 
 
 
 
 
 
99(e)
 
1-12833
Form 8-K (filed
June 1, 2016)
 
99.1
 
—
 
Debt Commitment Letter
 
 
 
 
 
 
 
 
 
 
 
XBRL Data Files
 
 
 
 
 
 
 
 
 
101.INS
 
 
 
 
 
—
 
XBRL Instance Document
 
 
 
 
 
 
 
 
 
101.SCH
 
 
 
 
 
—
 
XBRL Taxonomy Extension Schema Document
 
 
 
 
 
 
 
 
 
101.CAL
 
 
 
 
 
—
 
XBRL Taxonomy Extension Calculation Document
 
 
 
 
 
 
 
 
 
101.DEF
 
 
 
 
 
—
 
XBRL Taxonomy Extension Definition Document
 
 
 
 
 
 
 
 
 
101.LAB
 
 
 
 
 
—
 
XBRL Taxonomy Extension Labels Document
 
 
 
 
 
 
 
 
 
101.PRE
 
 
 
 
 
—
 
XBRL Taxonomy Extension Presentation Document
____________________
*
Incorporated herein by reference

67

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 Holdings Corp.
 
 
 
 
 
 
 
By:
 
/s/ TERRY L. NUTT
 
 
Name:
 
Terry L. Nutt
 
 
Title:
 
Senior Vice President and Controller
 
 
 
 
(Principal Accounting Officer)
 

Date: August 2, 2016



68

Energy Future Holdings Corp /TX/ Reports