10-Q 1 efh-3312015x10q.htm FORM 10-Q EFH-3.31.2015-10Q


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 MARCH 31, 2015

— OR —

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


Commission File Number 1-12833


Energy Future Holdings Corp.

(Exact name of registrant as specified in its charter)

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

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 May 7, 2015, 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 5.
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.
2014 Form 10-K
 
EFH Corp.'s Annual Report on Form 10-K for the year ended December 31, 2014
 
 
 
CAIR
 
Clean Air Interstate Rule
 
 
 
Chapter 11 Cases
 
Cases being heard in the US Bankruptcy Court for the District of Delaware (Bankruptcy Court) concerning voluntary petitions for relief under Chapter 11 of the US Bankruptcy Code (Bankruptcy Code) filed on April 29, 2014 by the Debtors
 
 
 
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 TCEH's debtor-in-possession financing and EFIH's debtor-in-possession financing. See Note 9 to the Financial Statements.
 
 
 
Debtors
 
EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH, but excluding the Oncor Ring-Fenced Entities
 
 
 
Disclosure Statement
 
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 on April 14, 2015, as it may be amended, modified or supplemented from time to time
 
 
 
D.C. Circuit Court
 
US Court of Appeals for the District of Columbia Circuit
 
 
 
EBITDA
 
earnings (net income) before interest expense, income taxes, depreciation and amortization
 
 
 
EFCH
 
Energy Future Competitive Holdings Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context
 
 
 
EFH Corp.
 
Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context, whose major subsidiaries include TCEH and Oncor
 
 
 
EFIH
 
Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings
 
 
 
EFIH Debtors
 
EFIH and EFIH Finance
 
 
 
EFIH Finance
 
EFIH Finance Inc., a direct, wholly owned subsidiary of EFIH, formed for the sole purpose of serving as co-issuer with EFIH of certain debt securities
 
 
 
EFIH First Lien Notes
 
Refers, collectively, to 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 9.
 
 
 
EFIH PIK Notes
 
EFIH's $1.566 billion principal amount of 11.25%/12.25% Senior Toggle Notes.
 
 
 
EFIH Second Lien Notes
 
Refers, collectively, to 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.
 
 
 

ii

EPA
 
US Environmental Protection Agency
 
 
 
ERCOT
 
Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
 
 
 
ERISA
 
Employee Retirement Income Security Act of 1974, as amended
 
 
 
Federal and State Income Tax Allocation Agreements
 
EFH Corp. and certain of its subsidiaries (including EFCH, EFIH and TCEH, but not including Oncor Holdings and Oncor) are parties to a Federal and State Income Tax Allocation Agreement, executed on May 15, 2012 but effective as of January 1, 2010. EFH Corp., Oncor Holdings, Oncor, Oncor's third-party minority investor, and Oncor Management Investment LLC are parties to a separate Federal and State Income Tax Allocation Agreement dated November 5, 2008. See Management's Discussion and Analysis, under Financial Condition.
 
 
 
Fifth Circuit Court
 
US Court of Appeals for the Fifth Circuit
 
 
 
GAAP
 
generally accepted accounting principles
 
 
 
GWh
 
gigawatt-hours
 
 
 
ICE
 
the IntercontinentalExchange, an electronic commodity derivative exchange
 
 
 
IRS
 
US Internal Revenue Service
 
 
 
LIBOR
 
London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
 
 
 
Luminant
 
subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas
 
 
 
market heat rate
 
Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.
 
 
 
Merger
 
the transaction referred to in the Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp., which was completed on October 10, 2007
 
 
 
MMBtu
 
million British thermal units
 
 
 
MW
 
megawatts
 
 
 
MWh
 
megawatt-hours
 
 
 
NOX
 
nitrogen oxide
 
 
 
NRC
 
US Nuclear Regulatory Commission
 
 
 
NYMEX
 
the New York Mercantile Exchange, a commodity derivatives exchange
 
 
 
Oncor
 
Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities
 
 
 
Oncor Holdings
 
Oncor Electric Delivery Holdings Company LLC, a direct, wholly owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context
 
 
 
Oncor Ring-Fenced Entities
 
Oncor Holdings and its direct and indirect subsidiaries, including Oncor
 
 
 
OPEB
 
postretirement employee benefits other than pensions
 
 
 
Petition Date
 
April 29, 2014, the date the Debtors made the Bankruptcy Filing
 
 
 

iii

Plan of Reorganization
 
Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code filed by the Debtors with the Bankruptcy Court on April 14, 2015, as it may be amended, modified or supplemented from time to time

 
 
 
PUCT
 
Public Utility Commission of Texas
 
 
 
purchase accounting
 
The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or "purchase price" of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
 
 
 
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
 
 
 
SO2
 
sulfur dioxide
 
 
 
Sponsor Group
 
Refers, collectively, to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Global, LLC (together with its affiliates, TPG) and GS Capital Partners, an affiliate of Goldman, Sachs & Co., that have an ownership interest in Texas Holdings.
 
 
 
TCEH
 
Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy market activities, and whose major subsidiaries include Luminant and TXU Energy
 
 
 
TCEH Debtors
 
EFCH, TCEH and the subsidiaries of TCEH that are Debtors in the Chapter 11 Cases
 
 
 
TCEH DIP Facility
 
TCEH's $3.375 billion debtor-in-possession financing facility approved by the Bankruptcy Court in June 2014 (see Note 9 to the Financial Statements)

 
 
 
TCEH Finance
 
TCEH Finance, Inc., a direct, wholly owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities
 
 
 
TCEH Senior Notes
 
Refers, collectively, to TCEH's and TCEH Finance's 10.25% Senior Notes and 10.25% Senior Notes, Series B (collectively, TCEH 10.25% Notes) and TCEH's and TCEH Finance's 10.50%/11.25% Senior Toggle Notes (TCEH Toggle Notes) with a total principal amount of $4.874 billion.
 
 
 
TCEH Senior Secured Facilities
 
Refers, collectively, to the TCEH First Lien Term Loan Facilities, TCEH First Lien Revolving Credit Facility and TCEH First Lien Letter of Credit Facility with a total principal amount of $22.616 billion.
 
 
 
TCEH Senior Secured Notes
 
TCEH's and TCEH Finance's $1.750 billion principal amount of 11.5% First Lien Senior Secured Notes
 
 
 
TCEH Senior Secured Second Lien Notes
 
Refers, collectively, to TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes and TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes, Series B with a total principal amount of $1.571 billion.
 
 
 
TCEQ
 
Texas Commission on Environmental Quality
 
 
 
Texas Holdings
 
Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group, that owns substantially all of the common stock of EFH Corp.
 
 
 
Texas Holdings Group
 
Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities
 
 
 

iv

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 INCOME (LOSS)
(Unaudited)
 
Three Months Ended March 31,
 
2015
 
2014
 
(millions of dollars)
Operating revenues
$
1,272

 
$
1,517

Fuel, purchased power costs and delivery fees
(613
)
 
(732
)
Net gain (loss) from commodity hedging and trading activities
103

 
(219
)
Operating costs
(193
)
 
(214
)
Depreciation and amortization
(218
)
 
(330
)
Selling, general and administrative expenses
(179
)
 
(218
)
Impairment of goodwill (Note 4)
(700
)
 
—

Impairment of long-lived assets (Note 6)
(676
)
 
—

Other income (Note 17)
8

 
9

Other deductions (Note 17)
(60
)
 
—

Interest income
—

 
1

Interest expense and related charges (Note 7)
(609
)
 
(863
)
Reorganization items (Note 8)
(138
)
 
—

Loss before income taxes and equity in earnings of unconsolidated subsidiaries
(2,003
)
 
(1,049
)
Income tax benefit (Note 5)
401

 
360

Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 3)
75

 
80

Net loss
$
(1,527
)
 
$
(609
)

See Notes to the Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Unaudited)
 
Three Months Ended March 31,
 
2015
 
2014
 
(millions of dollars)
Net loss
$
(1,527
)
 
$
(609
)
Other comprehensive income (loss), net of tax effects:
 
 
 
Effects related to pension and other retirement benefit obligations (net of tax benefit of $— and $1)
(2
)
 
(1
)
Cash flow hedges derivative value net loss related to hedged transactions recognized during the period (net of tax benefit of $— in all periods)
1

 
—

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

 
—

Total other comprehensive income (loss)
—

 
(1
)
Comprehensive loss
$
(1,527
)
 
$
(610
)

See Notes to the Financial Statements.

1


ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
 
Three Months Ended March 31,
 
2015
 
2014
 
(millions of dollars)
Cash flows — operating activities:
 
 
 
Net loss
$
(1,527
)
 
$
(609
)
Adjustments to reconcile net loss to cash used in operating activities:
 
 
 
Depreciation and amortization
254

 
371

Deferred income tax benefit, net
(339
)
 
(310
)
Impairment of goodwill (Note 4)
700

 
—

Impairment of long-lived assets (Note 6)
676

 
—

Contract rejection claims (Note 8)
32

 
—

Fees paid on EFIH Second Lien Notes repayment (Note 10) (reported as financing activities)
28

 
—

Unrealized net (gain) loss from mark-to-market valuations of commodity positions
(102
)
 
250

Unrealized net (gain) from mark-to-market valuations of interest rate swaps (Note 7)
—

 
(65
)
Interest expense on toggle notes payable in additional principal (Note 7)
—

 
49

Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 7)
—

 
55

Equity in earnings of unconsolidated subsidiaries
(75
)
 
(80
)
Distributions of earnings from unconsolidated subsidiaries
74

 
37

Impairment of intangible assets (Note 4)
59

 
—

Other, net
18

 
16

Changes in operating assets and liabilities:
 
 
 
Margin deposits, net
79

 
(127
)
Accrued interest
(3
)
 
210

Other operating assets and liabilities, including liabilities subject to compromise
(281
)
 
(228
)
Cash used in operating activities
(407
)
 
(431
)
Cash flows — financing activities:
 
 
 
Repayments/repurchases of debt (Notes 9 and 10)
(454
)
 
(191
)
Fees paid on EFIH Second Lien Notes repayment (Note 10)
(28
)
 
—

Other, net
(1
)
 
1

Cash used in financing activities
(483
)
 
(190
)
Cash flows — investing activities:
 
 
 
Capital expenditures
(121
)
 
(119
)
Nuclear fuel purchases
(5
)
 
(26
)
Changes in restricted cash
28

 
285

Proceeds from sales of nuclear decommissioning trust fund securities
23

 
33

Investments in nuclear decommissioning trust fund securities
(27
)
 
(37
)
Other, net
1

 
1

Cash provided by (used in) investing activities
(101
)
 
137

 
 
 
 
Net change in cash and cash equivalents
(991
)
 
(484
)
Cash and cash equivalents — beginning balance
3,428

 
1,217

Cash and cash equivalents — ending balance
$
2,437

 
$
733


See Notes to the Financial Statements.

2


ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
March 31,
2015
 
December 31,
2014
 
(millions of dollars)
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
2,437

 
$
3,428

Restricted cash (Note 17)
6

 
6

Trade accounts receivable — net (Note 17)
539

 
589

Inventories (Note 17)
470

 
468

Commodity and other derivative contractual assets (Note 14)
466

 
492

Other current assets
88

 
100

Total current assets
4,006

 
5,083

Restricted cash (Note 17)
873

 
901

Receivable from unconsolidated subsidiary (Note 15)
47

 
47

Investment in unconsolidated subsidiary (Note 3)
6,060

 
6,058

Other investments (Note 17)
1,007

 
995

Property, plant and equipment — net (Note 17)
11,590

 
12,397

Goodwill (Note 4)
1,652

 
2,352

Identifiable intangible assets — net (Note 4)
1,199

 
1,315

Commodity and other derivative contractual assets (Note 14)
18

 
5

Other noncurrent assets
96

 
95

Total assets
$
26,548

 
$
29,248

LIABILITIES AND EQUITY
Current liabilities:
 
 
 
Long-term debt due currently (Note 9)
$
36

 
$
39

Trade accounts payable
304

 
406

Net payables due to unconsolidated subsidiary (Note 15)
178

 
237

Commodity and other derivative contractual liabilities (Note 14)
202

 
316

Margin deposits related to commodity derivatives
97

 
26

Accumulated deferred income taxes
136

 
135

Accrued taxes
94

 
157

Accrued interest (Notes 7 and 10)
115

 
119

Other current liabilities
292

 
360

Total current liabilities
1,454

 
1,795

Borrowings under debtor-in-possession credit facilities (Note 9)
6,825

 
6,825

Long-term debt, less amounts due currently (Note 9)
121

 
128

Liabilities subject to compromise (Note 10)
36,935

 
37,432

Commodity and other derivative contractual liabilities (Note 14)
2

 
1

Accumulated deferred income taxes
362

 
713

Other noncurrent liabilities and deferred credits (Note 17)
2,099

 
2,077

Total liabilities
47,798

 
48,971

Commitments and Contingencies (Note 11)


 


Shareholders' equity (Note 12)
(21,250
)
 
(19,723
)
Total liabilities and equity
$
26,548

 
$
29,248


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 trading activities, and retail electricity operations. TCEH is a wholly owned subsidiary of EFCH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Oncor Holdings, a holding company that holds an approximate 80% equity interest in Oncor, is a wholly owned subsidiary of EFIH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor Holdings and its subsidiaries (the Oncor Ring-Fenced Entities) are not consolidated in EFH Corp.'s financial statements in accordance with consolidation accounting standards related to variable interest entities (VIEs) (see Note 3).

Various ring-fencing measures have been taken to enhance the credit quality of Oncor. Such measures include, among other things: the sale in November 2008 of a 19.75% equity interest in Oncor to Texas Transmission 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); maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor's board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or contractual obligations of any member of the Texas Holdings Group. Moreover, Oncor's operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.

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

We have two reportable segments: the Competitive Electric segment, consisting largely of TCEH, and the Regulated Delivery segment, consisting largely of our investment in Oncor. See Note 16 for further information concerning reportable business segments.

Bankruptcy Filing

On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities (collectively, the Debtors), filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). On April 14, 2015, the Debtors filed with the Bankruptcy Court the Plan of Reorganization and the Disclosure Statement. See Note 2 for further discussion regarding the Chapter 11 Cases and our recent filing of the Plan of Reorganization and the Disclosure Statement.


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 (ASC) 852, Reorganizations. During the pendency of the Chapter 11 Cases, the Debtors will operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. ASC 852 applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. See Notes 8 and 10 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 3). Adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in our 2014 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

Use of Estimates

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

Changes in Accounting Standards

In April 2014, the FASB issued ASU No. 2014-08, Presentation of Financial Statements (Topic 205) and Property Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which changes the requirements for reporting discontinued operations. The ASU states that a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity's operations and financial results when the component of an entity or group of components of an entity meets the criteria to be classified as held for sale, is disposed of by sale, or is disposed of other than by sale. The amendments in this ASU also require additional disclosures about discontinued operations. ASU 2014-08 is effective for the Company for the first quarter of 2015. This new requirement is relevant to our presentation of the equity method investment in Oncor, which has been proposed for sale within the Chapter 11 Cases. The new guidance eliminated a scope exception previously applicable to equity method investments, resulting in the requirement of further analysis of the presentation of the Oncor equity method investment. Based on our analysis, ASU 2014-08 will not materially affect our results of operations, financial position, or cash flows, until a plan of sale of the Oncor investment is approved by the Bankruptcy Court, at which time presentation as discontinued operations may be appropriate.

In February 2015 the FASB issued Accounting Standards Update 2015-02 (ASU 2015-02) Amendments to the Consolidation Analysis. The ASU is effective for annual reporting periods, including interim reporting periods within those periods, beginning after December 15, 2015. Early adoption is permitted. The new consolidation standard changes the criteria a reporting enterprise uses to evaluate if certain legal entities, such as limited partnerships and similar entities, should be consolidated. We are in the process of assessing the effects of the application of the new guidance on our financial statements.

In April 2015 the FASB issued Accounting Standards Update 2015-03 (ASU 2015-03) Simplifying Balance Sheet Presentation by Presenting Debt Issuance Costs as a Deduction from Recognized Debt Liability. The ASU is effective for annual reporting periods, including interim reporting periods within those periods, beginning after December 15, 2015. Early adoption is permitted. The new standard requires debt issuance costs to be classified as reductions to the face value of the related debt. We do not expect ASU 2015-03 to materially affect our financial position until we issue new debt. During the Chapter 11 Cases, debt issuance costs on prepetition debt subject to compromise will continue to be reported in liabilities subject to compromise.


5


2.    CHAPTER 11 CASES

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

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

Proposed Plan of Reorganization

A Chapter 11 plan of reorganization, among other things, determines the rights and satisfaction of claims of various creditors and security holders of an entity operating under the protection of the Bankruptcy Court and is subject to the ultimate outcome of stakeholder negotiations and Bankruptcy Court decisions ongoing through the date on which the Chapter 11 plan is confirmed. In order for the Debtors to emerge successfully from the Chapter 11 Cases as reorganized companies, they must obtain approval from the Bankruptcy Court and certain of their respective creditors for a Chapter 11 plan of reorganization. The Debtors currently have the exclusive right to file a Chapter 11 plan of reorganization in the Chapter 11 Cases until June 23, 2015 and the exclusive right to solicit the appropriate votes for any such plan it files prior to such date until August 23, 2015 (i.e. collectively, the exclusivity period).

On April 14, 2015, the Debtors filed with the Bankruptcy Court the Plan of Reorganization and the Disclosure Statement. In general, the Plan of Reorganization proposes a structure that involves a tax-free deconsolidation or tax-free spin-off of TCEH from EFH Corp. (Reorganized TCEH) and the reorganization of EFH Corp. and EFIH either (a) as contemplated by the Debtors' previously disclosed Bankruptcy Court approved bidding procedures with respect to the potential sale of EFH Corp.'s indirect economic interest in Oncor, (b) pursuant to a standalone plan of reorganization or (c) pursuant to a creditor back-stopped plan of reorganization. Pursuant to the Plan of Reorganization, among other things, holders of TCEH first lien secured claims would receive 100% of the common stock of Reorganized TCEH and 100% of the proceeds of new debt issued by Reorganized TCEH. Also, pursuant to the Plan of Reorganization, the Debtors would select the highest or otherwise best transaction to maximize value for reorganized EFH Corp. and EFIH.

The Plan of Reorganization is subject to revision in response to creditor and/or stakeholder claims and objections and the requirements of the Bankruptcy Code and/or the Bankruptcy Court. Unless the Plan of Reorganization receives the requisite approval from holders of claims and the Bankruptcy Court, upon expiration of the exclusivity period (unless extended by the Bankruptcy Court), any creditor or stakeholder would have the ability to file in the Chapter 11 Cases one or more Chapter 11 plans of reorganization.

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

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


6

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

In September 2014, the Debtors filed a motion with the Bankruptcy Court seeking the entry of an order approving bidding procedures with respect to the potential sale of EFH Corp.'s indirect economic ownership interest in Oncor. In January 2015, the Bankruptcy Court approved the Debtors' bidding procedures motion that sets forth the process by which the Debtors are authorized to solicit proposals (i.e., bids) from third parties to acquire (in any form and employing any structure, whether taxable (in whole or in part) or tax-free) EFH Corp.'s indirect economic ownership interest in Oncor in accordance with the Bankruptcy Code. These bidding procedures contemplate that the Debtors select a stalking horse bid after a two-stage closed bidding process, and, after approval by the Bankruptcy Court of such stalking horse bid, the Debtors conduct a round of open bidding culminating in an auction intended to obtain a higher or otherwise best bid for a transaction. Initial bids were received in early March 2015 and second round bids were received in April 2015, and each of the Debtors is currently assessing those submissions. We cannot predict the outcome of this process, including whether we will receive any acceptable bid, whether the Bankruptcy Court will approve any such bid or whether any such transaction will (or when it will) ultimately close because any such transaction would be the subject of customary closing conditions, including receipt of all applicable regulatory approvals.

Scheduling Matters

The Debtors filed a proposed scheduling order with respect to the Disclosure Statement and the Plan of Reorganization on April 14, 2015. On May 4, 2015, the Bankruptcy Court indicated that it would approve (a) the Debtors' request to hold a hearing on the Disclosure Statement on July 20, 2015 (and related discovery protocols) and (b) mediation between the Debtors and certain TCEH stakeholders with respect to Plan of Reorganization issues that affect the TCEH Debtors' estates. The Bankruptcy Court is expected to hold a scheduling conference on June 25, 2015 to address a Plan of Reorganization confirmation timeline (and related confirmation discovery protocols). The Disclosure Statement timeline set forth in the proposed scheduling order is subject to 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). There is no guarantee that mediation will be successful.

Tax Matters

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

Implications of the Chapter 11 Cases

Our ability to continue as a going concern is contingent upon, among other factors, our ability to comply with the financial and other covenants contained in the DIP Facilities described in Note 9, 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 and our ability to complete a Chapter 11 plan of reorganization in a timely manner, including obtaining creditor and Bankruptcy Court approval of such plan as well as applicable regulatory approvals required for such plan and obtaining any exit financing needed to implement such plan. These circumstances and uncertainties inherent in the bankruptcy proceedings raise substantial doubt about our ability to continue as a going concern.


7

Operations During the Chapter 11 Cases

In general, the Debtors have received final bankruptcy court orders with respect to first day motions and other operating motions that allow the Debtors to operate their businesses in the ordinary course, including, among others, providing for the payment of certain pre-petition employee and retiree expenses and benefits, the use of the Debtors' existing cash management system, the continuation of customer contracts and programs at our retail electricity operations, the payment of certain pre-petition amounts to certain critical vendors, the ability to perform under certain pre-petition hedging and trading arrangements and the ability to pay certain pre-petition taxes and regulatory fees. In addition, the Bankruptcy Court has issued orders approving the DIP Facilities discussed in Note 9.

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

Pre-Petition Claims

Holders of the substantial majority of pre-petition claims were required to file proofs of claims by the bar date established by the Bankruptcy Court. A bar date is the date by which certain claims against the Debtors must be filed if the claimants wish to receive any distribution in the Chapter 11 Cases. The Bankruptcy Court established a bar date of October 27, 2014 for the substantial majority of claims. We have received approximately 10,000 filed claims since the Petition Date. We are in the process of reconciling those claims to the amounts listed in our schedules of assets and liabilities, which includes communications with claimants to acquire additional information required for reconciliation. As of May 7, 2015, approximately 4,000 of those claims have been settled, withdrawn or expunged. To the extent claims are reconciled and resolved, we have recorded them at the expected allowed amount. Claims that remain unresolved or unreconciled through the filing of this report have been estimated based upon management's best estimate of the likely claim amounts that the Bankruptcy Court will ultimately allow.

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

Executory Contracts and Unexpired Leases

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

Since the Petition Date, we have renegotiated or rejected a limited number of executory contracts and unexpired leases. For the three months ended March 31, 2015, this activity has resulted in the recognition of approximately $32 million in contract claim adjustment charges recorded in reorganization items as detailed in Note 8.



8

3.
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 interest in Oncor Holdings 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 $6.060 billion and $6.058 billion at March 31, 2015 and December 31, 2014, respectively, and consists almost entirely of our interest in Oncor Holdings, which we account for under the equity method as described above. Oncor provides services, principally electricity distribution, to TCEH's retail operations, and the related revenues represented 25% and 26% of Oncor Holdings' consolidated operating revenues for the three months ended March 31, 2015 and 2014, respectively.

See Note 15 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 $74 million and $37 million for the three months ended March 31, 2015 and 2014, respectively. Distributions may not be paid except to the extent Oncor maintains a required regulatory capital structure as discussed below. At March 31, 2015, $37 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 March 31, 2015, Oncor's regulatory capitalization ratio was 59.8% debt and 40.2% equity. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes bonds issued by Oncor Electric Delivery Transition Bond Company LLC, which were issued in 2003 and 2004 to recover specific generation-related regulatory assets and other qualified costs. Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of accounting for the Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization).

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.


9

Oncor Holdings Financial Statements — Condensed statements of consolidated income of Oncor Holdings and its subsidiaries for the three months ended March 31, 2015 and 2014 are presented below:
 
Three Months Ended March 31,
 
2015
 
2014
Operating revenues
$
946

 
$
917

Operation and maintenance expenses
(380
)
 
(345
)
Depreciation and amortization
(217
)
 
(210
)
Taxes other than income taxes
(111
)
 
(108
)
Other income
2

 
4

Other deductions
(4
)
 
(3
)
Interest income
1

 
1

Interest expense and related charges
(81
)
 
(88
)
Income before income taxes
156

 
168

Income tax expense
(61
)
 
(67
)
Net income
95

 
101

Net income attributable to noncontrolling interests
(20
)
 
(21
)
Net income attributable to Oncor Holdings
$
75

 
$
80



10

Assets and liabilities of Oncor Holdings at March 31, 2015 and December 31, 2014 are presented below:
 
March 31,
2015
 
December 31,
2014
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
18

 
$
5

Restricted cash
58

 
56

Trade accounts receivable — net
417

 
407

Trade accounts and other receivables from affiliates
128

 
118

Income taxes receivable from EFH Corp.
80

 
144

Inventories
79

 
73

Accumulated deferred income taxes
10

 
10

Prepayments and other current assets
92

 
91

Total current assets
882

 
904

Restricted cash
16

 
16

Other investments
97

 
97

Property, plant and equipment — net
12,626

 
12,463

Goodwill
4,064

 
4,064

Regulatory assets — net
1,349

 
1,429

Other noncurrent assets
71

 
67

Total assets
$
19,105

 
$
19,040

LIABILITIES
 
 
 
Current liabilities:
 
 
 
Short-term borrowings
$
800

 
$
711

Long-term debt due currently
109

 
639

Trade accounts payable — nonaffiliates
158

 
202

Income taxes payable to EFH Corp.
31

 
24

Accrued taxes other than income
66

 
174

Accrued interest
56

 
93

Other current liabilities
117

 
156

Total current liabilities
1,337

 
1,999

Accumulated deferred income taxes
1,949

 
1,978

Long-term debt, less amounts due currently
5,720

 
4,997

Other noncurrent liabilities and deferred credits
2,260

 
2,245

Total liabilities
$
11,266

 
$
11,219



11


4.
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
(15,990
)
Balance at December 31, 2014
2,352

Additional noncash impairment charge in 2015
(700
)
Balance at March 31, 2015 (a)
$
1,652

____________
(a)
Net of accumulated impairment charges totaling $16.69 billion.

Goodwill Impairments

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

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

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

During the three months ended March 31, 2015, we experienced an impairment indicator related to decreases in forward wholesale electricity prices when compared to those prices reflected in our December 1, 2014 goodwill impairment testing analysis. As a result, the likelihood of a goodwill impairment had increased, and we initiated further testing of goodwill as of March 31, 2015. We completed our testing of goodwill for impairment during the period, which resulted in an impairment of $700 million of goodwill at March 31, 2015, which we reported in the Competitive Electric segment results.

There was no change to the goodwill balance for the three months ended March 31, 2014.

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

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

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


12

•
The discount rates applied to internally developed cash flow projections were 6.00% and 6.25% at March 31, 2015 and December 1, 2014, respectively. The discount rate represents the weighted average cost of capital consistent with our views of the rate that an expected market participant would utilize for valuation, including the risk inherent in future cash flows, taking into account the capital structure, debt ratings and current debt yields of comparable public companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry.

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

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

The impairment determinations involved significant assumptions and judgments. The calculations supporting the estimates of the fair value of our Competitive Electric segment and the fair values of its assets and liabilities utilized models that take into consideration multiple inputs, including commodity prices, operating parameters, discount rates, capital expenditures, the effects of proposed and final environmental regulations, securities prices of comparable publicly traded companies and other inputs. Assumptions regarding each of these inputs could have a significant effect on the related valuations. In performing these calculations, we also take into consideration assumptions on how current market participants would value the Competitive Electric segment and its operating assets and liabilities. Changes to assumptions that reflect the views of current market participants can also have a significant effect on the related valuations. The fair value measurements resulting from these models are classified as non-recurring Level 3 measurements consistent with accounting standards related to the determination of fair value (see Note 13). Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.

Identifiable Intangible Assets

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

 
$
429

 
$
34

 
$
463

 
$
425

 
$
38

Capitalized in-service software
 
346

 
203

 
143

 
362

 
216

 
146

Other identifiable intangible assets (a)
 
68

 
7

 
61

 
460

 
291

 
169

Total identifiable intangible assets subject to amortization
 
$
877

 
$
639

 
238

 
$
1,285

 
$
932

 
353

Retail trade name (not subject to amortization)
 
 
 
 
 
955

 
 
 
 
 
955

Mineral interests (not currently subject to amortization)
 
 
 
 
 
6

 
 
 
 
 
7

Total identifiable intangible assets
 
 
 
 
 
$
1,199

 
 
 
 
 
$
1,315

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

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


13

Amortization expense related to finite-lived identifiable intangible assets (including the condensed statements of consolidated income (loss) line item) consisted of:
Identifiable Intangible Asset
 
Condensed Statement of Consolidated Income (Loss) Line
 
Segment
 
Three Months Ended March 31,
 
 
 
2015
 
2014
Retail customer relationship
 
Depreciation and amortization
 
Competitive Electric
 
$
4

 
$
6

Capitalized in-service software
 
Depreciation and amortization
 
Competitive Electric and Corporate and Other
 
11

 
11

Other identifiable intangible assets
 
Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization
 
Competitive Electric
 
5

 
18

Total amortization expense (a)
 
 
 
 
 
$
20

 
$
35

____________
(a)
Amounts recorded in depreciation and amortization totaled $15 million and $25 million for the three months ended March 31, 2015 and 2014, respectively.

Intangible Impairments

During the three months ended March 31, 2015, we determined that certain intangible assets related to favorable power purchase contracts should be evaluated for impairment. That conclusion was based on further declines in wholesale electricity prices in ERCOT experienced during the three months ended March 31, 2015. Our fair value measurement was based on a discounted cash flow analysis of the contracts that compared the contractual price and terms of the contract to forecasted wholesale electricity and renewable energy credit prices in ERCOT. As a result of the analysis, we recorded a noncash impairment charge of $8 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions (see Note 17).

The impairment of our Big Brown generation facility (see Note 6) resulted in the impairment of the SO2 allowances under the Clean Air Act's acid rain cap-and-trade program that are associated with that facility to the extent they are not projected to be used at other sites. The fair market values of the SO2 allowances were estimated to be de minimis based on Level 3 fair value estimates (see Note 13). Accordingly, in the three months ended March 31, 2015 we recorded a noncash impairment charge of $51 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions related to our existing environmental allowances and credits intangible asset. SO2 emission allowances granted to us were recorded as intangible assets at fair value in connection with purchase accounting related to the Merger in 2007.

Estimated Amortization of Identifiable Intangible Assets

The estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as follows:
Year
 
Estimated Amortization Expense
2015
 
$
73

2016
 
$
59

2017
 
$
46

2018
 
$
26

2019
 
$
12



14


5.
INCOME TAXES

EFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. EFH Corp. is a corporate member of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH is classified as a disregarded entity for US federal income tax purposes. 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. EFH Corp., Oncor Holdings, Oncor and Oncor's minority investor are parties to a separate Federal and State Income Tax Allocation Agreement, which governs the computation of federal income tax liability among such parties, and similarly provides, among other things, that each of Oncor Holdings and Oncor will pay EFH Corp. its share of an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return.

The calculation of our effective tax rate is as follows:
 
Three Months Ended March 31,
 
2015
 
2014
Loss before income taxes and equity in earnings of unconsolidated subsidiaries
$
(2,003
)
 
$
(1,049
)
Income tax benefit
$
401

 
$
360

Effective tax rate
20.0
%
 
34.3
%

For the three months ended March 31, 2015, the effective tax rate of 20.0% 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 4) and nondeductible legal and other professional services costs related to the Chapter 11 Cases, 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 4 and 6). For the three months ended March 31, 2014, the effective tax rate of 34.3% related to our income tax benefit was slightly lower than the US Federal statutory rate of 35% due primarily to nondeductible expenses related to our debt restructuring activities.


6.
IMPAIRMENT OF LONG-LIVED ASSETS

Impairment of Lignite/Coal Fueled Generation and Mining Assets

We evaluated our generation assets for impairment during March 2015 as a result of an impairment indicator related to lower forecasted wholesale electricity prices in ERCOT. Our evaluation concluded that an impairment existed at our Big Brown generation facility, and the carrying value for that facility and related mining facility was reduced by $676 million. Our fair value measurement for these assets was determined based on an income approach that utilized probability-weighted estimates of discounted future cash flows, which were Level 3 fair value measurements (see Note 13). 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 at this or other of our generation facilities if forward wholesale electricity prices continue to decline or forecasted costs of producing electricity at our generation facilities increase.


15


7.
INTEREST EXPENSE AND RELATED CHARGES

 
Three Months Ended March 31,
 
2015
 
2014
Interest paid/accrued on debtor-in-possession financing
$
73

 
$
—

Adequate protection amounts paid/accrued (a)
302

 
—

Interest paid/accrued on pre-petition debt (b)
237

 
831

Interest expense on pre-petition toggle notes payable in additional principal (Note 10)
—

 
49

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

 
(65
)
Amortization of interest rate swap losses at dedesignation of hedge accounting
—

 
(1
)
Amortization of fair value debt discounts resulting from purchase accounting
—

 
5

Amortization of debt issuance, amendment and extension costs and discounts
—

 
51

Capitalized interest
(3
)
 
(7
)
Total interest expense and related charges
$
609

 
$
863

____________
(a)
Post-petition period only.
(b)
For the three months ended March 31, 2015, amounts include $235 million in post-petition interest related to the EFIH Second Lien Notes (see Note 10). Includes amounts related to interest rate swaps totaling zero and $146 million for the three months ended March 31, 2015 and 2014, respectively.

Interest expense for the three months ended March 31, 2015 reflects interest paid and accrued on debtor-in-possession financing (see Note 9), 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 $1.235 billion net liability related to the TCEH interest rate swaps and natural gas hedging positions terminated shortly after the Bankruptcy Filing (see Note 14), in exchange for their consent to the senior secured, super-priority liens contained in the TCEH DIP Facility and any diminution in value of their interests in the pre-petition collateral from the Petition Date, and interest paid on EFIH's pre-petition 11.00% Second Lien Notes due 2021 and 11.75% Second Lien Notes due 2022 as approved by the Bankruptcy Court in March 2015 (see Note 10). The interest rate applicable to the adequate protection amounts paid/accrued for the three months ended March 31, 2015 is 4.67% (one-month LIBOR plus 4.50%). In connection with the completion of the Plan of Reorganization, the amount of adequate protection payments may be adjusted to reflect the valuation of the TCEH Debtors determined in connection with confirmation of the Plan of Reorganization by the Bankruptcy Court.


16

The Bankruptcy Code generally restricts payment of interest on pre-petition debt, subject to certain exceptions. However, the Bankruptcy Court ordered the payment of adequate protection amounts as discussed above and post-petition interest payments on EFIH First Lien Notes in connection with the settlement in June 2014 as discussed in Note 9. Additionally, the Bankruptcy Court approved post-petition interest payments on the EFIH Second Lien Notes in March 2015 as discussed in Note 10. Additional payments may also be made upon approval by the Bankruptcy Court, at the federal judgment rate (see Note 11). Other than these amounts ordered or approved by the Bankruptcy Court, effective April 29, 2014, we discontinued recording interest expense on outstanding pre-petition debt classified as liabilities subject to compromise (LSTC). The table below shows contractual interest amounts, which are amounts due under the contractual terms of the outstanding debt, including debt subject to compromise during the Chapter 11 Cases. Interest expense reported in the condensed statements of consolidated income (loss) for the three months ended March 31, 2015 does not include $288 million in contractual interest on pre-petition debt classified as LSTC, which has been stayed by the Bankruptcy Court effective on the Petition Date. For the three months ended March 31, 2015, adequate protection paid/accrued presented below excludes $14 million related to interest paid/accrued on the TCEH first-lien interest rate and commodity hedge claims (see Note 14), as such amounts are not included in contractual interest amounts below.
 
 
Three Months Ended March 31, 2015
Entity:
 
Contractual Interest on
Debt Classified as LSTC
 
Adequate Protection
Paid/Accrued
 
Approved Interest Paid/Accrued (a)
 
Contractual Interest on
Debt Classified as LSTC Not
Paid/Accrued
EFH Corp.
 
$
31

 
$
—

 
$
—

 
$
31

EFIH
 
111

 
—

 
50

 
61

EFCH
 
2

 
—

 
—

 
2

TCEH
 
513

 
288

 
—

 
225

Eliminations (b)
 
(31
)
 
—

 
—

 
(31
)
Total
 
$
626

 
$
288

 
$
50

 
$
288

___________
(a)
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 the three months ended March 31, 2015 that contractually related to 2014 (see Note 10).
(b)
Represents contractual interest on affiliate debt held by EFH Corp. and EFIH that is classified as liabilities subject to compromise.


8.
REORGANIZATION ITEMS

Expenses and income directly associated with the Chapter 11 Cases are reported separately in the condensed statements of consolidated income (loss) as reorganization items as required by ASC 852, Reorganizations. Reorganization items also include adjustments to reflect the carrying value of liabilities subject to compromise (LSTC) at their estimated allowed claim amounts, as such adjustments are determined. The following table presents reorganization items incurred in the three months ended March 31, 2015 as reported in the condensed statements of consolidated income (loss):
 
Three Months Ended March 31, 2015
Expenses related to legal advisory and representation services
$
50

Expenses related to other professional consulting and advisory services
28

Fees associated with repayment of EFIH Second Lien Notes (Note 10)
28

Contract claims adjustments
32

Total reorganization items
$
138



17


9.
DEBTOR-IN-POSSESSION BORROWING FACILITIES AND LONG-TERM DEBT NOT SUBJECT TO COMPROMISE

TCEH DIP Facility — The Bankruptcy Court approved the TCEH DIP Facility in June 2014. The TCEH DIP Facility currently provides for up to $3.375 billion in senior secured, super-priority financing consisting of a revolving credit facility of up to $1.95 billion and a term loan facility of up to $1.425 billion. The TCEH DIP Facility is a Senior Secured, Super-Priority Credit Agreement by and among the TCEH Debtors, the lenders that are party thereto from time to time and an administrative and collateral agent.

The TCEH DIP Facility and related available capacity at March 31, 2015 are presented below. Borrowings are reported in the condensed consolidated balance sheets as borrowings under debtor-in-possession credit facilities.
 
 
March 31, 2015
TCEH DIP Facility
 
Facility
Limit
 
Available Cash
Borrowing Capacity
 
Available Letter of Credit Capacity
TCEH DIP Revolving Credit Facility (a)
 
$
1,950

 
$
1,950

 
$
—

TCEH DIP Term Loan Facility (b)
 
1,425

 
—

 
433

Total TCEH DIP Facility
 
$
3,375

 
$
1,950

 
$
433

___________
(a)
Facility used for general corporate purposes. No amounts were borrowed at March 31, 2015. Pursuant to an order of the Bankruptcy Court, the TCEH Debtors may not have more than $1.650 billion of TCEH DIP Revolving Credit Facility cash borrowings outstanding without written consent of the TCEH committee of unsecured creditors and the ad hoc group of TCEH unsecured noteholders or further order of the Bankruptcy Court.
(b)
Facility used for general corporate purposes, including but not limited to, $800 million for issuing letters of credit.

At both March 31, 2015 and December 31, 2014, all $1.425 billion of the TCEH DIP Term Loan Facility has been borrowed. Of this borrowing, $800 million represents amounts that support issuances of letters of credit and have been funded to a collateral account. Of the collateral account amount at March 31, 2015, $433 million is reported as cash and cash equivalents and $367 million is reported as restricted cash, which represents the amount of outstanding letters of credit.

Amounts borrowed under the TCEH DIP Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 3%. At both March 31, 2015 and December 31, 2014, the interest rate on outstanding borrowings was 3.75%. The TCEH DIP Facility also provides for certain additional fees payable to the agents and lenders, as well as availability fees payable with respect to any unused portions of the available TCEH DIP Facility.

The TCEH DIP Facility will mature on the earlier of (a) the effective date of any reorganization plan, (b) upon the event of the sale of substantially all of TCEH's assets or (c) May 2016. The maturity date may be extended to no later than November 2016 subject to the satisfaction of certain conditions, including the payment of a 25 basis point extension fee, a requirement that an acceptable plan of reorganization has been filed on or prior to such extension and the availability of certain metrics of liquidity applicable to the TCEH Debtors. In addition, TCEH's existing cash collateral order expires in October 2015. The expiration of the cash collateral order is an event of default under the TCEH DIP Facility. Accordingly, absent an extension of the existing cash collateral order or a new cash collateral order (agreed by the facility's lenders and the Bankruptcy Court), the lenders under the TCEH DIP Facility could accelerate the obligations under the facility.

The TCEH Debtors' obligations under the TCEH DIP Facility are secured by a lien covering substantially all of the TCEH Debtors' assets, rights and properties, subject to certain exceptions set forth in the TCEH DIP Facility. The TCEH DIP Facility provides that all obligations thereunder constitute administrative expenses in the Chapter 11 Cases, with administrative priority and senior secured status under the Bankruptcy Code and, subject to certain exceptions set forth in the TCEH DIP Facility, have priority over any and all administrative expense claims, unsecured claims and costs and expenses in the Chapter 11 Cases. EFCH is a parent guarantor to the agreement governing the TCEH DIP Facility along with substantially all of TCEH’s subsidiaries, including all subsidiaries that are Debtors in the Chapter 11 Cases.

The TCEH DIP Facility also permits certain hedging agreements to be secured on a pari-passu basis with the TCEH DIP Facility in the event those hedging agreements meet certain criteria set forth in the TCEH DIP Facility.


18

In June 2014, the RCT agreed to accept a collateral bond from TCEH of up to $1.1 billion, as a substitute for its self-bond, to secure mining land reclamation obligations. The collateral bond is a $1.1 billion carve-out from the super-priority liens under the TCEH DIP Facility that will enable the RCT to be paid before the TCEH DIP Facility lenders.

The TCEH DIP Facility provides for affirmative and negative covenants applicable to the TCEH Debtors, including affirmative covenants requiring the TCEH Debtors to provide financial information, budgets and other information to the agents under the TCEH DIP Facility, and negative covenants restricting the TCEH Debtors' ability to incur additional indebtedness, grant liens, dispose of assets, make investments, pay dividends or take certain other actions, in each case except as permitted in the TCEH DIP Facility. The TCEH Debtors' ability to borrow under the TCEH DIP Facility is subject to the satisfaction of certain customary conditions precedent set forth therein.

The TCEH DIP Facility provides for certain customary events of default, including events of default resulting from non-payment of principal, interest or other amounts when due, material breaches of representations and warranties, material breaches of covenants in the TCEH DIP Facility or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against the TCEH Debtors. The agreement governing the TCEH DIP Facility includes a covenant that requires the Consolidated Superpriority Secured Net Debt to Consolidated EBITDA ratio not exceed 3.50 to 1.00 beginning with the test period ending June 30, 2014. Consolidated Superpriority Secured Net Debt consists of outstanding term loans and revolving credit exposure under the TCEH DIP Facility less unrestricted cash. Upon the existence of an event of default, the TCEH DIP Facility provides that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

EFIH DIP Facility, EFIH First Lien Notes Settlement and EFIH Second Lien Notes Repayment — The Bankruptcy Court approved the EFIH DIP Facility in June 2014. The EFIH DIP Facility provides for a $5.4 billion first-lien debtor-in-possession financing facility. Since inception, the facility has been utilized as follows:

•
In June 2014, $1.836 billion of loans issued under the facility were issued as an exchange to holders of $1.673 billion principal amount of EFIH First Lien Notes plus accrued and unpaid interest totaling $78 million. Holders of substantially all of the principal amount exchanged received as payment in full a principal amount of loans under the DIP facility equal to 105% of the principal amount of the notes held plus 101% of the accrued and unpaid interest at the non-default rate on such principal;
•
In June 2014, $2.438 billion of cash borrowings were used to repay all remaining $2.312 billion principal amount of EFIH First Lien Notes (plus accrued and unpaid interest totaling $128 million), and
•
In March 2015, $750 million of cash borrowings were used to repay $445 million principal amount of EFIH Second Lien Notes (including accrued and unpaid pre-petition interest of $55 million and post-petition interest of $235 million) and certain fees (see Note 10).

As of March 31, 2015, remaining borrowings under the facility, net of fees, along with existing cash on hand, totaled approximately $392 million, which was held as cash and cash equivalents.

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 March 31, 2015 and December 31, 2014, outstanding borrowings under the EFIH DIP Facility totaled $5.4 billion at an annual interest rate of 4.25%. The EFIH DIP Facility is a non-amortizing loan that may, subject to certain limitations, be voluntarily prepaid by the EFIH Debtors, in whole or in part, without any premium or penalty.

The EFIH DIP Facility will mature on the earlier of (a) the effective date of any reorganization plan, (b) upon the event of the sale of substantially all of EFIH's assets or (c) June 2016. The maturity date may be extended to no later than December 2016 subject to the satisfaction of certain conditions, including the payment of a 25 basis point extension fee, a requirement that an acceptable plan of reorganization has been filed on or prior to such extension and the availability of certain metrics of liquidity applicable to EFIH and EFIH Finance.

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.


19

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 March 31, 2015, EFIH was in compliance with this minimum liquidity covenant. The Oncor Ring-Fenced Entities are not restricted subsidiaries for purposes of the EFIH DIP Facility.

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

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

Long-Term Debt Not Subject to Compromise — Amounts presented in the table below represent pre-petition liabilities that are not subject to compromise due to the debt being fully collateralized or specific orders from the Bankruptcy Court approving repayment of the debt.
 
March 31,
2015
 
December 31,
2014
EFH Corp. (parent entity)
 
 
 
8.82% Non-Debtor Building Financing due semiannually through February 11, 2022
$
38

 
$
40

Unamortized fair value premium (a)
7

 
7

Total EFH Corp.
45

 
47

EFCH
 
 
 
9.58% Fixed Notes due in annual installments through December 4, 2019 (b)
21

 
21

8.254% Fixed Notes due in quarterly installments through December 31, 2021 (b)
27

 
29

Unamortized fair value discount (a)
(3
)
 
(3
)
Total EFCH
45

 
47

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

 
25

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

 
4

Capital lease obligations
43

 
44

Other
2

 
2

Unamortized discount
(1
)
 
(2
)
Total TCEH
67

 
73

Total EFH Corp. consolidated
157

 
167

Less amounts due currently
(36
)
 
(39
)
Total long-term debt not subject to compromise
$
121

 
$
128

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


20


10.
LIABILITIES SUBJECT TO COMPROMISE

The amounts classified as liabilities subject to compromise (LSTC) reflect the company's estimate of pre-petition liabilities and other expected allowed claims to be addressed in the Chapter 11 Cases and may be subject to future adjustment as the Chapter 11 Cases proceed. Debt amounts include related unamortized deferred financing costs and discounts/premiums. Amounts classified to LSTC do not include pre-petition liabilities that are fully collateralized by letters of credit or cash deposits. The following table presents LSTC as reported in the condensed consolidated balance sheets at March 31, 2015 and December 31, 2014:
 
March 31,
2015
 
December 31,
2014
Notes, loans and other debt per the following table
$
34,679

 
$
35,124

Accrued interest on notes, loans and other debt
749

 
804

Net liability under terminated TCEH interest rate swap and natural gas hedging agreements (Note 14)
1,235

 
1,235

Trade accounts payable and other expected allowed claims
272

 
269

Total liabilities subject to compromise
$
36,935

 
$
37,432


Pre-Petition Notes, Loans and Other Debt Reported as Liabilities Subject to Compromise

Amounts presented below represent principal amounts of pre-petition notes, loans and other debt reported as liabilities subject to compromise.
 
March 31,
2015
 
December 31,
2014
EFH Corp. (parent entity)
 
 
 
9.75% Fixed Senior Notes due October 15, 2019
$
2

 
$
2

10% Fixed Senior Notes due January 15, 2020
3

 
3

10.875% Fixed Senior Notes due November 1, 2017
33

 
33

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

 
27

5.55% Fixed Series P Senior Notes due November 15, 2014 (a)
90

 
90

6.50% Fixed Series Q Senior Notes due November 15, 2024 (a)
201

 
201

6.55% Fixed Series R Senior Notes due November 15, 2034 (a)
291

 
291

Unamortized fair value discount (b)
(118
)
 
(118
)
Total EFH Corp.
529

 
529

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

 
406

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

 
1,750

11.25% / 12.25% Senior Toggle Notes due December 1, 2018
1,566

 
1,566

9.75% Fixed Senior Notes due October 15, 2019
2

 
2

Unamortized premium
243

 
243

Unamortized discount
(121
)
 
(121
)
Total EFIH
3,401

 
3,846

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

 
1

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

 
8

Unamortized fair value discount (b)
(1
)
 
(1
)
Total EFCH
8

 
8

TCEH
 
 
 
Senior Secured Facilities:
 
 
 
TCEH Floating Rate Term Loan Facilities due October 10, 2014
3,809

 
3,809

TCEH Floating Rate Letter of Credit Facility due October 10, 2014
42

 
42

 
 
 
 

21

 
March 31,
2015
 
December 31,
2014
TCEH Floating Rate Revolving Credit Facility due October 10, 2016
$
2,054

 
$
2,054

TCEH Floating Rate Term Loan Facilities due October 10, 2017 (a)
15,691

 
15,691

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

 
1,020

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

 
1,750

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

 
336

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

 
1,235

10.25% Fixed Senior Notes due November 1, 2015 (a)
1,833

 
1,833

10.25% Fixed Senior Notes due November 1, 2015, Series B (a)
1,292

 
1,292

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

 
1,749

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

 
39

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

 
111

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

 
50

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

 
71

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

 
171

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

 
39

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

 
52

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

 
31

5.00% Fixed Series 2006 due March 1, 2041
100

 
100

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

 
51

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

 
70

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

 
12

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

 
45

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

 
14

Unamortized fair value discount related to pollution control revenue bonds (b)
(103
)
 
(103
)
Other:
 
 
 
Other
1

 
1

Unamortized discount
(91
)
 
(91
)
Total TCEH
31,474

 
31,474

Deferred debt issuance and extension costs
(733
)
 
(733
)
Total EFH Corp. consolidated notes, loans and other debt
$
34,679

 
$
35,124

___________
(a)
Excludes the following principal amounts of debt held by EFIH or EFH Corp. (parent entity) and eliminated in consolidation.
 
March 31,
2015
 
December 31,
2014
EFH Corp. 5.55% Fixed Series P Senior Notes due November 15, 2014
$
281

 
$
281

EFH Corp. 6.50% Fixed Series Q Senior Notes due November 15, 2024
545

 
545

EFH Corp. 6.55% Fixed Series R Senior Notes due November 15, 2034
456

 
456

TCEH Floating Rate Term Loan Facilities due October 10, 2017
19

 
19

TCEH 10.25% Fixed Senior Notes due November 1, 2015
213

 
213

TCEH 10.25% Fixed Senior Notes due November 1, 2015, Series B
150

 
150

Total
$
1,664

 
$
1,664


(b)
Amount represents unamortized fair value adjustments recorded under purchase accounting.


22

Repayment of EFIH Second Lien Notes

In March 2015, with the approval of the Bankruptcy Court, EFIH used some of its cash to repay (Repayment) $735 million, including interest at contractual rates, in amounts outstanding under EFIH's pre-petition 11.00% Fixed Senior Secured Second Lien Notes due October 1, 2021 (11.00% Notes) and 11.75% Fixed Senior Secured Second Lien Notes due March 1, 2022 (11.75% Notes) and $15 million in certain fees and expenses of the trustee for such notes. The Repayment resulted in an $84 million reduction in the principal amount of the 11.00% Notes, a $361 million reduction in the principal amount of the 11.75% Notes and the payment of $235 million and $55 million of accrued and unpaid post-petition and pre-petition interest, respectively, at contractual rates. The Repayment required the requisite consent of the lenders under EFIH's DIP Facility. EFIH received such consent from approximately 97% of the lenders under the EFIH DIP Facility in consideration of an aggregate consent fee equal to approximately $13 million. As a result of the Repayment, as of March 31, 2015, the principal amount outstanding on the 11.00% Notes and 11.75% Notes are $322 million and $1.389 billion, respectively.

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 March 31, 2015, the restricted cash related to the pre-petition TCEH Letter of Credit Facility totaled $506 million and supported $7 million in outstanding letters of credit. Due to the default under the pre-petition TCEH Senior Secured Facilities, the remaining $499 million letter of credit capacity is no longer available. In the first quarter of 2014, TCEH issued a $157 million letter of credit to a subsidiary of EFH Corp. to secure its current and future amounts payable to the subsidiary arising from recurring transactions in the normal course of business, and in 2014, the subsidiary drew on the letter of credit in the amount of $150 million to settle amounts due from TCEH. The remaining $7 million under the letter of credit expired in July 2014. For the year ended December 31, 2014 and the three months ended March 31, 2015, $245 million and $45 million, respectively, of letters of credit have been drawn upon by counterparties to settle amounts due from TCEH. Included in the three months ended March 31, 2015 amount was $20 million drawn by certain executive officers to satisfy payments related to long-term incentive awards.

Information Regarding Significant Pre-Petition Debt

The TCEH pre-petition debt described below is junior in right of priority and payment to the TCEH DIP Facility, and the EFIH pre-petition debt (including EFIH's guarantee of the EFH Corp. debt) described below is junior in right of priority and payment to the EFIH DIP Facility.

TCEH Senior Secured Facilities — Borrowings under the TCEH Senior Secured Facilities total $22.616 billion and consist of:

•
$3.809 billion of TCEH Term Loan Facilities with interest at LIBOR plus 3.50%;
•
$15.691 billion of TCEH Term Loan Facilities with interest at LIBOR plus 4.50%, excluding $19 million aggregate principal amount held by EFH Corp.;
•
$42 million of cash borrowed under the TCEH Letter of Credit Facility with interest at LIBOR plus 3.50%;
•
$1.020 billion of cash borrowed under the TCEH Letter of Credit Facility with interest at LIBOR plus 4.50%, and
•
Amounts borrowed under the TCEH Revolving Credit Facility, which represent the entire amount of commitments under the facility totaling $2.054 billion.

The TCEH Senior Secured Facilities are fully and unconditionally guaranteed jointly and severally on a senior secured basis by EFCH, and subject to certain exceptions, each existing and future direct or indirect wholly owned US subsidiary of TCEH. The TCEH Senior Secured Facilities, the TCEH Senior Secured Notes and the TCEH first lien hedges (or any termination amounts related thereto), discussed below, are secured on a first priority basis by (i) substantially all of the current and future assets of TCEH and TCEH's subsidiaries who are guarantors of such facilities and (ii) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

TCEH 11.5% Senior Secured Notes — The principal amount of the TCEH 11.5% Senior Secured Notes totals $1.750 billion, with interest payable at a fixed rate of 11.5% per annum. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The notes are secured, on a first-priority basis, by security interests in all of the assets of TCEH, and the guarantees are secured on a first-priority basis by all of the assets and equity interests held by the Guarantors, in each case, to the extent such assets and equity interests secure obligations under the TCEH Senior Secured Facilities (the TCEH Collateral), subject to certain exceptions and permitted liens.


23

The notes are (i) senior obligations and rank equally in right of payment with all senior indebtedness of TCEH, (ii) senior in right of payment to all existing or future unsecured and second-priority secured debt of TCEH to the extent of the value of the TCEH Collateral and (iii) senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

The guarantees of the TCEH Senior Secured Notes by the Guarantors are effectively senior to any unsecured and second-priority debt of the Guarantors to the extent of the value of the TCEH Collateral. The guarantees are effectively subordinated to all debt of the Guarantors secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt.

TCEH 15% Senior Secured Second Lien Notes (including Series B) — The principal amount of the TCEH 15% Senior Secured Second Lien Notes totals $1.571 billion with interest at a fixed rate of 15% per annum. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities. The notes are secured, on a second-priority basis, by security interests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to the extent such assets and security interests secure obligations under the TCEH Senior Secured Facilities on a first-priority basis, subject to certain exceptions (including the elimination of the pledge of equity interests of any Subsidiary Guarantor to the extent that separate financial statements would be required to be filed with the SEC for such Subsidiary Guarantor under Rule 3-16 of Regulation S-X) and permitted liens. The guarantee from EFCH is not secured.

The notes are senior obligations of the issuer and rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH Senior Secured Facilities, the TCEH Senior Secured Notes and TCEH's commodity and interest rate hedges that are secured by a first-priority lien on the TCEH Collateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent of the value of the TCEH Collateral, and to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

The guarantees of the TCEH Senior Secured Second Lien Notes by the Subsidiary Guarantors are effectively senior to any unsecured debt of the Subsidiary Guarantors to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral). These guarantees are effectively subordinated to all debt of the Subsidiary Guarantors secured by the TCEH Collateral on a first-priority basis or that is secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt. EFCH's guarantee ranks equally with its unsecured debt (including debt it guarantees on an unsecured basis) and is effectively subordinated to any of its secured debt to the extent of the value of the collateral securing that debt.

TCEH 10.25% Senior Notes (including Series B) and 10.50%/11.25% Senior Toggle Notes (collectively, the TCEH Senior Notes) — The principal amount of the TCEH Senior Notes totals $4.874 billion, excluding $363 million aggregate principal amount held by EFH Corp. and EFIH, and the notes are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH's direct parent, EFCH, and by each subsidiary that guarantees the TCEH Senior Secured Facilities. The TCEH 10.25% Notes bore interest at a fixed rate of 10.25% per annum. The TCEH Toggle Notes bore interest at a fixed rate of 10.50% per annum.

EFIH 6.875% Senior Secured First Lien Notes — There were no principal amounts of the EFIH 6.875% Notes outstanding at March 31, 2015 as the notes were exchanged or settled in June 2014 as discussed in Note 9. The notes bore interest at a fixed rate of 6.875% per annum. The EFIH 6.875% Notes were secured on a first-priority basis by EFIH's pledge of its 100% ownership of the membership interests in Oncor Holdings (the EFIH Collateral) on an equal and ratable basis with the EFIH 10% Notes (discussed below).

EFIH 10% Senior Secured First Lien Notes — There were no principal amounts of the EFIH 10% Notes outstanding at March 31, 2015 as the notes were exchanged or settled in June 2014 as discussed in Note 9. The notes bore interest at a fixed rate of 10% per annum. The notes were secured by the EFIH Collateral on an equal and ratable basis with the EFIH 6.875% Notes.


24

EFIH 11% Senior Secured Second Lien Notes — The principal amount of the EFIH 11% Notes totals $322 million with interest at a fixed rate of 11% per annum. The EFIH 11% Notes are secured on a second-priority basis by the EFIH Collateral on an equal and ratable basis with the EFIH 11.75% Notes. See discussion above related to the Repayment of a portion of these notes in March 2015.

The EFIH 11% Notes are senior obligations of EFIH and EFIH Finance and rank equally in right of payment with all senior indebtedness of EFIH and are effectively senior in right of payment to all existing or future unsecured debt of EFIH to the extent of the value of the EFIH Collateral. The notes have substantially the same terms as the EFIH 11.75% Notes discussed below, and the holders of the EFIH 11% Notes will generally vote as a single class with the holders of the EFIH 11.75% Notes.

EFIH 11.75% Senior Secured Second Lien Notes — The principal amount of the EFIH 11.75% Notes totals $1.389 billion with interest at a fixed rate of 11.75% per annum. The EFIH 11.75% Notes are secured on a second-priority basis by the EFIH Collateral on an equal and ratable basis with the EFIH 11% Notes. The EFIH 11.75% Notes have substantially the same covenants as the EFIH 11% Notes, and the holders of the EFIH 11.75% Notes will generally vote as a single class with the holders of the EFIH 11% Notes. See discussion above related to the Repayment of a portion of these notes in March 2015.

The EFIH 11.75% Notes were issued in private placements and are not registered under the Securities Act. EFIH had agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH 11.75% Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable notes for the EFIH 11.75% Notes. Because the exchange offer was not completed, the annual interest rate on the EFIH 11.75% Notes increased by 25 basis points (to 12.00%) in February 2013 and by an additional 25 basis points (to 12.25%) in May 2013.

EFIH 11.25%/12.25% Senior Toggle Notes — The principal amount of the EFIH Toggle Notes totals $1.566 billion with interest at a fixed rate of 11.25% per annum for cash interest and 12.25% per annum for PIK Interest. The terms of the Toggle Notes include an election by EFIH, for any interest period until June 1, 2016, to pay interest on the Toggle Notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFIH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. EFIH made its pre-petition interest payments on the EFIH Toggle Notes by using the PIK feature of those notes.

The EFIH Toggle Notes were issued in private placements and are not registered under the Securities Act. EFIH had agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH Toggle Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable notes for the EFIH Toggle Notes. Because the exchange offer was not completed, the annual interest rate on the EFIH Toggle Notes increased by 25 basis points (to 11.50%) in December 2013 and by an additional 25 basis points (to 11.75%) in March 2014.

EFH Corp. 10.875% Senior Notes and 11.25%/12.00% Senior Toggle Notes — The collective principal amount of these notes totals $60 million. The notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by EFCH and EFIH. The notes bore interest at a fixed rate for the 10.875% Notes of 10.875% per annum and at a fixed rate for the Toggle Notes of 11.25% per annum.

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


25


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

Letters of Credit

At March 31, 2015, TCEH had outstanding letters of credit under credit facilities totaling $374 million as follows:

•
$200 million to support commodity risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions and collateral postings with ERCOT;
•
$80 million to support executory contracts and insurance agreements;
•
$62 million to support TCEH's REP financial requirements with the PUCT, and
•
$32 million for other credit support requirements.

The automatic stay under the Bankruptcy Code does not apply to letters of credit issued under the pre-petition credit facility and third parties may draw if the terms of a particular letter of credit so provide. See Note 10 for discussion of letter of credit draws in 2014 and 2015.

Litigation

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

Make-whole Claims — In May 2014, the indenture trustee for the EFIH 10% First Lien Notes initiated litigation in the Bankruptcy Court seeking, among other things, a declaratory judgment that EFIH is obligated to pay a make-whole premium in connection with the cash repayment of the EFIH First Lien Notes discussed in Note 9 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. The indenture trustee also filed a motion in May 2014 asking the Bankruptcy Court to lift the automatic stay for cause in order to allow the trustee's notice purporting to rescind the automatic acceleration of the EFIH First Lien Notes to take effect. Following argument and briefing on cross motions for summary judgment, in March 2015, the Bankruptcy Court issued a ruling and order in favor of the EFIH Debtors on almost all issues, including denying the indenture trustee's motion for summary judgment in full and granting the EFIH Debtors summary judgment on all but the issue of whether to lift the automatic stay. A trial took place in April 2015. The Bankruptcy Court has not yet issued a ruling on these issues.


26

In June 2014, the indenture trustee for the EFIH Second Lien Notes initiated litigation in the Bankruptcy Court seeking similar relief with respect to the EFIH Second Lien Notes, including among other things, that EFIH is obligated to pay a make-whole premium in connection with any repayment of the EFIH Second Lien Notes and that such make-whole premium would be an allowed secured claim, or in the alternative, an allowed secured or unsecured claim for breach of contract (the EFIH Second Lien Make-whole Claims). In the EFIH Second Lien Make-whole Claims, as of March 31, 2015, the amount of such claims alleged would have been equal to approximately $539 million plus reimbursement of expenses. In December 2014, the EFIH Debtors filed counterclaims for relief against the Second Lien indenture trustee, seeking declaratory relief that, among other things, EFIH is not obligated to pay a make-whole premium in connection with any repayment of the EFIH Second Lien Notes and that such make-whole premium, if owing, would not constitute an allowed secured claim (EFIH Second Lien Counterclaims). As a result of EFIH's partial repayment of the EFIH Second Lien Notes, the indenture trustee for the EFIH Second Lien Notes amended its complaint in April 2015. The parties are currently working together on a schedule to propose to the Bankruptcy Court in order to adjudicate this matter.

In December 2014, the EFIH Debtors initiated litigation against the indenture trustee for the EFIH PIK Notes seeking, among other things, a declaratory judgment that EFIH is not obligated to pay a redemption premium in connection with the cash repayment of the EFIH PIK Notes and that any post-petition interest owing on these notes is to be paid at the statutory Federal Judgment Rate of interest. The indenture trustee for the EFIH PIK Notes filed a motion in February 2015 to dismiss the EFIH Debtors' complaint for declaratory relief, and the EFIH Debtors filed a brief in opposition to that motion in February 2015. If a redemption claim was allowed, as of March 31, 2015, such claims would be approximately $100 million. On May 4, 2015, the Bankruptcy Court heard arguments on the motion to dismiss. The Bankruptcy Court has not yet issued a ruling on this issue.

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

Potential Inter/Intra Debtor Claims — In August 2014, the Bankruptcy Court entered an order in the Chapter 11 Cases establishing discovery procedures governing, among other things, certain prepetition transactions among the various Debtors' estates. In February 2015, the ad hoc group of TCEH unsecured creditors; the official committee representing unsecured interests at EFCH and its direct subsidiary, TCEH; and the official committee representing unsecured interests at EFH and EFIH filed motions with the Bankruptcy Court seeking standing to prosecute derivative claims on behalf of TCEH relating to certain of these prepetition transactions. These motions are scheduled to be heard at a later date. In addition to the claims described above, certain of the Debtors (or creditors purporting to act derivatively in the name of a Debtor) may bring inter-Debtor or intra-Debtor claims (including claims under the Federal and State Income Tax Allocation Agreement among EFH Corp. and certain of its subsidiaries under which TCEH and EFH Corp. have previously filed claims in the Chapter 11 Cases) that could be material in amount. Creditors who wish to seek derivative standing to prosecute claims on behalf of a Debtor relating to pre-petition transactions addressed by the discovery protocol governing the Debtors' Chapter 11 Cases are currently required to file motions seeking standing by the later of May 29, 2015 and fifteen days after approval of a disclosure statement. We cannot predict the timing or outcome of future proceedings, if any, related to these transactions. The outcome of any of these claims could be material and could affect the results of operation, liquidity or financial condition of a particular Debtor.

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.


27

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

Cross-State Air Pollution Rule (CSAPR)

In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions from our fossil fueled generation units. In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule. In June 2012, the EPA finalized the proposed rule (Second Revised Rule). As compared to the proposed revisions to the CSAPR issued by the EPA in October 2011, the Final Revisions and the Second Revised Rule finalize emissions budgets for our generation assets that are approximately 6% lower for SO2, 3% higher for annual NOx and 2% higher for seasonal NOx.

The CSAPR became effective January 1, 2015, but is still subject to further legal challenge before the D.C. Circuit Court on remand from the US Supreme Court. Oral argument took place in February 2015. While we cannot predict the outcome of future proceedings related to the CSAPR, based upon our current operating plans, including Mercury and Air Toxics Standard (MATS) compliance efforts, we do not believe that the CSAPR will cause any material operational, financial or compliance issues.

State Implementation Plan (SIP)

In February 2013, in response to a petition for rulemaking filed by the Sierra Club, the EPA proposed a rule requiring certain states to replace SIP exemptions for excess emissions during malfunctions with an affirmative defense. Texas was not included in that original proposal since it already had an EPA-approved affirmative defense provision in its SIP. In 2014, as a result of a D.C. Circuit Court decision striking down an affirmative defense in another EPA rule, the EPA revised its 2013 proposal to extend the EPA's proposed findings of inadequacy to states that have affirmative defense provisions, including Texas. The EPA's revised proposal would require Texas to remove or replace its EPA-approved affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. We filed comments on the EPA proposal in November 2014, and the EPA is expected to finalize the proposal in May 2015. We cannot predict the timing or outcome of future proceedings related to this rulemaking, including the requirements of any ultimately implemented rule, any compliance timeframe, or the financial effects, if any.

In June 2014, the Sierra Club filed a petition in the D.C. Circuit Court seeking review of several EPA regulations containing affirmative defenses for malfunctions, including the MATS rule for power plants. In the petition, the Sierra Club contends this affirmative defense is no longer permissible in light of a D.C. Circuit Court decision regarding similar defenses applicable to the cement industry. Luminant filed a motion to intervene in this case. In July 2014, the D.C. Circuit Court ordered the case stayed pending the EPA's consideration of a petition for administrative reconsideration of the regulations at issue. In December 2014, the EPA signed a proposal to make technical corrections to the MATS rule. 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.


28


12.
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 three months ended March 31, 2015:
 
EFH Corp. Shareholders’ Equity
 
 
 
 
 
Common Stock (a)
 
Additional Paid-in Capital
 
Retained Earnings (Deficit)
 
Accumulated Other Comprehensive Income (Loss)
 
Noncontrolling Interests
 
Total Equity
Balance at December 31, 2014
$
2

 
$
7,968

 
$
(27,563
)
 
$
(130
)
 
$
—

 
$
(19,723
)
Net loss
—

 
—

 
(1,527
)
 
—

 
—

 
(1,527
)
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 March 31, 2015
$
2

 
$
7,968

 
$
(29,090
)
 
$
(130
)
 
$
—

 
$
(21,250
)
____________
(a)
Authorized shares totaled 2,000,000,000 at March 31, 2015. Outstanding shares totaled 1,669,861,379 and 1,669,861,379 at March 31, 2015 and December 31, 2014, respectively.

The following table presents the changes to equity for the three months ended March 31, 2014:
 
EFH Corp. Shareholders’ Equity
 
 
 
 
 
Common Stock (a)
 
Additional Paid-in Capital
 
Retained Earnings (Deficit)
 
Accumulated Other Comprehensive Income (Loss)
 
Noncontrolling Interests
 
Total Equity
Balance at December 31, 2013
$
2

 
$
7,962

 
$
(21,157
)
 
$
(63
)
 
$
1

 
$
(13,255
)
Net loss
—

 
—

 
(609
)
 
—

 
—

 
(609
)
Effects of stock-based incentive compensation plans
—

 
2

 
—

 
—

 
—

 
2

Change in unrecognized losses related to pension and OPEB plans
—

 
—

 
—

 
(1
)
 
—

 
(1
)
Investment by noncontrolling interests
—

 
—

 
—

 
—

 
1

 
1

Other
—

 
—

 
—

 
—

 
(2
)
 
(2
)
Balance at March 31, 2014
$
2

 
$
7,964

 
$
(21,766
)
 
$
(64
)
 
$
—

 
$
(13,864
)
____________
(a)
Authorized shares totaled 2,000,000,000 at March 31, 2014. Outstanding shares totaled 1,669,861,383 and 1,669,861,383 at March 31, 2014 and December 31, 2013, respectively.


29

Accumulated Other Comprehensive Income (Loss)

The following table presents the changes to accumulated other comprehensive income (loss) for the three months ended March 31, 2015. There was no other comprehensive income (loss) before reclassification for the period.
 
Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 14)
 
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 income (loss) and reported in:
 
 
 
 
 
Operating costs
—

 
(1
)
 
(1
)
Depreciation and amortization
1

 
—

 
1

Selling, general and administrative expenses
—

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

 
—

 
—

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

 
—

 
1

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

 
(2
)
 
—

Balance at March 31, 2015
$
(51
)
 
$
(79
)
 
$
(130
)

The following table presents the changes to accumulated other comprehensive income (loss) for the three months ended March 31, 2014. There was no other comprehensive income (loss) before reclassification for the period.
 
Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 14)
 
Pension and Other Postretirement Employee Benefit Liabilities Adjustments
 
Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2013
$
(56
)
 
$
(7
)
 
$
(63
)
Amounts reclassified from accumulated other comprehensive income (loss) and reported in:
 
 
 
 
 
Operating costs
—

 
(1
)
 
(1
)
Depreciation and amortization
(1
)
 
—

 
(1
)
Selling, general and administrative expenses
—

 
(1
)
 
(1
)
Interest expense and related charges
1

 
—

 
1

Income tax benefit (expense)
—

 
1

 
1

Total amount reclassified from accumulated other comprehensive income (loss) during the period
—

 
(1
)
 
(1
)
Balance at March 31, 2014
$
(56
)
 
$
(8
)
 
$
(64
)


30


13.
FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

Probable loss from default by either us or our counterparties is considered in determining the fair value of derivative assets and liabilities. These non-performance risk adjustments take into consideration credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 14 for additional information regarding credit risk associated with our derivatives). We utilize published credit ratings, default rate factors and debt trading values in calculating these fair value measurement adjustments.


31

Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including, but not limited to, commodity prices, volatility factors, discount rates and other market based factors. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing locations and credit/non-performance risk assumptions. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.

The significant unobservable inputs and valuation models are developed by employees trained and experienced in market operations and fair value measurements and validated by the company's risk management group, which also further analyzes any significant changes in Level 3 measurements. Significant changes in the unobservable inputs could result in significant upward or downward changes in the fair value measurement.

With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

Assets and liabilities measured at fair value on a recurring basis consisted of the following:
March 31, 2015
 
Level 1
 
Level 2
 
Level 3 (a)
 
Total
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
361

 
$
54

 
$
69

 
$
484

Nuclear decommissioning trust – equity securities (b)
378

 
219

 
—

 
597

Nuclear decommissioning trust – debt securities (b)
—

 
308

 
—

 
308

Total assets
$
739

 
$
581

 
$
69

 
$
1,389

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
173

 
$
22

 
$
9

 
$
204

Total liabilities
$
173

 
$
22

 
$
9

 
$
204


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

 
$
46

 
$
49

 
$
497

Nuclear decommissioning trust – equity securities (b)
375

 
217

 
—

 
592

Nuclear decommissioning trust – debt securities (b)
—

 
301

 
—

 
301

Total assets
$
777

 
$
564

 
$
49

 
$
1,390

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
278

 
$
25

 
$
14

 
$
317

Total liabilities
$
278

 
$
25

 
$
14

 
$
317

____________
(a)
See table below for description of Level 3 assets and liabilities.
(b)
The nuclear decommissioning trust investment is included in the other investments line in the condensed consolidated balance sheets. See Note 17.

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


32

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

There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the three months ended March 31, 2015 and 2014. See the table of changes in fair values of Level 3 assets and liabilities below for discussion of transfers between Level 2 and Level 3 for the three months ended March 31, 2015 and 2014.

The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at March 31, 2015 and December 31, 2014:
March 31, 2015
 
 
Fair Value
 
 
 
 
 
 
Contract Type (a)
 
Assets
 
Liabilities
 
Total
 
Valuation Technique
 
Significant Unobservable Input
 
Range (b)
Electricity purchases and sales
 
$
11

 
$
(2
)
 
$
9

 
Valuation Model
 
Illiquid pricing locations (c)
 
$25 to $45/ MWh
 
 
 
 
 
 
 
 
 
 
Hourly price curve shape (d)
 
$20 to $60/ MWh
Electricity spread options
 
4

 
(2
)
 
2

 
Option Pricing Model
 
Gas to power correlation (e)
 
20% to 95%
 
 
 
 
 
 
 
 
 
 
Power volatility (f)
 
10% to 30%
Electricity congestion revenue rights
 
42

 
(3
)
 
39

 
Market Approach (g)
 
Illiquid price differences between settlement points (h)
 
$0.00 to $20.00
Coal purchases
 
—

 
(2
)
 
(2
)
 
Market Approach (g)
 
Illiquid price variances between heat content (j)
 
$0.00 to $0.50
 
 
 
 
 
 
 
 
 
 
 
 
 
Other (k)
 
12

 
—

 
12

 
 
 
 
 
 
Total
 
$
69

 
$
(9
)
 
$
60

 
 
 
 
 
 

December 31, 2014
 
 
Fair Value
 
 
 
 
 
 
Contract Type (a)
 
Assets
 
Liabilities
 
Total
 
Valuation Technique
 
Significant Unobservable Input
 
Range (b)
Electricity purchases and sales
 
$
4

 
$
(5
)
 
$
(1
)
 
Valuation Model
 
Illiquid pricing locations (c)
 
$30 to $50/ MWh
 
 
 
 
 
 
 
 
 
 
Hourly price curve shape (d)
 
$20 to $70/ MWh
Electricity spread options
 
2

 
(1
)
 
1

 
Option Pricing Model
 
Gas to power correlation (e)
 
15% to 95%
 
 
 
 
 
 
 
 
 
 
Power volatility (f)
 
10% to 30%
Electricity congestion revenue rights
 
38

 
(4
)
 
34

 
Market Approach (g)
 
Illiquid price differences between settlement points (h)
 
$0.00 to $20.00
Coal purchases
 
—

 
(4
)
 
(4
)
 
Market Approach (g)
 
Illiquid price variances between mines (i)
 
$0.00 to $1.00
 
 
 
 
 
 
 
 
 
 
Illiquid price variances between heat content (j)
 
$0.30 to $0.40
Other (k)
 
5

 
—

 
5

 
 
 
 
 
 
Total
 
$
49

 
$
(14
)
 
$
35

 
 
 
 
 
 
____________

33

(a)
Electricity purchase and sales contracts include hedging positions in the ERCOT regions, as well as power contracts, the valuations of which include unobservable inputs related to the hourly shaping of the price curve. Electricity spread option 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. Coal purchase contracts relate to western (Powder River Basin) coal.
(b)
The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.
(c)
Based on the historical range of forward average monthly ERCOT hub and load zone prices.
(d)
Based on the historical range of forward average hourly ERCOT North Hub prices.
(e)
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.
(f)
Based on historical forward price changes.
(g)
While we use the market approach, there is either insufficient market data to consider the valuation liquid or the significance of credit reserves or non-performance risk adjustments results in a Level 3 designation.
(h)
Based on the historical price differences between settlement points within the ERCOT hubs and load zones.
(i)
Based on the historical range of price variances between mine locations.
(j)
Based on historical ranges of forward average prices between different heat contents (potential energy in coal for a given mass).
(k)
Other includes contracts for ancillary services, natural gas, diesel options, coal options and weather dependent power options.

The following table presents the changes in fair value of the Level 3 assets and liabilities for the three months ended March 31, 2015 and 2014.
 
Three Months Ended March 31,
 
2015
 
2014
Net asset (liability) balance at beginning of period
$
35

 
$
(973
)
Total unrealized valuation gains (losses)
16

 
(85
)
Purchases, issuances and settlements (a):
 
 
 
Purchases
19

 
9

Issuances
(3
)
 
(1
)
Settlements
(8
)
 
151

Transfers into Level 3 (b)
—

 
—

Transfers out of Level 3 (b)
1

 
2

Net change (c)
25

 
76

Net asset (liability) balance at end of period
$
60

 
$
(897
)
Unrealized valuation gains (losses) relating to instruments held at end of period
$
15

 
$
(71
)
____________
(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 are reported in the condensed statements of consolidated income (loss) in net gain (loss) from commodity hedging and trading activities. Activity excludes changes in fair value in the month the positions settled as well as amounts related to positions entered into and settled in the same month.


14.
COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price risk. Because certain of these instruments are deemed to be forward contracts under the Bankruptcy Code, they are not subject to the automatic stay, and counterparties may elect to terminate the agreements. Prior to the Petition Date, we had entered into interest rate swaps to manage our interest rate risk exposure. See Note 13 for a discussion of the fair value of derivatives.


34

Commodity Hedging and Trading Activity — TCEH has natural gas hedging positions designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity has generally moved with the price of natural gas. TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas through 2016 in order to hedge a portion of electricity price exposure related to expected lignite/coal and nuclear fueled generation. TCEH also enters into derivatives, including electricity, natural gas, fuel oil, uranium, emission and coal instruments, generally for short-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets. Unrealized gains and losses arising from changes in the fair value of hedging and trading instruments as well as realized gains and losses upon settlement of the instruments are reported in the condensed statements of consolidated income (loss) in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements have been used to reduce exposure to interest rate changes by converting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swaps were used to effectively reduce the hedged borrowing costs. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps were reported in the condensed statements of consolidated income (loss) in interest expense and related charges. As of March 31, 2015 and December 31, 2014, we had no active interest rate swap derivatives.

Termination of Commodity Hedges and Interest Rate Swaps — Commodity hedges and interest rate swaps entered into prior to the Petition Date are deemed to be forward contracts under the Bankruptcy Code. The Bankruptcy Filing constituted an event of default under these arrangements, and in accordance with the contractual terms, counterparties terminated certain positions shortly after the Bankruptcy Filing. The positions terminated consisted almost entirely of natural gas hedging positions and interest rate swaps that were secured by a first-lien interest in the same assets of TCEH on a pari passu basis with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes.

Entities with a first-lien security interest included counterparties to both our natural gas hedging positions and interest rate swaps, which had entered into master agreements that provided for netting and setoff of amounts related to these positions. Additionally, certain counterparties to only our interest rate swaps hold the same first-lien security interest. The net liability recorded upon the terminations totaled $1.108 billion, which represented a realized loss of $1.225 billion related to the interest rate swaps, net of a realized gain of $117 million related to the natural gas hedging positions. Additionally, net accounts payable amounts related to matured interest rate swaps of $127 million are also secured by the same first-lien secured interest. The total net liability of $1.235 billion is subject to the terms of settlement of TCEH's first-lien claims ultimately approved by the Bankruptcy Court and is reported in the condensed consolidated balance sheets as a liability subject to compromise. Additionally, counterparties associated with the net liability are allowed, and have been receiving, adequate protection payments related to their claims as permitted by TCEH's cash collateral order approved by the Bankruptcy Court (see Note 7).

Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of commodity and other derivative contractual assets and liabilities (with the column totals representing the net positions of the contracts) as reported in the condensed consolidated balance sheets at March 31, 2015 and December 31, 2014. All amounts relate to commodity contracts.
 
March 31, 2015
 
December 31, 2014
 
Derivative
Assets
 
Derivative Liabilities
 
Derivative
Assets
 
Derivative Liabilities
Current assets
$
466

 
$
—

 
$
492

 
$
—

Noncurrent assets
18

 
—

 
5

 
—

Current liabilities
—

 
(202
)
 
—

 
(316
)
Noncurrent liabilities
—

 
(2
)
 
—

 
(1
)
Net assets (liabilities)
$
484

 
$
(204
)
 
$
497

 
$
(317
)

At March 31, 2015 and December 31, 2014, there were no derivative positions accounted for as cash flow or fair value hedges.


35

The following table presents the pretax effect of derivatives on net income (gains (losses)), including realized and unrealized effects:
 
 
Three Months Ended March 31,
Derivative (condensed statements of consolidated income (loss) presentation)
 
2015
 
2014
Commodity contracts (Net gain (loss) from commodity hedging and trading activities) (a)
 
$
125

 
$
(179
)
Interest rate swaps (Interest expense and related charges) (b)
 
—

 
(82
)
Net gain (loss)
 
$
125

 
$
(261
)
____________
(a)
Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.
(b)
Includes unrealized mark-to-market net gain (loss) as well as the net realized effect on interest paid/accrued, both reported in Interest Expense and Related Charges (see Note 7).

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 months ended March 31, 2015 and 2014. There were no amounts recognized in OCI for the three months ended March 31, 2015 and 2014.

Accumulated other comprehensive income related to cash flow hedges (excluding Oncor's interest rate hedges) at March 31, 2015 and December 31, 2014 totaled $35 million and $36 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps previously accounted for as cash flow hedges. We expect that $2 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income at March 31, 2015 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

Balance Sheet Presentation of Derivatives

Consistent with elections under US GAAP to present amounts on a gross basis, we report derivative assets and liabilities in the condensed consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. We may enter into offsetting positions with the same counterparty, resulting in both assets and liabilities. Volatility in underlying commodity prices can result in significant changes in assets and liabilities presented from period to period.

Margin deposits that contractually offset these derivative instruments are reported separately in the condensed consolidated balance sheets. Margin deposits received from counterparties are either used for working capital or other corporate purposes or are deposited in a separate restricted cash account. At March 31, 2015 and December 31, 2014, all margin deposits held were unrestricted.

We maintain standardized master netting agreements with certain counterparties that allow for the netting of positive and negative exposures. Generally, we utilize the International Swaps and Derivatives Association (ISDA) standardized contract for financial transactions, the Edison Electric Institute standardized contract for physical power transactions and the North American Energy Standards Board (NAESB) standardized contract for physical natural gas transactions. These contain credit enhancements that allow for the right to offset assets and liabilities and collateral received in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.

The following tables reconcile our derivative assets and liabilities as presented in the condensed consolidated balance sheets to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
March 31, 2015
 
 
Amounts Presented in Balance Sheet
 
Offsetting Instruments (a)
 
Financial Collateral (Received) Pledged (b)
 
Net Amounts
Derivative assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
484

 
$
(195
)
 
$
(93
)
 
$
196

Derivative liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
(204
)
 
195

 
1

 
(8
)
Net amounts
 
$
280

 
$
—

 
$
(92
)
 
$
188



36

December 31, 2014
 
 
Amounts Presented in Balance Sheet
 
Offsetting Instruments (a)
 
Financial Collateral (Received) Pledged (b)
 
Net Amounts
Derivative assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
497

 
$
(298
)
 
$
(16
)
 
$
183

Derivative liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
(317
)
 
298

 
2

 
(17
)
Net amounts
 
$
180

 
$
—

 
$
(14
)
 
$
166

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

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at March 31, 2015 and December 31, 2014:
 
 
March 31, 2015
 
December 31, 2014
 
 
Derivative type
 
Notional Volume
 
Unit of Measure
Natural gas (a)
 
2,115

 
1,687

 
Million MMBtu
Electricity
 
30,814

 
22,820

 
GWh
Congestion Revenue Rights (b)
 
89,637

 
89,484

 
GWh
Coal
 
8

 
10

 
Million US tons
Fuel oil
 
38

 
36

 
Million gallons
Uranium
 
252

 
150

 
Thousand pounds
____________
(a)
Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions.
(b)
Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT.

Credit Risk-Related Contingent Features of Derivatives

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

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

In addition, certain derivative agreements that are collateralized primarily with liens on certain of our assets include indebtedness cross-default provisions that have resulted in the termination of such contracts as a result of the Bankruptcy Filing. Substantially all of the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, were triggered upon the Bankruptcy Filing, and substantially all of the contracts had been cancelled. There was no liquidity exposure associated with these liabilities at both March 31, 2015 and December 31, 2014. See Note 10 for a description of other pre-petition obligations that are supported by liens on certain of our assets.

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


37

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 March 31, 2015, total credit risk exposure to all counterparties related to derivative contracts totaled $535 million (including associated accounts receivable). The net exposure to those counterparties totaled $229 million at March 31, 2015 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $49 million. At March 31, 2015, the credit risk exposure to the banking and financial sector represented 72% of the total credit risk exposure and 46% of the net exposure.

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

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


38


15.
RELATED PARTY TRANSACTIONS

The following represent our significant related-party transactions.

•
On a quarterly basis, we accrue a management fee payable to the Sponsor Group under the terms of a management agreement. Related amounts expensed and reported as SG&A expense totaled $10 million for both the three months ended March 31, 2015 and 2014. No payments were made in the three months ended March 31, 2015 and 2014. 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 have been reclassified to liabilities subject to compromise (LSTC), and fees accrued after the Petition Date have been reported in other noncurrent liabilities and deferred credits.

•
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.

•
EFH Corp. and EFIH have purchased, or received in exchanges, certain debt securities of EFH Corp. and TCEH, which they have held. Principal and interest payments received by EFH Corp. and EFIH on these investments have been used, in part, to service their outstanding debt. These investments are eliminated in consolidation in these consolidated financial statements. EFIH held $1.282 billion principal amount of EFH Corp. debt and $79 million principal amount of TCEH debt at both March 31, 2015 and December 31, 2014. EFH Corp. held $303 million principal amount of TCEH debt at both March 31, 2015 and December 31, 2014.

•
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 $236 million and $241 million for the three months ended March 31, 2015 and 2014, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The condensed consolidated balance sheets at March 31, 2015 and December 31, 2014 reflect amounts due currently to Oncor totaling $128 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 $6 million and $9 million for the three months ended March 31, 2015 and 2014, respectively.

•
A subsidiary of EFH Corp. bills TCEH subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges totaled $51 million and $56 million for the three months ended March 31, 2015 and 2014, respectively.

•
See Note 10 for discussion of a letter of credit issued by TCEH in 2014 to a subsidiary of EFH Corp. to secure its amounts payable to the subsidiary arising from recurring transactions in the normal course.

•
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. The assets are substantially for the use of TCEH and its subsidiaries.


39

•
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 March 31, 2015 and 2014. Income and expenses associated with the trust fund and the decommissioning liability incurred by TCEH are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates. At March 31, 2015 and December 31, 2014, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $485 million and $479 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 March 31, 2015, our net current amount payable to Oncor Holdings related to federal and state income taxes (reported in net payables due to unconsolidated subsidiary) totaled $49 million, $48 million of which related to Oncor. The $48 million net payable to Oncor included a $79 million federal income tax payable offset by a $31 million state margin tax receivable. Additionally, at March 31, 2015 we had a noncurrent tax payable to Oncor of $69 million recorded in other noncurrent liabilities and deferred credits and a noncurrent tax receivable from Oncor Holdings of $4 million recorded in other noncurrent assets. At December 31, 2014, our net current amount payable to Oncor Holdings totaled $120 million, all of which related to Oncor. The $120 million net payable to Oncor included a $144 million federal income tax payable offset by a $24 million state margin tax receivable. Additionally, at December 31, 2014 we had noncurrent tax payable to Oncor of $64 million recorded in other noncurrent liabilities and deferred credits.

For the three months ended March 31, 2015 and 2014, EFH Corp. received income tax payments from Oncor Holdings totaling $6 million and $5 million, respectively. For both the three months ended March 31, 2015 and 2014, EFH Corp. received no income tax payments from Oncor.

•
Certain transmission and distribution utilities in Texas have requirements in place to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, as a result of TCEH's credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, at both March 31, 2015 and December 31, 2014, TCEH had posted letters of credit and/or cash in the amount of $9 million for the benefit of Oncor.

•
In December 2012, Oncor became the sponsor of a new pension plan (the Oncor Plan), the participants in which consist of all of Oncor's active employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Oncor had previously contractually agreed to assume responsibility for pension liabilities that are recoverable by Oncor under regulatory rate-setting provisions. As part of the pension plan actions, EFH Corp. fully funded the non-recoverable pension liabilities under the Oncor Plan. After the pension plan actions, participants remaining in the EFH Corp. pension plan consist of active employees under collective bargaining agreements (union employees). Oncor continues to be responsible for the recoverable portion of pension obligations to these union employees. Under ERISA, EFH Corp. and Oncor remain jointly and severally liable for the funding of the EFH Corp. and Oncor pension plans. We view the risk of the retained liability under ERISA related to the Oncor Plan to be not significant.

•
EFH Corp.'s condensed consolidated balance sheets reflect unfunded pension and OPEB liabilities related to plans that it sponsors, but also reflects a receivable from Oncor for that portion of the unfunded liabilities for which Oncor is contractually responsible, substantially all of which is expected to be recovered in Oncor's rates. At both March 31, 2015 and December 31, 2014, the receivable amount relates only to the EFH Corp. pension plan and totaled $47 million. The amounts are classified as a noncurrent receivable from unconsolidated subsidiary. Net amounts of pension and OPEB expenses recognized in the three months ended March 31, 2015 and 2014 are not material.


40

•
In the first quarter of 2014, a cash contribution totaling $84 million was made to the EFH Corp. retirement plan, of which $64 million was contributed by Oncor and $20 million was contributed by TCEH, which resulted in the EFH Corp. retirement plan being fully funded as calculated under the provisions of ERISA. As a result of the Bankruptcy Filing, participants in the EFH Corp. retirement plan who choose to retire would not be eligible for the lump sum payout option under the retirement plan unless the EFH Corp. retirement plan was fully funded. The payment by TCEH was accounted for as an advance to EFH Corp. that will be settled as pension and OPEB expenses are allocated to TCEH in the normal course.

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


16.
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 3 for discussion of the reporting of Oncor Holdings and, accordingly, the Regulated Delivery segment, as an equity method investment. See Note 15 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 2014 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 income (loss) prepared based on GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices or regulated rates. Certain shared services costs are allocated to the segments.
 
Three Months Ended March 31,
 
2015
 
2014
Operating revenues (all Competitive Electric)
$
1,272

 
$
1,517

Equity in earnings of unconsolidated subsidiaries (net of tax) — Regulated Delivery (net of noncontrolling interests of $20 and $21)
$
75

 
$
80

Net income (loss):
 
 
 
Competitive Electric
$
(1,336
)
 
$
(567
)
Regulated Delivery
75

 
80

Corporate and Other
(266
)
 
(122
)
Consolidated net loss
$
(1,527
)
 
$
(609
)

41


17.
SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions
 
Three Months Ended March 31,
 
2015
 
2014
Other income:
 
 
 
Office space rental income (a)
$
3

 
$
3

Mineral rights royalty income (b)
1

 
1

All other
4

 
5

Total other income
$
8

 
$
9

Other deductions:
 
 
 
Impairment of favorable purchase contracts (Note 4) (b)
$
8

 
$
—

Impairment of emission allowances (Note 4) (b)
51

 
—

All other
1

 
—

Total other deductions
$
60

 
$
—

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

Restricted Cash
 
March 31, 2015
 
December 31, 2014
 
Current
Assets
 
Noncurrent Assets
 
Current
Assets
 
Noncurrent Assets
Amounts related to TCEH's DIP Facility (Note 9)
$
—

 
$
367

 
$
—

 
$
350

Amounts related to TCEH's pre-petition Letter of Credit
Facility (Note 10) (a)
—

 
506

 
—

 
551

Other
6

 
—

 
6

 
—

Total restricted cash
$
6

 
$
873

 
$
6

 
$
901

____________
(a)
See Note 10 for discussion of letter of credit draws in 2014 and 2015.

Trade Accounts Receivable
 
March 31,
2015
 
December 31,
2014
Wholesale and retail trade accounts receivable
$
554

 
$
604

Allowance for uncollectible accounts
(15
)
 
(15
)
Trade accounts receivable — net
$
539

 
$
589


Gross trade accounts receivable at March 31, 2015 and December 31, 2014 included unbilled revenues of $198 million and $239 million, respectively.

Allowance for Uncollectible Accounts Receivable
 
Three Months Ended March 31,
 
2015
 
2014
Allowance for uncollectible accounts receivable at beginning of period
$
15

 
$
14

Increase for bad debt expense
9

 
10

Decrease for account write-offs
(9
)
 
(7
)
Allowance for uncollectible accounts receivable at end of period
$
15

 
$
17



42

Inventories by Major Category
 
March 31,
2015
 
December 31,
2014
Materials and supplies
$
215

 
$
214

Fuel stock
230

 
215

Natural gas in storage
25

 
39

Total inventories
$
470

 
$
468


Other Investments
 
March 31,
2015
 
December 31,
2014
Nuclear plant decommissioning trust
$
905

 
$
893

Assets related to employee benefit plans, including employee savings programs, net of distributions
62

 
61

Land
36

 
37

Miscellaneous other
4

 
4

Total other investments
$
1,007

 
$
995


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 15). The nuclear decommissioning trust fund is not a debtor under the Chapter 11 Cases. A summary of investments in the fund follows:
 
March 31, 2015
 
Cost (a)
 
Unrealized gain
 
Unrealized loss
 
Fair market
value
Debt securities (b)
$
295

 
$
13

 
$
—

 
$
308

Equity securities (c)
281

 
321

 
(5
)
 
597

Total
$
576

 
$
334

 
$
(5
)
 
$
905


 
December 31, 2014
 
Cost (a)
 
Unrealized gain
 
Unrealized loss
 
Fair market
value
Debt securities (b)
$
288

 
$
13

 
$
—

 
$
301

Equity securities (c)
276

 
320

 
(4
)
 
592

Total
$
564

 
$
333

 
$
(4
)
 
$
893

____________
(a)
Includes realized gains and losses on securities sold.
(b)
The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's Investors Services, Inc. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.32% and 4.35% at March 31, 2015 and December 31, 2014, respectively, and an average maturity of 6 years at both March 31, 2015 and December 31, 2014.
(c)
The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.

Debt securities held at March 31, 2015 mature as follows: $80 million in one to five years, $72 million in five to ten years and $156 million after ten years.


43

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 March 31,
 
2015
 
2014
Realized gains
$
—

 
$
1

Realized losses
$
(1
)
 
$
—

Proceeds from sales of securities
$
23

 
$
33

Investments in securities
$
(27
)
 
$
(37
)

Property, Plant and Equipment

At March 31, 2015 and December 31, 2014, property, plant and equipment of $11.6 billion and $12.4 billion, respectively, is stated net of accumulated depreciation and amortization of $4.7 billion and $5.3 billion, respectively.

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

Asset Retirement and Mining Reclamation Obligations

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of Oncor's delivery fees.

In December 2014, the EPA signed the final Disposal of Coal Combustion Residuals from Electric Utilities rule, and in April 2015, the rule was posted in the Federal Register. While we continue to review the rule, our initial estimates are that it will result in approximately $100 million of capital expenditures from 2015 through 2020 for our lignite/coal fueled generation facilities. We are in the process of determining the effect of the rule on our asset retirement obligations.

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 three months ended March 31, 2015:
 
Nuclear Plant Decommissioning
 
Mining Land Reclamation
 
Other
 
Total
Liability at December 31, 2014
$
413

 
$
165

 
$
36

 
$
614

Additions:
 
 
 
 
 
 
 
Accretion
6

 
5

 
1

 
12

Reductions:
 
 
 
 
 
 
 
Payments
—

 
(14
)
 
—

 
(14
)
Liability at March 31, 2015
419

 
156

 
37

 
612

Less amounts due currently
—

 
(58
)
 
—

 
(58
)
Noncurrent liability at March 31, 2015
$
419

 
$
98

 
$
37

 
$
554



44

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:
 
March 31,
2015
 
December 31,
2014
Uncertain tax positions, including accrued interest
$
75

 
$
74

Retirement plan and other employee benefits (a)
244

 
243

Asset retirement and mining reclamation obligations
554

 
560

Unfavorable purchase and sales contracts
560

 
566

Nuclear decommissioning fund excess over asset retirement obligation (Note 15)
485

 
479

Other
181

 
155

Total other noncurrent liabilities and deferred credits
$
2,099

 
$
2,077

____________
(a)
Includes $47 million at both March 31, 2015 and December 31, 2014, representing pension liabilities related to Oncor (see Note 15).

Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $6 million for both the three months ended March 31, 2015 and 2014. See Note 4 for intangible assets related to favorable purchase and sales contracts.

The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:
Year
 
Amount
2015
 
$
24

2016
 
$
24

2017
 
$
24

2018
 
$
24

2019
 
$
24


Fair Value of Debt
 
 
March 31, 2015
 
December 31, 2014
Debt:
 
Carrying Amount
 
Fair
Value
 
Carrying Amount
 
Fair
Value
Borrowings under debtor-in-possession credit facilities (Note 9)
 
$
6,825

 
$
6,852

 
$
6,825

 
$
6,830

Pre-petition notes, loans and other debt reported as liabilities subject to compromise (Note 10)
 
$
35,411

 
$
19,633

 
$
35,857

 
$
21,411

Long-term debt not subject to compromise, excluding capital lease obligations (Note 9)
 
$
114

 
$
115

 
$
123

 
$
119


We determine fair value in accordance with accounting standards as discussed in Note 13, and at March 31, 2015, our debt fair value represents Level 2 valuations. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg.


45

Supplemental Cash Flow Information
 
Three Months Ended March 31,
 
2015
 
2014
Cash payments related to:
 
 
 
Interest paid (a)
$
671

 
$
622

Capitalized interest
(3
)
 
(7
)
Interest paid (net of capitalized interest) (a)
$
668

 
$
615

Income taxes
$
—

 
$
—

Reorganization items (b)
$
89

 
$
—

Noncash investing and financing activities:
 
 
 
Construction expenditures (c)
$
65

 
$
30

____________
(a)
Net of amounts received under interest rate swap agreements. For the three months ended March 31, 2015, this amount also includes amounts paid for adequate protection.
(b)
Represents cash payments for legal and other consulting services.
(c)
Represents end-of-period accruals.



46

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

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

Business

EFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through its TCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity operations. TCEH is a wholly owned subsidiary of EFCH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Oncor Holdings, a holding company that holds an 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 3 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 16 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 will operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

For additional discussion of the Bankruptcy Filing and its effects, see Note 2 to the Financial Statements. See Note 9 to the Financial Statements for discussion of the DIP Facilities.

Proposed Restructuring Plan — On April 14, 2015, the Debtors filed the Plan of Reorganization and Disclosure Statement with the Bankruptcy Court. For additional discussion see Note 2 to the Financial Statements.


47

Proposed Sale of EFH Corp.'s Indirect Economic Ownership Interest in Oncor — In January 2015, the Bankruptcy Court approved the Debtors' bidding procedures motion that sets forth the process by which the Debtors are authorized to solicit proposals (i.e., bids) from third parties to acquire (in any form and employing any structure, whether taxable (in whole or in part) or tax-free) EFH Corp.'s indirect economic ownership interest in Oncor in accordance with the Bankruptcy Code. These bidding procedures contemplate that the Debtors select a stalking horse bid after a two-stage closed bidding process, and, after approval by the Bankruptcy Court of such stalking horse bid, the Debtors conduct a round of open bidding culminating in an auction intended to obtain a higher or otherwise best bid for a transaction. Initial bids were received in early March 2015 and second round bids were received in April 2015, and each of the Debtors is currently assessing those submissions. For additional discussion see Note 2 to the Financial Statements.

Repayment of EFIH Second Lien 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 and paid an aggregate consent fee equal to approximately $13 million. As a result of the Repayment, as of the date hereof, the principal amount outstanding on the 11.00% Notes and 11.75% Notes are $322 million and $1.389 billion, respectively.

Overall Hedged Generation Position — Taking together forward wholesale and retail electricity sales with all hedging positions, at March 31, 2015 and December 31, 2014, we had effectively hedged an estimated 97% and 79%, respectively, of the price exposure, on a natural gas equivalent basis, related to our expected generation output for 2015 (assuming an 8.5 market heat rate). The majority of our third-party hedges are financial natural gas positions.

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 March 31, 2015, which for natural gas reflects estimates of electricity generation less amounts under existing wholesale and retail sales contracts and amounts related to hedging positions. On a rolling basis, generally twelve-months, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.
 
Balance 2015
 
2016
$1.00/MMBtu change in natural gas price (a)(b)
$ ~9
 
$ ~220
0.1/MMBtu/MWh change in market heat rate (c)
$ ~3
 
$ ~17
___________
(a)
Balance of 2015 is from May 1, 2015 through December 31, 2015.
(b)
Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally being on the margin 70% to 90% of the time in the ERCOT market (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated). Excludes the impact of economic backdown.
(c)
Based on Houston Ship Channel natural gas prices at March 31, 2015.

Impairment of Goodwill — In the three months ended March 31, 2015 and the years ended 2014, 2013 and 2012, we recorded $700 million, $1.6 billion, $1.0 billion and $1.2 billion, respectively, in noncash goodwill impairment charges (which were not deductible for income tax purposes) related to the Competitive Electric segment. The write-offs reflected the effect of lower wholesale electricity prices in ERCOT, driven by the sustained decline in natural gas prices. Recorded goodwill related to the Competitive Electric segment totaled $1.652 billion at March 31, 2015. See Note 4 to the Financial Statements for a description of the methods and key inputs and assumptions used by management to determine implied fair value of goodwill, the degree of uncertainty associated with those key inputs and assumptions, and the changes in circumstances that reasonably could be expected to affect the key inputs and assumptions.

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


48

Impairment of Long-Lived Assets — EFH Corp. records impairment losses on long-lived assets used in our operations when events and circumstances indicate the long-lived assets might be impaired and the undiscounted cash flows generated by those assets are less than the carrying amounts of the assets. During 2014, the decrease in forecasted wholesale electricity prices in ERCOT, potential effects from environmental regulations and changes to our operating plans led to recording $4.670 billion in noncash impairment charges substantially all related to our Martin Lake, Monticello and Sandow 5 generation facilities. During the three months ended March 31, 2015, continued decreases in forecasted wholesale electricity prices in ERCOT resulted in a $676 million noncash impairment charge recorded related to our Big Brown generation facility (see Note 6 to the Financial Statements for further discussion). Additional material impairments related to these or other of our generation facilities may occur in the future if forward wholesale electricity prices in ERCOT continue to decline or if the forecasted costs of producing electricity at our generation facilities increase.

Environmental Matters — See Note 11 to Financial Statements for a discussion of the CSAPR and other EPA actions as well as related litigation.

Recent Global Climate Change Legislation — Over the past several years, the EPA has taken a number of actions regarding GHG emissions. In December 2009, the EPA issued a finding that GHG emissions endanger human health and the environment and that emissions from motor vehicles contribute to that endangerment. The EPA's finding required it to begin regulating GHG emissions from motor vehicles, and the EPA ultimately extended regulation of GHG emissions to stationary sources under existing provisions of the federal Clean Air Act (CAA). In March 2010, the EPA determined that the CAA's Prevention of Significant Deterioration (PSD) program permit requirements would apply to newly identified pollutants such as GHGs when a nation-wide rule requiring the control of a pollutant takes effect. Under this determination, PSD permitting requirements became applicable to GHG emissions from planned stationary sources or planned modifications to stationary sources that had not been issued a PSD permit by January 2, 2011 - the first date that new motor vehicles were required to meet the new GHG standards. In June 2010, the EPA finalized its so-called "tailoring rule" that established new thresholds of GHG emissions for the applicability of permits under the CAA for stationary sources, including our electricity generation facilities. The EPA's tailoring rule defined a threshold of GHG emissions for determining applicability of the CAA's PSD and Title V permitting programs at levels greater than the emission thresholds contained in the CAA. In June 2014, the US Supreme Court ruled that the EPA's regulation of GHG emissions from motor vehicles did not mandate that the EPA implement permit requirements for stationary source GHGs, but upheld the EPA's permitting program in situations where the source is already required to permit emissions that have historically been covered under the CAA. The case was remanded to the D.C. Circuit Court for further proceedings consistent with the US Supreme Court's decision.

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


49

Regional Haze — The Regional Haze Program of the Clean Air Act (CAA) establishes "as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I federal areas, like national parks, which impairment results from man-made pollution." There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. Second, electricity generation units built between 1962 and 1977 are subject to best available retrofit technology (BART) standards designed to improve visibility. BART reductions of SO2 and NOX are required either on a unit-by-unit basis or are deemed satisfied by state participation in an EPA-approved regional trading program such as the CAIR or the CSAPR. In February 2009, the TCEQ submitted a State Implementation Plan (SIP) concerning regional haze (Regional Haze SIP) to the EPA. In December 2011, the EPA proposed a limited disapproval of the Regional Haze SIP due to its reliance on the CAIR instead of the EPA's replacement CSAPR program. In August 2012, we filed a petition for review in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the EPA's limited disapproval of the Regional Haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court's decision in the CSAPR litigation. In September 2012, we filed a petition to intervene in a case filed by industry groups and other states and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance of FIP regarding the regional haze BART program. The Fifth Circuit Court case has since been transferred to the D.C. Circuit Court and consolidated with other pending BART program regional haze appeals. The consolidated cases now in the D.C. Circuit Court are currently stayed. Following the US Supreme Court's ruling in the CSAPR litigation, the case remains stayed in the D.C. Circuit Court. In December 2014, the EPA filed an unopposed motion to continue to hold the case in abeyance pending a decision in the CSAPR litigation that is pending in the D.C. Circuit Court on remand from the US Supreme Court as described in Note 11 to the Financial Statements.

In response to a lawsuit by environmental groups, the D.C. Circuit Court issued a consent decree in March 2012 that required the EPA to propose a decision on the Regional Haze SIP by May 2012 and finalize that decision by November 2012. The consent decree requires a FIP for any provisions that the EPA disapproves. The D.C. Circuit Court amended the consent decree and extended the dates for the EPA to propose and finalize a decision on the Regional Haze SIP to November 2014 and September 2015, respectively.

In June 2014, the EPA issued requests for information under Section 114 of the CAA to Luminant and other generators in Texas. In November 2014, the EPA released a proposed rule approving in part and disapproving in part Texas' SIP for Regional Haze and proposing a FIP for Regional Haze. In the proposed rule, the EPA asserts that the Texas SIP does not show reasonable progress in improving visibility for two areas in Texas and that its long-term strategy fails to make emission reductions needed to achieve reasonable progress in improving visibility in the Wichita Mountains of Oklahoma. Consistent with how the EPA has applied Regional Haze rules to other states, the EPA's final rule confirms that Texas's compliance with the CSAPR will satisfy its obligations under the BART portion of the Regional Haze Program. However, the EPA's proposed FIP for Texas goes beyond the requirements of the CSAPR and sets emission limits on a unit-by-unit basis for 15 electricity generation units in Texas. The EPA's proposed emission limits assume additional control equipment for specific coal fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven generation units and upgrades to existing scrubbers at seven generation units. Specifically for Luminant, the EPA's emission limitations are based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4. Luminant is continuing to evaluate the requirements and potential financial and operational impacts of the proposed rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the proposed FIP (if those limits are even possible to attain) would likely challenge the long-term viability of those units. Luminant, the State of Texas, and many others filed comments on the EPA's proposal in April 2015, and the rule is expected to be finalized in September 2015. As discussed in detail in these comments, we and others believe this proposed rule is unlawful and must be withdrawn. As proposed, the scrubber upgrades would be required three years after the rule is finalized, and the new scrubbers would be required five years after the rule is finalized. Assuming the proposed rule is finalized in September 2015, compliance would be required beginning in September 2018 and September 2020, respectively. While we cannot predict the outcome of the final rule, the result may have a material impact on our results of operations, liquidity or financial condition.

Recent PUCT/ERCOT Actions — In the ERCOT market, a generation entity may submit a voluntary mitigation plan to the PUCT for ensuring compliance with the PUCT rules related to abuse of market power through economic withholding. In April 2015, Luminant submitted a voluntary mitigation plan, which is expected to be voted on by the PUCT in late May or June 2015. The proposed plan specifies offering practices that Luminant could use when offering its generation into the ERCOT day-ahead and real-time markets. If approved by the PUCT, adherence to the plan would provide Luminant with an absolute defense against allegations of abuse of market power through economic withholding with respect to the specific behaviors addressed by the plan.


50

Oncor Matters with the PUCT — 2008 Rate Review Filing (PUCT Docket No. 35717) — In August 2009, the PUCT issued a final order with respect to Oncor's June 2008 rate review filing with the PUCT and 204 cities based on a test year ended December 31, 2007, and new rates were implemented in September 2009. Oncor and four other parties appealed various portions of the rate review final order to a state district court. In January 2011, the district court signed its judgment reversing the PUCT with respect to two issues: the PUCT's disallowance of certain franchise fees and the PUCT's decision that the Texas Public Utility Regulatory Act no longer requires imposition of a rate discount for state colleges and universities. Oncor filed an appeal with the Texas Third Court of Appeals (Austin Court of Appeals) in February 2011 with respect to the issues it appealed to the district court and did not prevail upon, as well as the district court's decision to reverse the PUCT with respect to discounts for state colleges and universities. In August 2014, the Austin Court of Appeals reversed the district court and affirmed the PUCT with respect to the PUCT's disallowance of certain franchise fees and the PUCT's decision that PURA no longer requires imposition of a rate discount for state colleges and universities. The Austin Court of Appeals also reversed the PUCT and district court's rejection of a proposed consolidated tax savings adjustment arising out of EFH Corp.'s ability to offset Oncor's taxable income against losses from other investments and remanded the issue to the PUCT to determine the amount of the consolidated tax savings adjustment. Oncor filed a motion on rehearing with the Austin Court of Appeals with respect to certain appeal issues on which Oncor was not successful, including the consolidated tax savings adjustment. In December 2014, the Austin Court of Appeals issued its opinion, clarifying that it was rendering judgment on the rate discount for state colleges and universities issue (affirming that PURA no longer requires imposition of the rate discount) rather than remanding it to the PUCT, and dismissing the motions for rehearing regarding the franchise fee issue and the consolidated tax savings adjustment. Oncor filed a petition for review with the Texas Supreme Court in February 2015, and in April 2015 the court requested that the parties file responses to the petitions for review. These responses are due by May 26, 2015 unless the parties request, and the court grants, an extension. There is no deadline for the court to act after receipt of these responses. 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 $130 million loss (after-tax). Oncor does not believe that any of the other issues ruled upon by the Austin Court of Appeals would result in a material impact to its results of operations or financial condition.

Transmission Cost Recovery and Rates (PUCT Docket No. 43858) — In order to reflect increases or decreases in its wholesale transmission costs, including fees it pays to other transmission service providers, PUCT rules allow Oncor to update the transmission cost recovery factor (TCRF) component of its retail delivery rates charged to REPs on March 1 and September 1 each year. In December 2014, Oncor filed an application to update the TCRF, which became effective March 1, 2015. This application was designed to reduce Oncor's billings for the period from March 2015 through August 2015 by $27 million.

Transmission Interim Rate Update Applications (PUCT Docket No. 44363) — In order to reflect changes in its invested transmission capital, PUCT rules allow Oncor to update its transmission cost of service (TCOS) rates by filing up to two interim TCOS rate adjustments in a calendar year. TCOS revenues are collected from load serving entities benefiting from Oncor's transmission system. REPs serving customers in Oncor's service territory are billed through the TCRF mechanism discussed above while other load serving entities are billed directly. In January 2015, Oncor filed an application for an interim update of its TCOS rate. The new rate was approved by the PUCT and became effective in March 2015. Oncor's expected annualized revenues increased by an estimated $35 million with approximately $23 million of this increase recoverable through transmission costs charged to wholesale customers and $12 million recoverable from REPs through the TCRF component of Oncor's delivery rates.


51


RESULTS OF OPERATIONS

Consolidated Financial Results — Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

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

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

In 2015, noncash impairments of certain long-lived assets totaling $676 million were recorded in the Competitive Electric segment as discussed in Note 6 to the Financial Statements.

See Note 17 to the Financial Statements for details of other income and deductions.

Results in 2014 include fees for legal and other professional services associated with our debt restructuring activities prior to the Petition Date, which totaled $29 million and are reported in SG&A expenses. Of this amount, $17 million is included in the Competitive Electric segment results and $12 million is included in Corporate and Other activities. Legal and other professional services costs incurred with the Chapter 11 Cases since the Petition Date are now being reported in reorganization items as discussed below.

Interest expense and related charges decreased $254 million to $609 million in 2015. The decrease reflected:

•
$643 million in lower interest expense on pre-petition debt due to the discontinuance of interest due to the Chapter 11 Cases and the termination of the interest rate swap agreements, and
•
$51 million in lower amortization of pre-petition debt issuance, amendment and extension costs and discounts due to reclassification of such amounts to liabilities subject to compromise,

partially offset by

•
$302 million in expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of TCEH secured creditors;
•
$73 million in interest expense on debtor-in-possession financing, and
•
$65 million in mark-to-market net gains on interest rate swaps in 2014.

See Note 7 to the Financial Statements for details of interest expense and related charges.

Reorganization items totaled $138 million in 2015 and included $50 million in legal advisory and representation services fees, $28 million in other professional consulting and advisory services fees, $28 million in fees associated with the repayment of EFIH Second Lien Notes in March 2015 and $32 million primarily related to contract claim adjustments. See Note 8 to the Financial Statements for additional discussion.

Income tax benefit totaled $401 million and $360 million in 2015 and 2014, respectively. Excluding the nondeductible goodwill impairment charge in 2015, the effective tax benefit rate was 30.8% and 34.3% in 2015 and 2014, respectively. See Note 5 to the Financial Statements for reconciliation of these comparable effective rates to the US federal statutory rate.


52

Net loss for EFH Corp. increased $918 million to $1.527 billion in 2015.

•
Net loss for the Competitive Electric segment increased $769 million to $1.336 billion.

•
Earnings from the Regulated Delivery segment decreased $5 million to $75 million.

•
After-tax net expenses from Corporate and Other activities totaled $266 million and $122 million in 2015 and 2014, respectively. The change primarily reflects $82 million ($128 million pre-tax) in higher interest expense reflecting interest payments as a result of the EFIH Second Lien Note repayment (see Note 10 to the Financial Statements) and charges of $42 million ($65 million pre-tax) for the Corporate and Other portion of reorganization items in 2015 discussed above, partially offset by charges of $8 million ($12 million pre-tax) in legal and other professional fees for the Corporate and Other portion of our debt restructuring activities in 2014.

Competitive Electric Segment
Financial Results
 
Three Months Ended March 31,
 
2015
 
2014
Operating revenues
$
1,272

 
$
1,517

Fuel, purchased power costs and delivery fees
(613
)
 
(732
)
Net gain (loss) from commodity hedging and trading activities
103

 
(219
)
Operating costs
(193
)
 
(214
)
Depreciation and amortization
(215
)
 
(327
)
Selling, general and administrative expenses
(161
)
 
(195
)
Impairment of goodwill
(700
)
 
—

Impairment of long-lived assets
(676
)
 
—

Other income
3

 
5

Other deductions
(60
)
 
(1
)
Interest expense and related charges
(315
)
 
(697
)
Reorganization items
(73
)
 
—

Loss before income taxes
(1,628
)
 
(863
)
Income tax benefit
292

 
296

Net loss
$
(1,336
)
 
$
(567
)


53

Competitive Electric Segment
Sales Volume and Customer Count Data
 
Three Months Ended March 31,
 
% Change
 
2015
 
2014
 
Sales volumes:
 
 
 
 
 
Retail electricity sales volumes – (GWh):
 
 
 
 
 
Residential
5,107

 
5,174

 
(1.3
)%
Small business (a)
1,496

 
1,268

 
18.0
 %
Large business and other customers
2,868

 
2,271

 
26.3
 %
Total retail electricity
9,471

 
8,713

 
8.7
 %
Wholesale electricity sales volumes (b)
5,370

 
9,803

 
(45.2
)%
Total sales volumes
14,841

 
18,516

 
(19.8
)%
 
 
 
 
 
 
Average volume (kilowatt-hours) per residential customer (c)
3,402

 
3,424

 
(0.6
)%
 
 
 
 
 
 
Weather (North Texas average) – percent of normal (d):
 
 
 
 
 
Heating degree days
120.0
%
 
118.9
%
 
0.9
 %
 
 
 
 
 
 
Customer counts:
 
 
 
 
 
Retail electricity customers (end of period, in thousands) (e):
 
 
 
 
 
Residential
1,503

 
1,506

 
(0.2
)%
Small business (a)
175

 
173

 
1.2
 %
Large business and other customers
27

 
17

 
58.8
 %
Total retail electricity customers
1,705

 
1,696

 
0.5
 %
____________
(a)
Customers with demand of less than 1 MW annually.
(b)
Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.
(c)
Calculated using average number of customers for the period.
(d)
Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over the 10-year period from 2000 to 2010.
(e)
Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers.


54

Competitive Electric Segment
Revenue and Commodity Hedging and Trading Activities
 
Three Months Ended March 31,
 
% Change
 
2015
 
2014
 
Operating revenues:
 
 
 
 
 
Retail electricity revenues:
 
 
 
 
 
Residential
$
691

 
$
683

 
1.2
 %
Small business (a)
174

 
162

 
7.4
 %
Large business and other customers
188

 
160

 
17.5
 %
Total retail electricity revenues
1,053

 
1,005

 
4.8
 %
Wholesale electricity revenues (b)(c)
148

 
428

 
(65.4
)%
Amortization of intangibles (d)
6

 
6

 
—
 %
Other operating revenues
65

 
78

 
(16.7
)%
Total operating revenues
$
1,272

 
$
1,517

 
(16.2
)%
 
 
 
 
 
 
Net gain (loss) from commodity hedging and trading activities:
 
 
 
 
 
Realized net gains (losses)
$
(1
)
 
$
35

 


Unrealized net gains (losses)
104

 
(254
)
 


Total
$
103

 
$
(219
)
 
 
____________
(a)
Customers with demand of less than 1 MW annually.
(b)
Upon settlement of physical derivative commodity contracts that we mark-to-market in net income, such as certain electricity sales and purchase agreements and coal purchase contracts, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, rather than contract price. The offsetting differences between contract and market prices are reported in net gain (loss) from commodity hedging and trading activities.
(c)
Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.
(d)
Represents amortization of the intangible net asset value of retail and wholesale electricity sales agreements resulting from purchase accounting.


55

Competitive Electric Segment
Production, Purchased Power and Delivery Cost Data
 
Three Months Ended March 31,
 
% Change
 
2015
 
2014
 
Fuel, purchased power costs and delivery fees ($ millions):
 
 
 
 
 
Fuel for nuclear facilities
$
38

 
$
42

 
(9.5
)%
Fuel for lignite/coal facilities
141

 
214

 
(34.1
)%
Total nuclear and lignite/coal facilities
179

 
256

 
(30.1
)%
Fuel for natural gas facilities and purchased power costs (a)
62

 
86

 
(27.9
)%
Amortization of intangibles (b)
1

 
9

 
(88.9
)%
Other costs
41

 
72

 
(43.1
)%
Fuel and purchased power costs
283

 
423

 
(33.1
)%
Delivery fees
330

 
309

 
6.8
 %
Total
$
613

 
$
732

 
(16.3
)%
 
 
 
 
 
 
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
 
 
 
 
 
Nuclear facilities
$
7.25

 
$
8.39

 
(13.6
)%
Lignite/coal facilities (c)
$
20.49

 
$
21.07

 
(2.8
)%
Natural gas facilities and purchased power (d)
$
45.85

 
$
53.26

 
(13.9
)%
 
 
 
 
 
 
Delivery fees per MWh
$
34.71

 
$
35.40

 
(1.9
)%
 
 
 
 
 
 
Production and purchased power volumes (GWh):
 
 
 
 
 
Nuclear facilities
5,283

 
5,066

 
4.3
 %
Lignite/coal facilities (e)
8,797

 
12,414

 
(29.1
)%
Total nuclear and lignite/coal facilities
14,080

 
17,480

 
(19.5
)%
Natural gas facilities
60

 
192

 
(68.8
)%
Purchased power (f)
701

 
844

 
(16.9
)%
Total energy supply volumes
14,841

 
18,516

 
(19.8
)%
 
 
 
 
 
 
Capacity factors:
 
 
 
 
 
Nuclear facilities
106.4
%
 
102.0
%
 
4.3
 %
Lignite/coal facilities (e)
50.8
%
 
71.7
%
 
(29.1
)%
Total
63.2
%
 
78.5
%
 
(19.5
)%
____________
(a)
See note (b) to the Revenue and Commodity Hedging and Trading Activities table on previous page.
(b)
Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.
(c)
Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs and excludes unrealized amounts as discussed in footnote (b) to the Revenue and Commodity Hedging and Trading Activities table on the previous page.
(d)
Excludes volumes related to line loss and power imbalances and unrealized amounts referenced in footnote (d) immediately above.
(e)
Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal fueled units totaling 7,150 GWh and 3,740 GWh for the three months ended March 31, 2015 and 2014, respectively.
(f)
Includes amounts related to line loss and power imbalances.


56

Competitive Electric Segment — Financial Results — Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

Operating revenues decreased $245 million, or 16%, to $1.272 billion in 2015.

Retail electricity revenues increased $48 million, or 5%, to $1.053 billion in 2015 reflecting an $87 million increase due to higher retail sales volumes, partially offset by $39 million in lower average retail sales prices. Retail sales volumes increased 9% driven by a 23% increase in business markets sales volumes. Lower average retail prices were driven by lower average electricity prices and change in business customer mix.

Wholesale electricity revenues decreased $280 million, or 65%, to $148 million in 2015 reflecting a $193 million decrease due to lower wholesale sales volumes and an $87 million decrease due to lower average sales prices. A 45% decrease in wholesale sales volumes was driven by lower generation volumes that resulted from increased economic backdown (including seasonal operations) at our generation facilities. The increased economic backdown of our generation facilities was primarily driven by a 44% decline in average wholesale electricity prices in 2015, which was impacted by lower natural gas prices during the period compared to natural gas prices in 2014. Lower average sales prices were driven by the impacts of lower natural gas prices on wholesale electricity prices.

A 29% decrease in lignite/coal fueled generation volumes reflected increased economic backdown (including seasonal operations) in 2015 as discussed above. A 4% increase in nuclear fueled generation volumes reflected the start of a refueling outage in the three months ended March 31, 2014.

Fuel, purchased power costs and delivery fees decreased $119 million, or 16%, to $613 million in 2015. Lignite/coal fuel costs decreased $73 million reflecting lower generation volumes, partially offset by higher lignite mining costs. Fuel for natural gas facilities and purchased power costs decreased $24 million reflecting lower generation from natural gas generation units and a 17% decrease in purchased power volumes. Natural gas purchases for resale decreased $17 million due to lower prices for natural gas. ERCOT ancillary service fees were $14 million lower in 2015 due to lower prices. Amortization of intangibles decreased $8 million reflecting decreased amortization of favorable purchase contracts due to impairments recorded at the end of 2014. Delivery fees increased $21 million reflecting higher volumes and delivery rates.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $103 million in net gains and $219 million in net losses for the three months ended March 31, 2015 and 2014, respectively, and included the natural gas hedging positions as well as other hedging positions.
 
Three Months Ended March 31, 2015
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains
 
Total
Hedging positions
$
4

 
$
94

 
$
98

Trading positions
(5
)
 
10

 
5

Total
$
(1
)
 
$
104

 
$
103


 
Three Months Ended March 31, 2014
 
Net Realized
Gains (Losses)
 
Net Unrealized
Gains (Losses)
 
Total
Hedging positions
$
40

 
$
(257
)
 
$
(217
)
Trading positions
(5
)
 
3

 
(2
)
Total
$
35

 
$
(254
)
 
$
(219
)

Net realized gains (losses) on hedging and trading positions decreased by $36 million in 2015 reflecting lower hedging gains from the natural gas hedging program in 2015.

The increase in net unrealized gains on hedging and trading positions of $358 million in 2015 reflected unrealized gains and lower recognized losses in our natural gas hedging program. The decrease in market prices during 2015, as noted above in our discussion of wholesale revenues, resulted in unrealized gains on our hedging positions. Unrealized losses in 2014 in the natural gas hedging program reflected the reversal of previously recognized unrealized gains as those transactions settled.


57

Operating costs decreased $21 million, or 10%, to $193 million in 2015. The decrease was driven by $16 million of lower maintenance and other costs at lignite/coal fueled generation facilities and $11 million in lower nuclear maintenance costs reflecting the start of a spring refueling outage in 2014, partially offset by $5 million in severance costs in 2015.

Depreciation and amortization expenses decreased $112 million, or 34%, to $215 million in 2015 primarily reflecting reduced depreciation expense resulting from the effect of noncash impairments of certain long-lived assets recorded at the end of 2014.

SG&A expenses decreased $34 million, or 17%, to $161 million in 2015 reflecting $17 million in legal and other professional services costs associated with our debt restructuring activities prior to the Petition Date being reported in SG&A in 2014, compared to legal and professional service costs associated with the Chapter 11 Cases since the Petition Date being reported in reorganization items as discussed below. SG&A expenses in 2015 are also lower due to $7 million in management fees paid to the Sponsor Group prior to the Petition Date (see Note 15 to the Financial Statements) and $9 million in lower employee compensation and benefits costs.

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

In 2015, noncash impairments of certain long-lived assets totaling $676 million were recorded as discussed in Note 6 to the Financial Statements.

Other deductions totaled $60 million in 2015 and $1 million in 2014. Other deductions in 2015 included $51 million related to impairment of environmental allowances and $8 million related to favorable purchase contracts (see Note 4 to the Financial Statements).

Interest expense and related charges decreased $382 million, or 55%, to $315 million in 2015. The decrease reflected:

•
$701 million in lower interest expense on pre-petition debt due to the discontinuance of interest due to the Chapter 11 Cases and the termination of the interest rate swap agreements, and
•
$65 million in lower amortization of pre-petition debt issuances, amendment and extension costs and discounts due to reclassification of such amounts to liabilities subject to compromise,

partially offset by

•
$302 million in expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of TCEH secured creditors;
•
$64 million in mark-to-market net gains on interest rate swaps in 2014, and
•
$15 million in interest expense on debtor-in-possession financing.

Reorganization items totaled $73 million in 2015 and included $26 million in legal advisory and representation services fees, $17 million in other professional consulting and advisory services fees and $32 million primarily related to contract claim adjustments. See Note 8 to the Financial Statements for additional discussion.

Income tax benefit totaled $292 million and $296 million on pretax losses in 2015 and 2014, respectively. Excluding the nondeductible goodwill impairment charge in 2015, the effective tax rate was 31.4% in 2015 and 34.3% in 2014. The decrease in the effective income tax rate is driven primarily by higher nondeductible legal and other professional services costs related to the Chapter 11 Cases in 2015, offset by the difference in the forecasted effective tax rate and the statutory rate applied to long-lived and intangible asset impairment charges in 2015.

Net loss for the Competitive Electric segment increased $769 million to $1.336 billion in 2015. The change reflected the noncash impairment of goodwill, the noncash impairments of certain long-lived assets and reorganization items, partially offset by the decrease in interest expense and related charges and improved results from hedging and trading activities.


58

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 three months ended March 31, 2015 and 2014. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $101 million in unrealized net gains in 2015 and $250 million in unrealized net losses in 2014 arising from mark-to-market accounting for positions in the commodity contract portfolio. The portfolio consists primarily of economic hedges but also includes proprietary trading positions.
 
Three Months Ended March 31,
 
2015
 
2014
Commodity contract net asset at beginning of period
$
180

 
$
525

Settlements/termination of positions (a)
(24
)
 
(71
)
Changes in fair value of positions in the portfolio (b)
125

 
(179
)
Other activity (c)
(1
)
 
14

Commodity contract net asset at end of period
$
280

 
$
289

____________
(a)
Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month.
(b)
Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month.
(c)
These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold.

Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values at March 31, 2015, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
 
 
Maturity dates of unrealized commodity contract net asset at March 31, 2015
Source of fair value
 
Less than
1 year
 
1-3 years
 
Total
Prices actively quoted
 
$
151

 
$
37

 
$
188

Prices provided by other external sources
 
29

 
3

 
32

Prices based on models
 
47

 
13

 
60

Total
 
$
227

 
$
53

 
$
280



FINANCIAL CONDITION

Cash Flows — Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014 — Cash used in operating activities totaled $407 million and $431 million in 2015 and 2014, respectively. The decrease in cash used of $24 million was driven by a decrease in cash used for margin deposits and other operating assets and liabilities, partially offset by cash used to pay reorganization costs and higher cash interest payments as a result of the EFIH Second Lien Note repayment (see Note 10 to the Financial Statements).

Depreciation and amortization expense reported in the condensed statements of consolidated cash flows exceeded the amount reported in the condensed statements of consolidated income (loss) by $36 million and $41 million for the three months ended March 31, 2015 and 2014, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the condensed statements of consolidated income (loss) consistent with industry practice, and amortization of intangible assets arising from purchase accounting that is reported in various other condensed statements of consolidated income (loss) line items including operating revenues and fuel and purchased power costs and delivery fees.

Cash used in financing activities totaled $483 million and $190 million in 2015 and 2014, respectively. 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. Activity in 2014 reflected $185 million principal amount of pollution control revenue bonds tendered.


59

Cash used in investing activities totaled $101 million in 2015 compared to cash provided by investing activities of $137 million in 2014. Cash used in 2015 reflected capital expenditures (including nuclear fuel purchases) totaling $126 million, partially offset by $25 million in restricted cash released from an escrow account when certain letters of credit were drawn. Cash provided in 2014 reflected $285 million in restricted cash released from an escrow account when certain letters of credit were drawn, partially offset by capital expenditures (including nuclear fuel purchases) totaling $145 million.

Debt Activity — Debt activities during the three months ended March 31, 2015 are as follows (all amounts presented are principal, and settlements include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses). There were no borrowings in the three months ended March 31, 2015.
 
Settlements
TCEH (a)
$
(7
)
EFCH
(2
)
EFIH (b)
(445
)
EFH Corp. (c)
(2
)
Total
$
(456
)
___________
(a)
Settlements include $6 million of payments of principal at scheduled maturity dates and $1 million of payments of capital lease liabilities.
(b)
Settlements represent cash repayments of pre-petition debt as approved by the Bankruptcy Court (see Note 10 to the Financial Statements).
(c)
Settlements are noncash.

See Notes 9 and 10 to the Financial Statements for further detail of debtor-in-possession borrowing facilities and pre-petition debt.

Available Liquidity — The following table summarizes changes in available liquidity for the three months ended March 31, 2015:
 
Available Liquidity
 
March 31, 2015
 
December 31, 2014
 
Change
Cash and cash equivalents – EFH Corp. and other
$
428

 
$
428

 
$
—

Cash and cash equivalents – EFIH
392

 
1,157

 
(765
)
Cash and cash equivalents – TCEH (a)
1,617

 
1,843

 
(226
)
Total cash and cash equivalents
2,437

 
3,428

 
(991
)
TCEH DIP Revolving Credit Facility (b)
1,950

 
1,950

 
—

Total liquidity (b)
$
4,387

 
$
5,378

 
$
(991
)
___________
(a)
Cash and cash equivalents at March 31, 2015 and December 31, 2014 exclude $873 million and $901 million, respectively, of restricted cash held for letter of credit support. The March 31, 2015 restricted cash balance includes $506 million under the TCEH pre-petition Letter of Credit Facility and $367 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 $991 million in the three months ended March 31, 2015 compared to December 31, 2014 was driven by the EFIH Second Lien Note repayment totaling $750 million (see Note 10 to the Financial Statements). The decrease also reflected $126 million in capital expenditures (including nuclear fuel purchases) and $74 million of cash used to pay reorganization items in 2015. See discussion of cash flows above.

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


60

The Bankruptcy Court approved final orders in June 2014 authorizing the TCEH DIP Facility and the EFIH DIP Facility (see Note 9 to the Financial Statements). The TCEH DIP Facility provides for $3.375 billion in senior secured, super-priority financing. The EFIH First Lien DIP Facility provides for $5.4 billion in senior secured, super-priority financing.

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

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

Distributions of Earnings from Oncor Holdings and Related Considerations — Oncor Holdings' distributions of earnings to us totaled $74 million and $37 million for the three months ended March 31, 2015 and 2014, respectively. See Note 3 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 9 to the Financial Statements for discussion of the TCEH DIP Facility.

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

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

•
$1 million in cash has been posted with counterparties as compared to $9 million posted at December 31, 2014;
•
$97 million in cash has been received from counterparties as compared to $26 million received at December 31, 2014;
•
$200 million in letters of credit have been posted with counterparties, as compared to $329 million posted at December 31, 2014, and
•
$12 million in letters of credit have been received from counterparties, as compared to $3 million received at December 31, 2014.

Because certain agreements related to these activities are deemed to be "forward contracts" under the Bankruptcy Code, they are not subject to the automatic stay, and counterparties may elect to terminate the agreements. If the agreements are terminated, such cash and letter of credit postings may be used in the ultimate settlement of the positions. See Note 14 to the Financial Statements for discussion of agreements terminated subsequent to the Bankruptcy Filing.


61

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

Income Tax Payments — In the next twelve months, income tax payments related to the Texas margin tax are expected to total approximately $50 million, and no payments or refunds of federal income taxes are expected. There were no material income tax payments for the three months ended March 31, 2015 and 2014.

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

The agreement governing the TCEH DIP Facility includes a covenant that requires the Consolidated Superpriority Secured Net Debt to Consolidated EBITDA ratio not exceed 3.50 to 1.00, beginning with the test period ending June 30, 2014. The ratio was 1.12 to 1.00 at March 31, 2015, and TCEH is in compliance with this covenant. Consolidated Superpriority Secured Net Debt consists of outstanding term loans and revolving credit exposure under the TCEH DIP Facility less unrestricted cash. TCEH's Consolidated EBITDA (as used in the covenant contained in the agreement governing the TCEH DIP Facility) for the three and twelve months ended March 31, 2015 totaled $390 million and $1.956 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.

See Note 9 to the Financial Statements for discussion of other covenants related to the DIP Facilities.

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

Certain transmission and distribution utilities in Texas are required to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, as a result of TCEH's below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. At March 31, 2015, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $22 million, with $9 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at March 31, 2015, TCEH posted letters of credit in the amount of $62 million, which are subject to adjustments.


62

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

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

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

Under the terms of a TCEH rail car lease, which has $35 million in remaining lease payments at March 31, 2015 and terminates in 2017, if TCEH fails to perform under agreements causing its indebtedness in an aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease. Under the Bankruptcy Code, the lessors are stayed from taking any action against the Debtors as a result of the default.

Under the terms of another TCEH rail car lease, which has $37 million in remaining lease payments at March 31, 2015 and terminates in 2029, if payment obligations of TCEH in excess of $200 million in the aggregate to third-party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease. Under the Bankruptcy Code, the lessors are stayed from taking any action against the Debtors as a result of the default.

Guarantees — See Note 11 to the Financial Statements for discussion of guarantees.


OFF–BALANCE SHEET ARRANGEMENTS

See Notes 3 and 11 to the Financial Statements regarding VIEs and guarantees, respectively.


COMMITMENTS AND CONTINGENCIES

See Note 11 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.


63


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.

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.


64

VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period of five to 60 days.
 
March 31, 2015
 
December 31, 2014
Month-end average MtM VaR:
$
76

 
$
50

Month-end high MtM VaR:
$
97

 
$
129

Month-end low MtM VaR:
$
59

 
$
22


Earnings at Risk (EaR) — This measurement estimates the potential reduction of pretax earnings for the periods presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities), based on a 95% confidence level and an assumed holding period of five to 60 days.
 
March 31, 2015
 
December 31, 2014
Month-end average EaR:
$
31

 
$
27

Month-end high EaR:
$
34

 
$
60

Month-end low EaR:
$
26

 
$
4


The decrease in the month end high MtM VaR risk measure during 2015 reflected lower natural gas prices and lower market volatility.

Credit Risk

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

Credit Exposure — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $785 million at March 31, 2015. The components of this exposure are discussed in more detail below.

Assets subject to credit risk at March 31, 2015 include $449 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $54 million. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

The remaining credit exposure arises from wholesale trade receivables and amounts associated with derivative instruments related to hedging and trading activities. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. At March 31, 2015, the exposure to credit risk from these counterparties totaled $336 million consisting of accounts receivable of $50 million and net asset positions related to commodity contracts of $286 million, after taking into account the netting provisions of the master agreements described above but before taking into account $106 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $230 million decreased $15 million in the three months ended March 31, 2015.


65

Of this $230 million net exposure, 90% is with investment grade customers and counterparties, as determined by our internal credit evaluation process which includes publicly available information including major rating agencies' published ratings as well as internal credit methodologies and credit scoring models. Those customers and counterparties without an S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate an S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties based on, but not limited to, the assigned credit rating, margining and collateral management.

The following table presents the distribution of credit exposure at March 31, 2015. This credit exposure largely represents wholesale trade accounts receivable and net asset positions related to commodity contracts and hedging and trading activities (a substantial majority of which mature in 2015) recognized as derivative assets in the 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 14 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
$
308

 
$
102

 
$
206

Below investment grade
28

 
4

 
24

Totals
$
336

 
$
106

 
$
230

Investment grade
91.7
%
 
 
 
89.6
%
Below investment grade
8.3
%
 
 
 
10.4
%

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 21%, 21% and 20% of the $230 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.


66

FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including such matters as activities related to our bankruptcy, financial or operational projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated," "should," "projection," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under Item 1A, Risk Factors in our 2014 Form 10-K and the discussion under Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations in this report and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:

•
our ability to obtain the necessary votes from the required creditors and stakeholders and the approval from the Bankruptcy Court for the Plan of Reorganization, particularly prior to the expiration of the exclusivity period granted by the Bankruptcy Court;
•
the outcome of the court-supervised bid process with respect to the restructuring of EFH Corp. and EFIH;
•
our ability to obtain Bankruptcy Court approval with respect to our motions in the Chapter 11 Cases, including such approvals not being overturned on appeal or being stayed for any extended period of time;
•
the terms and conditions of any Chapter 11 plan of reorganization that is ultimately approved by the Bankruptcy Court;
•
the extent to which the Chapter 11 Cases cause customers, suppliers and others with whom we have commercial relationships to lose confidence in us, which may make it more difficult for us to obtain and maintain such commercial relationships on competitive terms;
•
difficulties we may face in retaining and motivating our key employees through the bankruptcy process, and difficulties we may face in attracting new employees;
•
the significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations;
•
our ability to remain in compliance with the requirements of the DIP Facilities;
•
our ability to maintain or obtain sufficient financing sources for our operations during the pendency of the Chapter 11 Cases and our ability to obtain sufficient exit financing to fund any Chapter 11 plan of reorganization;
•
limitations on our ability to utilize previously incurred federal net operating losses or alternative minimum tax credits;
•
the actions and decisions of creditors, regulators and other third parties that have an interest in the Chapter 11 Cases or reorganization that may be inconsistent with, or interfere with, our business and/or plans;
•
the duration of the Chapter 11 Cases;
•
the actions and decisions of regulatory authorities relative to any Chapter 11 plan of reorganization;
•
restrictions on our operations due to the terms of our debt agreements, including the 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;
•
the outcome of current or potential litigation regarding intercompany claims and/or derivative claims;
•
prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the US Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Texas Reliability Entity, Inc., the PUCT, the RCT, the NRC, the EPA, the TCEQ, the US Mine Safety and Health Administration and the US Commodity Futures Trading Commission, with respect to, among other things:
◦
allowed prices;
◦
allowed rates of return;
◦
permitted capital structure;
◦
industry, market and rate structure;
◦
purchased power and recovery of investments;
◦
operations of nuclear generation facilities;
◦
operations of fossil fueled generation facilities;
◦
operations of mines;
◦
self-bonding requirements;
◦
acquisition and disposal of assets and facilities;
◦
development, construction and operation of facilities;

67

◦
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 Mercury and Air Toxics Standard, regional haze program implementation and greenhouse gas and other climate change initiatives, and
◦
clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith;
•
legal and administrative proceedings and settlements, including the legal proceedings arising out of the bankruptcy;
•
general industry trends;
•
economic conditions, including the impact of an economic downturn;
•
our ability to collect trade receivables from counterparties;
•
our ability to attract and retain profitable customers;
•
our ability to profitably serve our customers;
•
restrictions on competitive retail pricing;
•
changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;
•
changes in prices of transportation of natural gas, coal, fuel oil and other refined products;
•
changes in the ability of vendors to provide or deliver commodities as needed;
•
changes in market heat rates in the ERCOT electricity market;
•
our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;
•
weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, wars or terrorist or cyber security threats or activities;
•
population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT;
•
changes in business strategy, development plans or vendor relationships;
•
access to adequate transmission facilities to meet changing demands;
•
changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;
•
changes in operating expenses, liquidity needs and capital expenditures;
•
commercial bank market and capital market conditions and the potential impact of disruptions in US and international credit markets;
•
access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets;
•
our ability to generate sufficient cash flow to make interest or adequate protection payments, or refinance, our debt instruments, including the 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;
•
changes in assumptions used to estimate future executive compensation payments;
•
hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;
•
significant changes in critical accounting policies, and
•
actions by credit rating agencies.

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


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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

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect at the end of the current period included in this quarterly report on Form 10-Q. Based on the evaluation performed as of March 31, 2015, our principal executive officer and principal financial officer concluded that due to the material weakness in our internal control over financial reporting related to accounting for deferred income taxes, as previously disclosed in our 2014 Form 10-K, our disclosure controls and procedures were not effective as of March 31, 2015. In light of the material weakness in internal control over financial reporting, management completed substantive procedures, including validating the completeness and accuracy of the underlying data used for accounting for deferred income taxes, prior to filing this quarterly report on Form 10-Q.

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

Previously Reported Material Weakness

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

In response to the material weakness described above, during the three months ended March 31, 2015, we began implementing a plan of remediation to strengthen our overall internal control over accounting for deferred income taxes. The remediation plan includes the following steps:

•
enhancing the formality and rigor of review and documentation related to our deferred income tax reconciliation procedures,

•
implementing additional oversight and monitoring controls over our deferred income tax review processes that are designed to operate at a level of precision to detect an error resulting from a related control failure before it results in a material misstatement of our financial statements, and

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

Management is still evaluating new controls and procedures. Once placed in operation for a sufficient period of time, we will subject these controls and procedures to appropriate tests in order to determine whether they are operating effectively.


69

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

Changes in Internal Control over Financial Reporting

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


70


PART II. OTHER INFORMATION

Item 1.
LEGAL PROCEEDINGS

Reference is made to the discussion in Note 11 to the Financial Statements regarding legal proceedings.


Item 1A.
RISK FACTORS

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

We may not be able to obtain the requisite acceptances of constituencies in the Chapter 11 Cases for, or confirmation by the Bankruptcy Court of, the Plan of Reorganization, and we may not be able to consummate the Plan of Reorganization.

We filed a Plan of Reorganization on April 14, 2015. We may not receive the requisite acceptances of constituencies in the Chapter 11 Cases for the Plan of Reorganization. Even if the requisite acceptances of the Plan of Reorganization are received, the Bankruptcy Court may not confirm the Plan of Reorganization. In addition, completion of the Plan of Reorganization is subject to the satisfaction of certain conditions precedent. There can be no assurance that such acceptance and confirmation will be obtained, or that such conditions will be satisfied, and therefore, that the Plan of Reorganization will be completed.

Furthermore, even if the requisite acceptances of constituencies in the Chapter 11 Cases for the Plan of Reorganization are received and the Plan of Reorganization is confirmed by the Bankruptcy Court, there can be no assurance as to the timing or as to whether the effective date of the reorganization contemplated therein will occur. If the Plan of Reorganization does not receive the requisite acceptances or is not confirmed or if it does receive the requisite acceptances and is confirmed but the effective date of the reorganization contemplated therein does not occur, it may become necessary to amend the Plan of Reorganization to provide for alternative treatment of claims and interests which may result in holders of claims and interests receiving significantly less or no value for their claims and interests in the Chapter 11 Cases. If any modifications to the Plan of Reorganization are material, it may be necessary to re-solicit votes from holders of claims and interests adversely affected by the modifications with respect to such Plan of Reorganization.


Item 4.
MINE SAFETY DISCLOSURES

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


Item 5.
OTHER INFORMATION

None.


71


Item 6.
EXHIBITS

(a)
Exhibits filed or furnished as part of Part II are:
Exhibits
 
Previously Filed With File Number*
 
As
Exhibit
 
 
 
 
 
 
 
 
 
 
 
 
 
(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.
 
 
 
 
 
 
 
 
 
(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 Income – Twelve Months Ended March 31, 2015.
 
 
 
 
 
 
 
 
 
99(b)
 
 
 
 
 
—
 
Texas Competitive Electric Holdings Company LLC Consolidated EBITDA reconciliation for the three and twelve months ended March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
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


72

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: May 7, 2015



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