Attached files
| file | filename |
|---|---|
| EXCEL - IDEA: XBRL DOCUMENT - Energy Future Holdings Corp /TX/ | Financial_Report.xls |
| EX-32.A - CERTIFICATION OF JOHN F. YOUNG - Energy Future Holdings Corp /TX/ | efh-2014630xexhibit32a.htm |
| EX-95.A - MINE SAFETY DISCLOSURES - Energy Future Holdings Corp /TX/ | efh-2014630xexhibit95a.htm |
| EX-31.A - CERTIFICATION OF JOHN F YOUNG - Energy Future Holdings Corp /TX/ | efh-2014630xexhibit31a.htm |
| EX-31.B - CERTIFICATION OF PAUL M. KEGLEVIC - Energy Future Holdings Corp /TX/ | efh-2014630xexhibit31b.htm |
| EX-99.B - TEXAS COMPETITIVE ELECTRIC HOLDINGS COMPANY LLC EBITDA RECONCILIATION - Energy Future Holdings Corp /TX/ | efh-2014630xexhibit99b.htm |
| EX-32.B - CERTIFICATION OF PAUL M. KEGLEVIC - Energy Future Holdings Corp /TX/ | efh-2014630xexhibit32b.htm |
| EX-99.A - TWELVE MONTHS ENDED JUNE 30, 2014 STATEMENT OF INCOME (LOSS) - Energy Future Holdings Corp /TX/ | efh-2014630xexhibit99a.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2014
— OR —
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-12833
Energy Future Holdings Corp.
(Exact name of registrant as specified in its charter)
Texas | 46-2488810 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
1601 Bryan Street, Dallas, TX 75201-3411 | (214) 812-4600 | |
(Address of principal executive offices) (Zip Code) | (Registrant's telephone number, including area code) | |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o Accelerated filer o Non-Accelerated filer x (Do not check if a smaller reporting company)
Smaller reporting company o
Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
At August 1, 2014, there were 1,669,861,383 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.
2013 Form 10-K | EFH Corp.'s Annual Report on Form 10-K for the year ended December 31, 2013, as amended | |
Bankruptcy Filing | Voluntary petitions for relief under Chapter 11 of the US Bankruptcy Code (Bankruptcy Code) in the US Bankruptcy Court for the District of Delaware (Bankruptcy Court) filed on April 29, 2014 by the Debtors. | |
CAIR | Clean Air Interstate Rule | |
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 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, vacated by the US Court of Appeals for the District of Columbia Circuit in August 2012 and remanded by the US Supreme Court to the D.C. Circuit Court for further proceedings consistent with the US Supreme Court's opinion (see Note 9 to Financial Statements) | |
DIP Facilities | Refers, collectively, to TCEH's debtor-in-possession financing and EFIH's debtor-in-possession financing. See Note 5 to 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 | |
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 | |
Effective Date | the effective date of the Debtors' plan of reorganization | |
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 $503 million principal amount of 6.875% Senior Secured First Lien Notes and $3.482 billion principal amount of 10.000% Senior Secured First Lien Notes. | |
EFIH Second Lien Notes | Refers, collectively, to EFIH's and EFIH Finance's $406 million principal amount of 11% Senior Secured Second Lien Notes and $1.75 billion principal amount of 1.75% Senior Secured Second Lien Notes. | |
EPA | US Environmental Protection Agency | |
ii
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 | |
PUCT | Public Utility Commission of Texas | |
iii
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 | |
RSA | Restructuring Support and Lock-Up Agreement | |
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 Demand Notes | Refers to certain loans from TCEH to EFH Corp. in the form of demand notes to finance EFH Corp. debt principal and interest payments and, until April 2011, other general corporate purposes of EFH Corp. that were guaranteed on a senior unsecured basis by EFCH and EFIH and were settled by EFH Corp. in January 2013. | |
TCEH 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 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 | |
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 | |
iv
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 June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
(millions of dollars) | |||||||||||||||
Operating revenues | $ | 1,406 | $ | 1,419 | $ | 2,924 | $ | 2,679 | |||||||
Fuel, purchased power costs and delivery fees | (656 | ) | (687 | ) | (1,388 | ) | (1,323 | ) | |||||||
Net gain (loss) from commodity hedging and trading activities | 27 | 168 | (192 | ) | (29 | ) | |||||||||
Operating costs | (242 | ) | (266 | ) | (455 | ) | (496 | ) | |||||||
Depreciation and amortization | (333 | ) | (345 | ) | (663 | ) | (695 | ) | |||||||
Selling, general and administrative expenses | (175 | ) | (177 | ) | (375 | ) | (338 | ) | |||||||
Franchise and revenue-based taxes | (18 | ) | (16 | ) | (36 | ) | (33 | ) | |||||||
Other income (Note 15) | 6 | 7 | 14 | 14 | |||||||||||
Other deductions (Note 15) | (23 | ) | (1 | ) | (23 | ) | (4 | ) | |||||||
Interest income | — | — | 1 | 1 | |||||||||||
Interest expense and related charges (Note 8) | (571 | ) | (598 | ) | (1,436 | ) | (1,382 | ) | |||||||
Reorganization items (Note 6) | (665 | ) | — | (665 | ) | — | |||||||||
Loss before income taxes and equity in earnings of unconsolidated subsidiaries | (1,244 | ) | (496 | ) | (2,294 | ) | (1,606 | ) | |||||||
Income tax benefit | 398 | 351 | 759 | 825 | |||||||||||
Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 3) | 72 | 74 | 152 | 141 | |||||||||||
Net loss | $ | (774 | ) | $ | (71 | ) | $ | (1,383 | ) | $ | (640 | ) | |||
See Notes to Financial Statements.
CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
(millions of dollars) | |||||||||||||||
Net loss | $ | (774 | ) | $ | (71 | ) | $ | (1,383 | ) | $ | (640 | ) | |||
Other comprehensive income (loss), net of tax effects: | |||||||||||||||
Effects related to pension and other retirement benefit obligations (net of tax benefit of $—, $—, $1 and $1) | (2 | ) | (1 | ) | (3 | ) | (3 | ) | |||||||
Cash flow hedges derivative value net loss related to hedged transactions recognized during the period (net of tax benefit of $—, $1, $— and $2) | 1 | 2 | 1 | 4 | |||||||||||
Net effects related to Oncor — reported in equity in earnings of unconsolidated subsidiaries (net of tax benefit of $— in all periods) | 1 | — | 1 | 1 | |||||||||||
Total other comprehensive income (loss) | — | 1 | (1 | ) | 2 | ||||||||||
Comprehensive loss | $ | (774 | ) | $ | (70 | ) | $ | (1,384 | ) | $ | (638 | ) | |||
See Notes to Financial Statements.
1
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) | |||||||
Six Months Ended June 30, | |||||||
2014 | 2013 | ||||||
(millions of dollars) | |||||||
Cash flows — operating activities: | |||||||
Net loss | $ | (1,383 | ) | $ | (640 | ) | |
Adjustments to reconcile net loss to cash used in operating activities: | |||||||
Depreciation and amortization | 742 | 777 | |||||
Deferred income tax benefit, net | (666 | ) | (565 | ) | |||
Income tax benefit due to IRS audit resolution | — | (267 | ) | ||||
Fees paid for DIP Facilities (Note 5) (reported as financing activities) | 180 | — | |||||
Unrealized net loss from mark-to-market valuations of commodity positions | 549 | 529 | |||||
Unrealized net gain from mark-to-market valuations of interest rate swaps (Note 8) | (1,303 | ) | (489 | ) | |||
Liability adjustment arising from termination of interest rate swaps (Note 12) | 278 | — | |||||
Noncash realized loss on termination of interest rate swaps (Note 8) | 1,237 | — | |||||
Noncash realized gain on termination of natural gas hedging positions (Note 12) | (117 | ) | — | ||||
Loss on exchange and settlement of EFIH First Lien Notes (Note 5) | 108 | — | |||||
Interest expense on toggle notes payable in additional principal (Note 8) | 65 | 83 | |||||
Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 8) | 72 | 119 | |||||
Equity in earnings of unconsolidated subsidiaries | (152 | ) | (141 | ) | |||
Distributions of earnings from unconsolidated subsidiaries | 77 | 80 | |||||
Asset write-downs (Note 15) | 21 | — | |||||
Bad debt expense (Note 15) | 20 | 13 | |||||
Accretion expense related primarily to mining reclamation obligations (Note 15) | 12 | 16 | |||||
Other, net | 2 | 2 | |||||
Changes in operating assets and liabilities: | |||||||
Margin deposits, net | (300 | ) | (140 | ) | |||
Accrued interest | 509 | (46 | ) | ||||
Other operating assets and liabilities, including liabilities subject to compromise | (133 | ) | 48 | ||||
Cash used in operating activities | (182 | ) | (621 | ) | |||
Cash flows — financing activities: | |||||||
Proceeds from DIP Facilities before fees paid (Note 5) | 4,989 | — | |||||
Fees paid for DIP Facilities (Note 5) | (180 | ) | — | ||||
Repayments/repurchases of debt | (2,524 | ) | (81 | ) | |||
Net borrowings under accounts receivable securitization program | — | 37 | |||||
Contributions from noncontrolling interests | 1 | 2 | |||||
Debt amendment, exchange and issuance costs and discounts, including third-party fees expensed | — | (6 | ) | ||||
Other, net | — | (4 | ) | ||||
Cash provided by (used in) financing activities | 2,286 | (52 | ) | ||||
2
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) | |||||||
Six Months Ended June 30, | |||||||
2014 | 2013 | ||||||
(millions of dollars) | |||||||
Cash flows — investing activities: | |||||||
Capital expenditures | $ | (189 | ) | $ | (274 | ) | |
Nuclear fuel purchases | (36 | ) | (27 | ) | |||
Acquisition of combustion turbine trust interest | — | (40 | ) | ||||
Restricted cash used to settle TCEH Demand Notes (Note 13) | — | 680 | |||||
Increase in restricted cash related to TCEH DIP Facility (Note 5) | (53 | ) | — | ||||
Reduction of restricted cash related to TCEH Letter of Credit Facility (Note 7) | 363 | — | |||||
Other changes in restricted cash | — | (5 | ) | ||||
Proceeds from sales of environmental allowances and credits | 2 | — | |||||
Purchases of environmental allowances and credits | (9 | ) | (10 | ) | |||
Proceeds from sales of nuclear decommissioning trust fund securities | 85 | 105 | |||||
Investments in nuclear decommissioning trust fund securities | (93 | ) | (112 | ) | |||
Other, net | 11 | 6 | |||||
Cash provided by investing activities | 81 | 323 | |||||
Net change in cash and cash equivalents | 2,185 | (350 | ) | ||||
Cash and cash equivalents — beginning balance | 1,217 | 1,913 | |||||
Cash and cash equivalents — ending balance | $ | 3,402 | $ | 1,563 | |||
See Notes to Financial Statements.
3
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) | |||||||
June 30, 2014 | December 31, 2013 | ||||||
(millions of dollars) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 3,402 | $ | 1,217 | |||
Restricted cash (Note 15) | 4 | 949 | |||||
Trade accounts receivable — net | 772 | 718 | |||||
Inventories (Note 15) | 442 | 399 | |||||
Commodity and other derivative contractual assets (Note 12) | 231 | 851 | |||||
Accumulated deferred income taxes | 98 | 105 | |||||
Margin deposits related to commodity positions | 94 | 93 | |||||
Other current assets | 104 | 135 | |||||
Total current assets | 5,147 | 4,467 | |||||
Restricted cash (Note 15) | 635 | — | |||||
Receivable from unconsolidated subsidiary (Note 13) | 851 | 838 | |||||
Investment in unconsolidated subsidiary (Note 3) | 6,035 | 5,959 | |||||
Other investments (Note 15) | 945 | 891 | |||||
Property, plant and equipment — net (Note 15) | 17,317 | 17,791 | |||||
Goodwill (Note 4) | 3,952 | 3,952 | |||||
Identifiable intangible assets — net (Note 4) | 1,627 | 1,679 | |||||
Commodity and other derivative contractual assets (Note 12) | 9 | 4 | |||||
Other noncurrent assets (Note 7) | 80 | 865 | |||||
Total assets | $ | 36,598 | $ | 36,446 | |||
LIABILITIES AND EQUITY | |||||||
Current liabilities: | |||||||
Notes, loans and other debt, including $2,054 of borrowings under revolving credit facility (Note 7) | $ | — | $ | 40,252 | |||
Trade accounts payable | 380 | 401 | |||||
Net payables due to unconsolidated subsidiary (Note 13) | 161 | 128 | |||||
Commodity and other derivative contractual liabilities (Note 12) | 241 | 1,355 | |||||
Margin deposits related to commodity positions | 3 | 302 | |||||
Accrued interest (Notes 7 and 8) | 110 | 564 | |||||
Other current liabilities (a) | 390 | 504 | |||||
Total current liabilities | 1,285 | 43,506 | |||||
Borrowings under debtor-in-possession credit facilities (Note 5) | 6,825 | — | |||||
Long-term debt, less amounts due currently (b) | 153 | — | |||||
Liabilities subject to compromise (Note 7) | 37,458 | — | |||||
Commodity and other derivative contractual liabilities (Note 12) | 2 | — | |||||
Accumulated deferred income taxes | 2,757 | 3,433 | |||||
Other noncurrent liabilities and deferred credits (Note 15) | 2,754 | 2,762 | |||||
Total liabilities | 51,234 | 49,701 | |||||
Commitments and Contingencies (Note 9) | |||||||
4
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) | |||||||
June 30, 2014 | December 31, 2013 | ||||||
(millions of dollars) | |||||||
Equity (Note 10): | |||||||
EFH Corp. shareholders' equity | $ | (14,636 | ) | $ | (13,256 | ) | |
Noncontrolling interests in subsidiaries | — | 1 | |||||
Total equity | (14,636 | ) | (13,255 | ) | |||
Total liabilities and equity | $ | 36,598 | $ | 36,446 | |||
_______________
(a) | Balance at June 30, 2014 includes $36 million of current portion of debt described in (b) below. |
(b) | Consists of a non-Debtor $38 million principal amount of debt related to a building financing (plus $8 million of unamortized fair value premium), $49 million principal amount of debt approved by the Bankruptcy Court for repayment (less $4 million of unamortized fair value discount), $23 million principal amount of debt issued by a trust and secured by assets held by the trust (less $3 million of unamortized discount) and $42 million of capitalized lease obligations. |
See Notes to Financial Statements.
5
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 sales. 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.
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 14 for further information concerning reportable business segments.
Bankruptcy Filing
As discussed further in Note 2, 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). See Note 5 for discussion of debtor-in-possession financing.
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Basis of Presentation, Including Application of Bankruptcy Accounting
The condensed consolidated financial statements have been prepared as if EFH Corp. is a going concern and reflect the application of ASC 852-10, Reorganizations. During the pendency of the Bankruptcy Filing, 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 852-10 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, as well as expenses and income directly associated with the Chapter 11 Cases. See Notes 6 and 7 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 2013 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.
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2. BANKRUPTCY FILING
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 Bankruptcy Filing, 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 (see Note 12). 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.
Restructuring Support and Lock-Up Agreement (RSA)
As previously disclosed, after a series of discussions with certain creditors that began in 2013 and in anticipation of the Bankruptcy Filing, on April 29, 2014, the Debtors entered into a Restructuring Support and Lock-Up Agreement (RSA) with various stakeholders (Consenting Parties) in order to effect an agreed upon restructuring of the Debtors through a pre-arranged Chapter 11 plan of reorganization.
On July 24, 2014, pursuant to the RSA, each of EFH Corp., EFIH, EFCH, TCEH, EFIH Finance, Inc. and TCEH Finance Inc. provided a notice of termination of the RSA in accordance with its terms to the Consenting Parties. The RSA termination became effective on July 31, 2014.
The Debtors believe that the RSA provided significant benefit to the Debtors, including, without limitation, (a) enabling the TCEH Debtors to obtain the support of holders of the TCEH first lien secured claims for the TCEH debtor-in-possession financing facility and (b) providing a framework for the restructuring transactions involving EFH Corp. and EFIH described in the RSA, which prompted competing proposals (including, among others, an alternative proposal from NextEra Energy, Inc.).
Each of the Debtors remain committed to the tax-free spin of TCEH and its subsidiaries described in the RSA. Moreover, the TCEH first lien creditors who were party to the RSA have advised the Debtors that, notwithstanding the RSA termination, they intend to continue to work cooperatively with the Debtors and other parties in interest to pursue transactions that can be achieved expeditiously, including a possible tax-free spin of the TCEH Debtors, which will maximize the value of the TCEH Debtors' estates and resolve the Chapter 11 Cases.
In cooperation with various stakeholders, the Debtors have focused, and will continue to focus, on formulating and implementing an effective and efficient plan of reorganization for each of the Debtors under Chapter 11 of the Bankruptcy Code that maximizes enterprise value. The Debtors intend to conduct a court supervised bid process with respect to the restructuring of EFH Corp. and EFIH to maximize their respective enterprise values for all stakeholders. In addition, EFH Corp. and EFIH intend to negotiate with each party that has submitted or does submit a bid with respect to the reorganization of EFH Corp. and EFIH.
EFIH Settlement of First Lien Notes and Related Exchanges
Pursuant to the RSA, certain holders of EFIH First Lien Notes agreed to voluntary settlements of such notes. In June 2014, the Bankruptcy Court issued an order approving this settlement, the EFIH DIP Facility and the settlement of remaining EFIH First Lien Notes, all of which were completed as described in Note 5.
The RSA termination does not impact or cancel the EFIH First Lien Notes settlement since such settlement was completed prior to the RSA termination. See Note 9 for a discussion of litigation regarding alleged makewhole claims of holders of EFIH First Lien Notes in connection with the EFIH First Lien Notes settlement.
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Private Letter Ruling
Pursuant to the RSA, on June 10, 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, (ii) the transfer by the Debtors to Reorganized TCEH of certain operating 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. Notwithstanding the termination of the RSA, the Debtors intend to continue to pursue the Private Letter Ruling in connection with any Chapter 11 plan of reorganization that is ultimately proposed.
Operation and Implications of the Chapter 11 Cases
The accompanying consolidated financial statements contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Our ability to continue as a going concern is contingent upon our ability to comply with the financial and other covenants contained in the debtor-in-possession financing (DIP Facilities, described in Note 5), the Bankruptcy Court's approval of the Chapter 11 plan of reorganization ultimately proposed by the Debtors and our ability to successfully implement such Chapter 11 plan and obtain new financing, among other factors. As a result of the Chapter 11 Cases, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession under Chapter 11, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Facilities), for amounts other than those reflected in the accompanying consolidated financial statements.
In general, the Debtors have received final bankruptcy court orders with respect to "first day motions" that allow the Debtors to operate their businesses in the ordinary course of business, 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 programs at our retail electricity sales 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 June 2014, the Bankruptcy Court issued orders approving the TCEH and EFIH DIP Facilities and the exchange and settlement of the EFIH First Lien Notes as described in Note 5.
Pre-Petition Claims
Holders of pre-petition claims will be required to file proofs of claims by the "bar dates" 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 has not yet established the bar date. Differences between liability amounts recorded by the company as liabilities subject to compromise and claims filed by creditors will be investigated and, if necessary, the Bankruptcy Court will make a final determination of the allowable claim. Differences between those final allowed claims and the liabilities recorded in the condensed consolidated balance sheet will be recognized as reorganization items in our condensed statement 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. 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 the company’s financial statements.
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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.
Our balance sheet includes assets and liabilities of VIEs that meet the consolidation standards. The maximum exposure to loss from our interests in VIEs does not exceed our carrying value.
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.
Assets and liabilities of other consolidated VIEs are immaterial. The assets of our consolidated VIEs can only be used to settle the obligations of the VIE, and the creditors of our consolidated VIEs do not have recourse to our assets to settle the obligations of the VIE.
Non-Consolidation of Oncor and Oncor Holdings
Our investment in unconsolidated subsidiary as presented in the condensed consolidated balance sheets totaled $6.035 billion and $5.959 billion at June 30, 2014 and December 31, 2013, 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 27% of Oncor Holdings' consolidated operating revenues for the six months ended June 30, 2014 and 2013, respectively.
See Note 13 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 $77 million and $80 million for the six months ended June 30, 2014 and 2013, respectively. Distributions may not be paid except to the extent Oncor maintains a required regulatory capital structure as discussed below. At June 30, 2014, $108 million was eligible to be distributed to Oncor's members after taking into account the regulatory capital structure limit, of which approximately 80% relates to our ownership interest in Oncor. The boards of directors of each of Oncor and Oncor Holdings can withhold distributions to the extent the applicable board determines in good faith that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings.
Oncor's distributions are limited by its regulatory capital structure, which is required to be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. At June 30, 2014, Oncor's regulatory capitalization ratio, as defined by the PUCT, was 59.3% debt and 40.7% 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).
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As a result of the Bankruptcy Filing, Oncor had credit risk exposure to trade accounts receivable from TCEH, which related to delivery services provided by Oncor to TCEH's retail electricity operations. At the Petition Date, these accounts receivable totaled $109 million. In June 2014, the Bankruptcy Court authorized the Debtors to pay all pre-petition delivery charges due Oncor, and such amounts were paid in full.
Oncor has additional credit risk exposure to EFH Corp. and certain of its subsidiaries totaling approximately $20 million at the Petition Date, including an $18 million federal income tax receivable from EFH Corp. under the Federal and State Income Tax Allocation Agreement. Additional income tax receivable amounts may arise in the normal course under that agreement.
Because Oncor would not seek regulatory rate recovery for such credit losses, Oncor's earnings could be reduced by the amount (after-tax) of any nonpayment by EFH Corp. and its subsidiaries of amounts owed to Oncor.
Oncor has not established any reserves related to this exposure.
Oncor Holdings Financial Statements — Condensed statements of consolidated income of Oncor Holdings and its subsidiaries for the three and six months ended June 30, 2014 and 2013 are presented below:
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Operating revenues | $ | 912 | $ | 857 | $ | 1,829 | $ | 1,674 | |||||||
Operation and maintenance expenses | (353 | ) | (307 | ) | (698 | ) | (605 | ) | |||||||
Depreciation and amortization | (210 | ) | (202 | ) | (420 | ) | (401 | ) | |||||||
Taxes other than income taxes | (106 | ) | (101 | ) | (215 | ) | (203 | ) | |||||||
Other income | 3 | 5 | 7 | 10 | |||||||||||
Other deductions | (4 | ) | (4 | ) | (7 | ) | (8 | ) | |||||||
Interest income | 1 | 1 | 2 | 2 | |||||||||||
Interest expense and related charges | (89 | ) | (95 | ) | (177 | ) | (189 | ) | |||||||
Income before income taxes | 154 | 154 | 321 | 280 | |||||||||||
Income tax expense | (63 | ) | (61 | ) | (129 | ) | (102 | ) | |||||||
Net income | 91 | 93 | 192 | 178 | |||||||||||
Net income attributable to noncontrolling interests | (19 | ) | (19 | ) | (40 | ) | (37 | ) | |||||||
Net income attributable to Oncor Holdings | $ | 72 | $ | 74 | $ | 152 | $ | 141 | |||||||
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Assets and liabilities of Oncor Holdings at June 30, 2014 and December 31, 2013 are presented below:
June 30, 2014 | December 31, 2013 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 6 | $ | 28 | |||
Restricted cash | 49 | 52 | |||||
Trade accounts receivable — net | 454 | 385 | |||||
Trade accounts and other receivables from affiliates | 140 | 135 | |||||
Income taxes receivable from EFH Corp. | 36 | 16 | |||||
Inventories | 75 | 65 | |||||
Accumulated deferred income taxes | 22 | 32 | |||||
Prepayments and other current assets | 89 | 82 | |||||
Total current assets | 871 | 795 | |||||
Restricted cash | 16 | 16 | |||||
Other investments | 93 | 91 | |||||
Property, plant and equipment — net | 12,163 | 11,902 | |||||
Goodwill | 4,064 | 4,064 | |||||
Regulatory assets — net | 1,156 | 1,324 | |||||
Other noncurrent assets | 76 | 71 | |||||
Total assets | $ | 18,439 | $ | 18,263 | |||
LIABILITIES | |||||||
Current liabilities: | |||||||
Short-term borrowings | $ | 822 | $ | 745 | |||
Long-term debt due currently | 635 | 131 | |||||
Trade accounts payable — nonaffiliates | 141 | 178 | |||||
Income taxes payable to EFH Corp. | 14 | 23 | |||||
Accrued taxes other than income | 99 | 169 | |||||
Accrued interest | 94 | 95 | |||||
Other current liabilities | 145 | 135 | |||||
Total current liabilities | 1,950 | 1,476 | |||||
Accumulated deferred income taxes | 1,885 | 1,905 | |||||
Long-term debt, less amounts due currently | 5,065 | 5,381 | |||||
Other noncurrent liabilities and deferred credits | 1,759 | 1,822 | |||||
Total liabilities | $ | 10,659 | $ | 10,584 | |||
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. There were no changes to the goodwill balance for the three and six months ended June 30, 2014 and 2013. None of the goodwill is being deducted for tax purposes.
Goodwill before impairment charges | $ | 18,342 | |
Accumulated noncash impairment charges | (14,390 | ) | |
Balance at June 30, 2014 and December 31, 2013 | $ | 3,952 | |
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Identifiable Intangible Assets
Identifiable intangible assets, including amounts that arose in connection with accounting for the Merger, are comprised of the following:
June 30, 2014 | December 31, 2013 | |||||||||||||||||||||||
Identifiable Intangible Asset | Gross Carrying Amount | Accumulated Amortization | Net | Gross Carrying Amount | Accumulated Amortization | Net | ||||||||||||||||||
Retail customer relationship | $ | 463 | $ | 413 | $ | 50 | $ | 463 | $ | 402 | $ | 61 | ||||||||||||
Favorable purchase and sales contracts | 352 | 151 | 201 | 352 | 139 | 213 | ||||||||||||||||||
Capitalized in-service software | 357 | 208 | 149 | 355 | 192 | 163 | ||||||||||||||||||
Environmental allowances and credits | 211 | 27 | 184 | 209 | 20 | 189 | ||||||||||||||||||
Mining development costs | 163 | 82 | 81 | 156 | 69 | 87 | ||||||||||||||||||
Total identifiable intangible assets subject to amortization | $ | 1,546 | $ | 881 | 665 | $ | 1,535 | $ | 822 | 713 | ||||||||||||||
Retail trade name (not subject to amortization) | 955 | 955 | ||||||||||||||||||||||
Mineral interests (not currently subject to amortization) | 7 | 11 | ||||||||||||||||||||||
Total identifiable intangible assets | $ | 1,627 | $ | 1,679 | ||||||||||||||||||||
Amortization expense related to identifiable intangible assets (including income statement line item) consisted of:
Identifiable Intangible Asset | Income Statement Line | Segment | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||
Retail customer relationship | Depreciation and amortization | Competitive Electric | $ | 6 | $ | 6 | $ | 11 | $ | 12 | ||||||||||
Favorable purchase and sales contracts | Operating revenues/fuel, purchased power costs and delivery fees | Competitive Electric | 7 | 7 | 12 | 13 | ||||||||||||||
Capitalized in-service software | Depreciation and amortization | Competitive Electric and Corporate and Other | 11 | 11 | 23 | 21 | ||||||||||||||
Environmental allowances and credits | Fuel, purchased power costs and delivery fees | Competitive Electric | 3 | 3 | 7 | 6 | ||||||||||||||
Mining development costs | Depreciation and amortization | Competitive Electric | 8 | 7 | 17 | 15 | ||||||||||||||
Total amortization expense (a) | $ | 35 | $ | 34 | $ | 70 | $ | 67 | ||||||||||||
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(a) | Amounts recorded in depreciation and amortization totaled $25 million and $24 million for the three months ended June 30, 2014 and 2013, respectively, and $51 million and $48 million for the six months ended June 30, 2014 and 2013, respectively. |
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 | |||
2014 | $ | 133 | ||
2015 | $ | 123 | ||
2016 | $ | 100 | ||
2017 | $ | 77 | ||
2018 | $ | 56 | ||
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5. | DEBTOR-IN-POSSESSION BORROWING FACILITIES |
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 facility initially provided for an additional $1.1 billion RCT Delayed Draw Letter of Credit commitment that has since been terminated as described below. 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 Facilities and related available capacity at June 30, 2014 are presented below. Borrowings are reported in the condensed consolidated balance sheet as borrowings under debtor-in-possession credit facilities.
June 30, 2014 | ||||||||||||
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 | — | 747 | |||||||||
Total TCEH DIP Facility | $ | 3,375 | $ | 1,950 | $ | 747 | ||||||
___________
(a) | Facility used for general corporate purposes. No amounts were borrowed at June 30 or July 31, 2014. 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 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 June 30, 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, $747 million is reported as cash and cash equivalents and $53 million is reported as restricted cash, which amount represents outstanding letters of credit at June 30, 2014.
Amounts borrowed under the TCEH DIP Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 3%. At June 30, 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.
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 TCEH DIP Credit Agreement 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.
In June 2014, the RCT agreed to accept a collateral bond from TCEH of up to $1.1 billion, as a substitute for its self-bond, to secure mining land reclamation obligations. The collateral bond is a $1.1 billion carve-out from the super-priority liens under the TCEH DIP Facility that will enable the RCT to be paid before the TCEH DIP Facility lenders. As a result, in July 2014, TCEH terminated a $1.1 billion RCT Delayed Draw Letter of Credit commitment included in the original DIP facility.
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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 and EFIH First Lien Notes Settlement — 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, all of which was utilized as of June 30, 2014 as follows:
• | $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; |
• | $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 |
• | Remaining borrowings under the facility, net of fees, of $1.038 billion are held as cash and cash equivalents. |
The exchange and settlement of the EFIH First Lien Notes resulted in a loss of $108 million, reported in reorganization items, which represents the excess of the principal amounts of debt issued, cash repayments and deferred financing costs associated with the exchanged and settled debt over the carrying value of the exchanged and settled debt and related accrued interest.
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 June 30, 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.
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. The Oncor Ring-Fenced Entities are not restricted subsidiaries for purposes of the EFIH DIP Facility.
15
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.
6. | 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 852-10, 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 since the Petition Date as reported in the condensed statements of consolidated income (loss):
Post-Petition Period Through June 30, 2014 | |||
Liability adjustment arising from termination of interest rate swaps (Note 12) | $ | 278 | |
Fees associated with completion of TCEH and EFIH DIP Facilities | 185 | ||
Loss on exchange and settlement of EFIH First Lien Notes (Note 5) | 108 | ||
Expenses related to legal advisory and representation services | 41 | ||
Expenses related to other professional consulting and advisory services | 50 | ||
Other | 3 | ||
Total reorganization items | $ | 665 | |
7. | LIABILITIES SUBJECT TO COMPROMISE |
The amounts classified as liabilities subject to compromise (LSTC) reflect the company's estimate of pre-petition liabilities 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 secured by letters of credit or cash deposits. The following table presents LSTC as reported in the condensed consolidated balance sheets at June 30, 2014:
June 30, 2014 | |||
Notes, loans and other debt per the following table | $ | 35,127 | |
Accrued interest on notes, loans and other debt | 804 | ||
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements (Note 12) | 1,235 | ||
Trade accounts payable and accrued liabilities | 292 | ||
Total liabilities subject to compromise | $ | 37,458 | |
16
Pre-Petition Notes, Loans and Other Debt Reported as Liabilities Subject to Compromise
All amounts of pre-petition notes, loans and other debt reported as liabilities subject to compromise represent principal amounts.
June 30, 2014 | December 31, 2013 | ||||||
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 | |||||
8.82% Building Financing due semiannually through February 11, 2022 (b) | — | 46 | |||||
Unamortized fair value premium related to Building Financing (b)(c) | — | 9 | |||||
Unamortized fair value discount (c) | (118 | ) | (121 | ) | |||
Total EFH Corp. | 529 | 581 | |||||
EFIH | |||||||
6.875% Fixed Senior Secured First Lien Notes due August 15, 2017 (d) | — | 503 | |||||
10% Fixed Senior Secured First Lien Notes due December 1, 2020 (d) | — | 3,482 | |||||
11% Fixed Senior Secured Second Lien Notes due October 1, 2021 | 406 | 406 | |||||
11.75% Fixed Senior Secured Second Lien Notes due March 1, 2022 | 1,750 | 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 | 284 | |||||
Unamortized discount | (121 | ) | (146 | ) | |||
Total EFIH | 3,846 | 7,847 | |||||
EFCH | |||||||
9.58% Fixed Notes due in annual installments through December 4, 2019 (b) | — | 29 | |||||
8.254% Fixed Notes due in quarterly installments through December 31, 2021 (b) | — | 34 | |||||
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 (c) | (1 | ) | (6 | ) | |||
Total EFCH | 8 | 66 | |||||
TCEH | |||||||
Senior Secured Facilities: | |||||||
TCEH Floating Rate Term Loan Facilities due October 10, 2014 | 3,809 | 3,809 | |||||
TCEH Floating Rate Letter of Credit Facility due October 10, 2014 | 42 | 42 | |||||
TCEH Floating Rate Revolving Credit Facility due October 10, 2016 | 2,054 | 2,054 | |||||
TCEH Floating Rate Term Loan Facilities due October 10, 2017 (a) | 15,691 | 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 | |||||
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June 30, 2014 | December 31, 2013 | ||||||
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 | |||||
Floating Rate Series 2001D-2 due May 1, 2033 (e) | — | 97 | |||||
Floating Rate Taxable Series 2001I due December 1, 2036 (e) | 1 | 62 | |||||
Floating Rate Series 2002A due May 1, 2037 (e) | — | 45 | |||||
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 (c) | (103 | ) | (105 | ) | |||
Other: | |||||||
7.48% Fixed Secured Facility Bonds with amortizing payments through January 2017 (b) | — | 36 | |||||
7.46% Fixed Secured Facility Bonds with amortizing payments through January 2015 (b) | — | 4 | |||||
Capitalized lease obligations (b) | — | 52 | |||||
Other | 3 | 3 | |||||
Unamortized discount | (91 | ) | (103 | ) | |||
Total TCEH | 31,477 | 31,758 | |||||
Deferred debt issuance and extension costs (f) | (733 | ) | — | ||||
Total EFH Corp. consolidated notes, loans and other debt | $ | 35,127 | $ | 40,252 | |||
___________
(a) | Excludes the following principal amounts of debt held by EFIH or EFH Corp. (parent entity) and eliminated in consolidation. |
June 30, 2014 | December 31, 2013 | ||||||
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) | Amounts classified as debt in the condensed consolidated balance sheet at June 30, 2014. See (a) and (b) notes to condensed consolidated balance sheet. |
(c) | Amount represents unamortized fair value adjustments recorded under purchase accounting. |
(d) | The EFIH First Lien Notes were exchanged or settled in June 2014 (see Note 5). |
(e) | These bonds were tendered and settled through letter of credit draws. |
(f) | Deferred debt issuance and extension costs were reported in other noncurrent assets at December 31, 2013. |
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Information Regarding Significant Pre-Petition Debt
TCEH elected not to make interest payments due in April 2014 totaling $123 million on certain debt obligations.
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 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 that have a maturity date in October 2014 with interest at LIBOR plus 3.50%; |
• | $15.691 billion of TCEH Term Loan Facilities that have a maturity date in October 2017 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 that has a maturity date in October 2014 with interest at LIBOR plus 3.50%; |
• | $1.020 billion of cash borrowed under the TCEH Letter of Credit Facility that has a maturity date in October 2017 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), 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.
Borrowings under the TCEH Letter of Credit Facility have been recorded by TCEH as restricted cash that supports issuances of letters of credit. At June 30, 2014, the restricted cash totaled $582 million and supports $556 million in letters of credit outstanding. In the first quarter 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 through the second quarter 2014, the subsidiary drew on the letter of credit in the amount of $138 million to settle amounts receivable from TCEH. Year to date June 30, 2014, $225 million of letters of credit have been drawn upon by unaffiliated counterparties to settle amounts receivable from TCEH, including $203 million related to pollution control revenue bonds that were tendered.
TCEH 11.5% Senior Secured Notes — The principal amount of the TCEH 11.5% Senior Secured Notes totals $1.750 billion. The notes have a maturity date in October 2020, with interest at a fixed rate of 11.5% per annum. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The notes are secured, on a first-priority basis, by security interests in all of the assets of TCEH, and the guarantees are secured on a first-priority basis by all of the assets and equity interests held by the Guarantors, in each case, to the extent such assets and equity interests secure obligations under the TCEH Senior Secured Facilities (the TCEH Collateral), subject to certain exceptions and permitted liens.
The notes are (i) senior obligations and rank equally in right of payment with all senior indebtedness of TCEH, (ii) senior in right of payment to all existing or future unsecured and second-priority secured debt of TCEH to the extent of the value of the TCEH Collateral and (iii) senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.
The guarantees of the TCEH Senior Secured Notes by the Guarantors are effectively senior to any unsecured and second-priority debt of the Guarantors to the extent of the value of the TCEH Collateral. The guarantees are effectively subordinated to all debt of the Guarantors secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt.
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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. These notes have a maturity date in April 2021, 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 (which owns 100% of TCEH), and by each subsidiary that guarantees the TCEH Senior Secured Facilities. The TCEH 10.25% Notes have a maturity date in November 2015, with interest at a fixed rate of 10.25% per annum. The TCEH Toggle Notes have a maturity date in November 2016, with 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 June 30, 2014 as the notes were exchanged or settled in June 2014 as discussed in Note 5. These notes had a maturity date in August 2017, with 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).
The EFIH 6.875% Notes were senior obligations of EFIH and ranked equally in right of payment with all senior indebtedness of EFIH and were senior in right of payment to any future subordinated indebtedness of EFIH. The EFIH 6.875% Notes were effectively senior to all second lien and unsecured indebtedness of EFIH, to the extent of the value of the EFIH Collateral, and were effectively subordinated to any indebtedness of EFIH secured by assets of EFIH other than the EFIH Collateral, to the extent of the value of such assets. Furthermore, the EFIH 6.875% Notes were structurally subordinated to all indebtedness and other liabilities of EFIH's subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries. The holders of the EFIH 6.875% Notes voted as a separate class from the holders of the EFIH 10% Notes.
The EFIH 6.875% 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 6.875% 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 6.875% Notes. Because the exchange offer was not completed, the annual interest rate on the EFIH 6.875% Notes increased by 25 basis points (to 7.125%) on August 15, 2013 and by an additional 25 basis points (to 7.375%) on November 15, 2013.
20
EFIH 10% Senior Secured First Lien Notes — There were no principal amounts of the EFIH 10% Notes outstanding at June 30, 2014 as the notes were exchanged or settled in June 2014 as discussed in Note 5. The notes had a maturity date in December 2020, with 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.
The EFIH 10% Notes were senior obligations of EFIH and ranked equally in right of payment with all existing and future senior indebtedness of EFIH, including the EFIH 6.875% Notes. The EFIH 10% Notes had substantially the same terms as the EFIH 6.875% Notes. The holders of the EFIH 10% Notes voted as a separate class from the holders of the EFIH 6.875% Notes.
The $1.302 billion of EFIH 10% Notes issued in January 2013 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 10% 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 10% Notes. Because the exchange offer was not completed, the annual interest rate on the EFIH 10% Notes increased by 25 basis points (to 10.25%) on January 30, 2014 and by an additional 25 basis points (to 10.50%) on April 30, 2014.
EFIH 11% Senior Secured Second Lien Notes — The principal amount of the EFIH 11% Notes totals $406 million. The notes have a maturity date in October 2021, 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.
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 $1.750 billion. These notes have a maturity date in March 2022, 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.
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%) on February 6, 2013 and by an additional 25 basis points (to 12.25%) on May 6, 2013.
EFIH 11.25%/12.25% Senior Toggle Notes — The principal amount of the EFIH Toggle Notes totals $1.566 billion. These notes have a maturity date in December 2018, 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%) on December 6, 2013 and by an additional 25 basis points (to 11.75%) on March 6, 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 have a maturity date in November 2017, with 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.
21
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 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.
8. | INTEREST EXPENSE AND RELATED CHARGES |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Interest paid/accrued on debtor-in-possession financing | $ | 14 | $ | — | $ | 14 | $ | — | |||||||
Adequate protection amounts paid/accrued (a) | 211 | — | 211 | — | |||||||||||
Interest paid/accrued on pre-petition debt (including net amounts paid/accrued under interest rate swaps) (b) | 318 | 844 | 1,151 | 1,683 | |||||||||||
Interest expense on pre-petition toggle notes payable in additional principal (Note 7) | 16 | 42 | 65 | 83 | |||||||||||
Noncash realized net loss on termination of interest rate swaps (offset in unrealized net gain) (c) | 1,237 | — | 1,237 | — | |||||||||||
Unrealized mark-to-market net gain on interest rate swaps | (1,238 | ) | (339 | ) | (1,303 | ) | (489 | ) | |||||||
Amortization of interest rate swap losses at dedesignation of hedge accounting | — | 2 | (1 | ) | 4 | ||||||||||
Amortization of fair value debt discounts resulting from purchase accounting | 1 | 5 | 6 | 10 | |||||||||||
Amortization of debt issuance, amendment and extension costs and discounts | 16 | 51 | 67 | 105 | |||||||||||
Capitalized interest | (4 | ) | (7 | ) | (11 | ) | (14 | ) | |||||||
Total interest expense and related charges | $ | 571 | $ | 598 | $ | 1,436 | $ | 1,382 | |||||||
____________
(a) | Post-petition period only. |
(b) | Includes amounts related to interest rate swaps totaling $48 million and $156 million for the three months ended June 30, 2014 and 2013, respectively, and $194 million and $309 million for the six months ended June 30, 2014 and 2013, respectively. Of the $194 million for the six months ended June 30, 2014, $129 million represents matured positions that have not been settled in cash. Of the $129 million, $127 million is included in the liability arising from the termination of TCEH interest rate swaps discussed in Note 12. |
(c) | Includes $1.225 billion related to terminated TCEH interest rate swaps (see Note 12) and $12 million related to other interest rate swaps. |
Interest expense for the three and six months ended June 30, 2014 reflects interest paid and accrued on debtor-in-possession financing (see Note 5), as well as 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 terminated TCEH interest rate swaps and natural gas hedging positions (see Note 12), in exchange for their consent to the senior secured, super-priority liens contained in the TCEH DIP Facility and any diminution in value of their interests in the pre-petition collateral from the Petition Date. The weighted average interest rate applicable to the adequate protection amounts paid/accrued at June 30, 2014 is 4.65% (one-month LIBOR plus 4.50%). In connection with the completion of a plan of reorganization of the Debtors, the amount of adequate protection payments will be "trued-up" to reflect the valuation of the TCEH Debtors determined in connection with confirmation of the plan of reorganization by the Bankruptcy Court.
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The Bankruptcy Code generally restricts payment of interest on pre-petition debt, subject to certain exceptions. However, the Bankruptcy Court ordered the payment of adequate protection amounts as discussed above and post-petition interest payments on EFIH First Lien Notes in connection with the settlement discussed in Note 5. Other than these amounts allowed by the Bankruptcy Court, effective April 29, 2014, the company discontinued recording interest expense on outstanding pre-petition debt classified as liabilities subject to compromise (LSTC). Contractual interest expense represents amounts due under the contractual terms of the outstanding debt, including debt subject to compromise during the Chapter 11 Cases. Interest expense for the three and six months ended June 30, 2014 does not include $257 million in contractual interest on pre-petition debt classified as LSTC, which has been stayed by the Bankruptcy Court effective on the Petition Date, as presented below:
Post-Petition Period Through June 30, 2014 | ||||||||||||||||
Entity: | Contractual Interest on Debt Classified as LSTC | Adequate Protection Paid/Accrued | Allowed Interest Paid/Accrued (a) | Contractual Interest on Debt Classified as LSTC Not Paid/Accrued | ||||||||||||
EFH Corp. | $ | 22 | $ | — | $ | — | $ | 22 | ||||||||
EFIH | 133 | — | 54 | 79 | ||||||||||||
EFCH | 1 | — | — | 1 | ||||||||||||
TCEH (b) | 356 | 201 | — | 155 | ||||||||||||
Total | $ | 512 | $ | 201 | $ | 54 | $ | 257 | ||||||||
___________
(a) | Interest on EFIH First Lien Notes exchanged and settled in June 2014 (see Note 5). |
(b) | Adequate protection paid/accrued presented in this table excludes $10 million related to the liability for terminated TCEH natural gas hedging positions and interest rate swaps (see Note 12). |
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9. | 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.
Disposed TXU Gas Company operations — In connection with the sale of the assets of TXU Gas Company to Atmos Energy Corporation (Atmos) in October 2004, EFH Corp. agreed to indemnify Atmos, until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas Company, including certain inactive gas plant sites not acquired by Atmos, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.
See Notes 5 and 7 for discussion of guarantees and security for certain of our post-petition and pre-petition debt.
Letters of Credit
At June 30, 2014, TCEH had outstanding letters of credit under its post-petition and pre-petition credit facilities totaling $609 million as follows:
• | $358 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions and collateral postings with ERCOT; |
• | $1 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $1 million; |
• | $62 million to support TCEH's REP financial requirements with the PUCT, and |
• | $188 million for miscellaneous 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 on their letters of credit if the terms of a particular letter of credit so provide. See Note 7 for discussion of letter of credit draws in 2014.
Litigation
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. EFCH and the directors filed a motion to dismiss this lawsuit in June 2013. In January 2014, the district court granted the motion to dismiss and in February 2014 entered final judgment dismissing the lawsuit. Aurelius has appealed the district court's judgment to the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court). We cannot predict the outcome of this proceeding, including the financial effects, if any.
Litigation Related to Generation Facilities — In November 2010, an administrative appeal challenging the decision of the TCEQ to renew and amend Oak Grove Management Company LLC's (Oak Grove) (a wholly owned subsidiary of TCEH) Texas Pollutant Discharge Elimination System (TPDES) permit related to water discharges was filed by Robertson County: Our Land, Our Lives and Roy Henrichson in the Travis County, Texas District Court. Plaintiffs sought a reversal of the TCEQ's order and a remand back to the TCEQ for further proceedings. The district court affirmed the TCEQ's issuance of the TPDES permit to Oak Grove. In December 2012, plaintiffs appealed the district court's decision to the Third Court of Appeals in Austin, Texas. Oral argument was held in April 2014. In June 2014, the Third Court of Appeals issued its opinion affirming the district court's judgment and the TCEQ's decision. Plaintiffs sought rehearing by the Third Court of Appeals, which was denied in July 2014. In July 2014, the Third Court of Appeals issued a replacement opinion again affirming TCEQ's issuance of the permit. Plaintiffs may again seek rehearing by the Third Court of Appeals or review by the Texas Supreme Court. While we cannot predict the timing or outcome of any subsequent rehearing proceeding or whether plaintiffs will seek review by the Texas Supreme Court, we believe the renewal and amendment of the Oak Grove TPDES permit are protective of the environment and were in accordance with applicable law.
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In May 2012, the Sierra Club filed a lawsuit in the US District Court for the Western District of Texas (Waco Division) against EFH Corp. and Luminant Generation Company LLC (a wholly owned subsidiary of TCEH) for alleged violations of the Clean Air Act (CAA) at Luminant's Big Brown generation facility. The Big Brown trial was held in February 2014. In pre-trial filings submitted in January 2014, the Sierra Club stated it was seeking over $337 million in civil penalties for the alleged violations and injunctive relief. In March 2014, the district court entered final judgment denying all of the Sierra Club's claims and all relief requested by the Sierra Club. The Sierra Club has appealed the district court's decision to the Fifth Circuit Court.
In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC for alleged violations of the CAA at Luminant's Martin Lake generation facility. In April 2014, the Martin Lake trial setting of May 2014 was vacated by the district court so that the district court could consider the effects of the decision in the Big Brown case. The Sierra Club has stated that it intends to ask the district court in this case to impose civil penalties of approximately $147 million. The Sierra Club has also stated that the district court can impose 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. In addition, the Sierra Club has requested injunctive relief, including the installation of new emissions control equipment at the plant. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. While we are unable to estimate any possible loss or predict the outcome of the Martin Lake case, we believe that, as the judge ruled in the Big Brown case, the Sierra Club's claims are without merit, and we intend to vigorously defend the lawsuit.
In addition, in December 2010 and again in October 2011, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating CAA provisions in connection with Luminant's Monticello generation facility. In May 2012, the Sierra Club informed us that it may sue us for allegedly violating CAA provisions in connection with Luminant's Sandow 4 generation facility. While we cannot predict whether the Sierra Club will actually file suit regarding Monticello or Sandow 4 or the outcome of any resulting proceedings, we believe we have complied with the requirements of the CAA at all of our generation facilities.
The affirmative claims asserted against EFH Corp. and Luminant Generation Company LLC described above were automatically stayed as a result of the Bankruptcy Filing. The matters will be subject to resolution in accordance with the Bankruptcy Code and the orders of the Bankruptcy Court. We are pursuing an affirmative claim against the Sierra Club in the US District Court for the Western District of Texas (Waco Division) for attorneys' fees incurred in defending the Big Brown case that the Bankruptcy Court has ruled is not subject to the automatic stay.
Makewhole 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 redemption premium in connection with the cash repayment of the EFIH First Lien Notes discussed in Note 5 and that such redemption premium is an allowed secured claim (EFIH First Lien Makewhole Claims). In the EFIH First Lien Makewhole Claim, the amount of such claims is alleged to be equal to approximately $432 million plus reimbursement of expenses. 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 redemption premium in connection with any repayment of the EFIH Second Lien Notes and that such redemption premium would be an allowed secured claim (the EFIH Second Lien Makewhole Claims and, together with the EFIH First Lien Makewhole Claims, the Makewhole Claims). In the EFIH Second Lien Makewhole Claim, as of July 31, 2014, the amount of such claims alleged would have been equal to approximately $675 million plus reimbursement of expenses. The EFIH Debtors expect to seek to obtain entry of orders from the Bankruptcy Court disallowing each of the Makewhole Claims.
In addition, creditors may make additional claims in the Chapter 11 Cases for redemption premiums in connection with repayments or settlement of other pre-petition debt. There can be no assurance regarding the outcome of this litigation or the Bankruptcy Court's determination regarding the validity or the amounts payable in respect of each of the Makewhole Claims or other claims for redemption premiums.
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 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. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement.
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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 September 2012, we filed a petition for review in the Fifth Circuit Court seeking judicial review of the EPA's notice of violation. Given recent legal precedent subjecting agency orders like the notice of violation to judicial review, we filed the petition for review to preserve our ability to challenge the EPA's issuance of the notice and its defects. In October 2012, the EPA filed a motion to dismiss our petition. In December 2012, the Fifth Circuit Court issued an order that delayed a ruling on the EPA's motion to dismiss until after the case was fully briefed and oral argument held.
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. In July 2013, we filed a petition for review in the Fifth Circuit Court seeking judicial review of the EPA's July 2013 notice of violation. In September 2013, the Fifth Circuit Court consolidated the petitions for review of the July 2012 and July 2013 notices of violation. Oral argument was heard in June 2014. In July 2014, the Fifth Circuit Court ruled that our challenges to the notices of violation must first be heard by the district court and may be presented as defenses to the EPA's civil enforcement lawsuit discussed below.
In August 2013, the US Department of Justice, acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant Generation Company LLC and Big Brown Power Company LLC in federal district court in Dallas, alleging violations of the CAA at our Big Brown and Martin Lake generation facilities. In September 2013, we filed a motion to stay this lawsuit pending the outcome of the Fifth Circuit Court's review of the July 2012 and July 2013 notices of violation. In January 2014, the district court granted our motion to stay the lawsuit until the Fifth Circuit Court resolved our petitions for review of the July 2012 and July 2013 notices of violation. In July 2014, the district court lifted the stay of the lawsuit. 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 oxides (NOx) emissions from our fossil fueled generation units. In September 2011, we filed a petition for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) challenging the CSAPR as it applies to Texas. If the CSAPR had taken effect at that time, it would have caused us to, among other actions, idle two lignite/coal fueled generation units and cease certain lignite mining operations by the end of 2011.
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 April 2012, we filed in the D.C. Circuit Court a petition for review of the Final Revisions on the ground, among others, that the rules do not include all of the budget corrections we requested from the EPA. The parties to the case agreed that the case should be held in abeyance pending the conclusion of the CSAPR rehearing proceeding discussed below. 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.
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In August 2012, the D.C. Circuit Court vacated the CSAPR, remanding it to the EPA for further proceedings. As a result, the CSAPR, the Final Revisions and the Second Revised Rule have not, to date, imposed any immediate requirements on us, the State of Texas, or other affected parties. The D.C. Circuit Court's order stated that the EPA was expected to continue administering the CAIR (the predecessor rule to the CSAPR) pending the EPA's further consideration of the rule. In March 2013, the EPA and certain other parties that supported the CSAPR submitted petitions to the US Supreme Court seeking its review of the D.C. Circuit Court's decision. The US Supreme Court granted review of the D.C. Circuit Court's decision in June 2013 and heard oral arguments in December 2013. In April 2014, the US Supreme Court issued its opinion in the CSAPR litigation, reversing the D.C. Circuit Court's decision in which that court vacated CSAPR, but clarifying that the EPA may not over-control states by requiring reductions in excess of those necessary for downwind states to attain applicable air quality standards. The US Supreme Court remanded the case to the D.C. Circuit Court for further proceedings consistent with its opinion. Additionally there are several issues that the D.C. Circuit did not reach in its first opinion that must now be resolved. In June 2014, the D.C. Circuit Court directed that the parties file motions to govern further proceedings. Those proposals have been filed and are pending before the D.C. Circuit Court. While the U.S. Supreme Court's ruling did not disturb the stay entered by the D.C. Circuit Court in December 2011, in June 2014 the EPA filed a motion in the D.C. Circuit Court seeking to lift the stay. On July 25, 2014, we filed a motion for summary vacatur of the CSAPR budgets for Texas, requesting that the D.C. Circuit Court remand Texas's CSAPR emission budgets to the EPA to develop a valid budget that does not require Texas to reduce emissions in excess of what is necessary for downwind areas to comply with air quality standards and that Texas's emissions should continue to be governed by CAIR in the interim. On July 31, 2014, we along with other Petitioners filed an opposition to the EPA's motion to lift the stay. We cannot predict the timing or outcome of future proceedings related to CSAPR, including the requirements of any ultimately implemented rule, any compliance timeframe or the financial effects, if any.
State Implementation Plan (SIP)
In September 2010, the EPA disapproved a portion of the SIP pursuant to which the TCEQ implements its program to achieve the requirements of the CAA. The EPA disapproved the Texas standard permit for pollution control projects (PCP). We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. We challenged the EPA's disapproval by filing a lawsuit in the Fifth Circuit Court arguing that the TCEQ's adoption of the standard permit conditions for pollution control projects was consistent with the CAA. In March 2012, the Fifth Circuit Court vacated the EPA's disapproval of the Texas standard permit for pollution control projects and remanded the matter to the EPA for expedited reconsideration. In September 2013, the State of Texas filed a motion with the Fifth Circuit Court requesting that the Court amend and enforce its judgment in this case by requiring the EPA to satisfy the Court's judgment by taking action on the pending SIP revision regarding Texas' PCP standard permit. In February 2014, the Fifth Circuit Court ordered the EPA to issue a final rule on the standard permit for pollution control projects by May 2014. In May 2014, the EPA filed a notice in the Fifth Circuit Court that they complied with the Court's mandate and issued the final approval of Texas' PCP standard permit.
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.
10. | 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 Bankruptcy Filing, no dividends are eligible to be paid without the approval of the Bankruptcy Court.
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Noncontrolling Interests
As discussed in Note 3, we consolidate certain VIEs, which results in a noncontrolling interests component of equity. Net loss attributable to the noncontrolling interests was immaterial for the six months ended June 30, 2014 and 2013.
Equity
The following table presents the changes to equity for the six months ended June 30, 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 | — | — | (1,383 | ) | — | — | (1,383 | ) | |||||||||||||||
Effects of stock-based incentive compensation plans | — | 4 | — | — | — | 4 | |||||||||||||||||
Change in unrecognized losses related to pension and OPEB plans | — | — | — | (3 | ) | — | (3 | ) | |||||||||||||||
Net effects of cash flow hedges | — | — | — | 1 | — | 1 | |||||||||||||||||
Net effects related to Oncor | — | — | — | 1 | — | 1 | |||||||||||||||||
Investment by noncontrolling interests | — | — | — | — | 1 | 1 | |||||||||||||||||
Other | — | — | — | — | (2 | ) | (2 | ) | |||||||||||||||
Balance at June 30, 2014 | $ | 2 | $ | 7,966 | $ | (22,540 | ) | $ | (64 | ) | $ | — | $ | (14,636 | ) | ||||||||
____________
(a) | Authorized shares totaled 2,000,000,000 at June 30, 2014. Outstanding shares totaled 1,669,861,383 and 1,669,861,383 at June 30, 2014 and December 31, 2013, respectively. |
The following table presents the changes to equity for the six months ended June 30, 2013:
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, 2012 | $ | 2 | $ | 7,959 | $ | (18,939 | ) | $ | (47 | ) | $ | 102 | $ | (10,923 | ) | ||||||||
Net loss | — | — | (640 | ) | — | — | (640 | ) | |||||||||||||||
Effects of stock-based incentive compensation plans | — | 3 | — | — | — | 3 | |||||||||||||||||
Repurchases of stock | — | (5 | ) | — | — | — | (5 | ) | |||||||||||||||
Change in unrecognized losses related to pension and OPEB plans | — | — | — | (3 | ) | — | (3 | ) | |||||||||||||||
Net effects of cash flow hedges | — | — | — | 4 | — | 4 | |||||||||||||||||
Net effects related to Oncor | — | — | — | 1 | — | 1 | |||||||||||||||||
Investment by noncontrolling interests | — | — | — | — | 2 | 2 | |||||||||||||||||
Balance at June 30, 2013 | $ | 2 | $ | 7,957 | $ | (19,579 | ) | $ | (45 | ) | $ | 104 | $ | (11,561 | ) | ||||||||
____________
(a) | Authorized shares totaled 2,000,000,000 at June 30, 2013. Outstanding shares totaled 1,669,861,383 and 1,680,539,245 at June 30, 2013 and December 31, 2012, respectively. |
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Accumulated Other Comprehensive Income (Loss)
The following table presents the changes to accumulated other comprehensive income (loss) for the six months ended June 30, 2014. There was no other comprehensive income (loss) before reclassification for the period.
Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 12) | 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 | — | (2 | ) | (2 | ) | ||||||
Depreciation and amortization | 1 | — | 1 | ||||||||
Selling, general and administrative expenses | — | (2 | ) | (2 | ) | ||||||
Interest expense and related charges | — | — | — | ||||||||
Income tax benefit (expense) | — | 1 | 1 | ||||||||
Equity in earnings of unconsolidated subsidiaries | 1 | — | 1 | ||||||||
Total amount reclassified from accumulated other comprehensive income (loss) during the period | 2 | (3 | ) | (1 | ) | ||||||
Balance at June 30, 2014 | $ | (54 | ) | $ | (10 | ) | $ | (64 | ) | ||
The following table presents the changes to accumulated other comprehensive income (loss) for the six months ended June 30, 2013. There was no other comprehensive income (loss) before reclassification for the period.
Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 12) | Pension and Other Postretirement Employee Benefit Liabilities Adjustments | Accumulated Other Comprehensive Income (Loss) | |||||||||
Balance at December 31, 2012 | $ | (64 | ) | $ | 17 | $ | (47 | ) | |||
Amounts reclassified from accumulated other comprehensive income (loss) and reported in: | |||||||||||
Operating costs | — | (2 | ) | (2 | ) | ||||||
Depreciation and amortization | 1 | — | 1 | ||||||||
Selling, general and administrative expenses | — | (2 | ) | (2 | ) | ||||||
Interest expense and related charges | 5 | — | 5 | ||||||||
Income tax benefit (expense) | (2 | ) | 1 | (1 | ) | ||||||
Equity in earnings of unconsolidated subsidiaries | 2 | (1 | ) | 1 | |||||||
Total amount reclassified from accumulated other comprehensive income (loss) during the period | 6 | (4 | ) | 2 | |||||||
Balance at June 30, 2013 | $ | (58 | ) | $ | 13 | $ | (45 | ) | |||
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11. | 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 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 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 whose values are 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 use generally accepted interest rate swap valuation models utilizing month-end interest rate curves.
Probable loss of 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 12 for additional information regarding credit risk associated with our derivatives). We utilize published credit ratings, default rate factors and debt trading values in calculating these fair value measurement adjustments.
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Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including, but not limited to, commodity prices, volatility factors, discount rates and other market based factors. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing locations and credit/non-performance risk assumptions. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.
The significant unobservable inputs and valuation models are developed by employees trained and experienced in market operations and fair value measurements and validated by the company's risk management group, which also further analyzes any significant changes in Level 3 measurements. Significant changes in the unobservable inputs could result in significant upward or downward changes in the fair value measurement.
With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.
Assets and liabilities measured at fair value on a recurring basis consisted of the following:
June 30, 2014 | |||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Total | ||||||||||||
Assets: | |||||||||||||||
Commodity contracts | $ | 118 | $ | 64 | $ | 58 | $ | 240 | |||||||
Nuclear decommissioning trust – equity securities (b) | 354 | 204 | — | 558 | |||||||||||
Nuclear decommissioning trust – debt securities (b) | — | 287 | — | 287 | |||||||||||
Total assets | $ | 472 | $ | 555 | $ | 58 | $ | 1,085 | |||||||
Liabilities: | |||||||||||||||
Commodity contracts | $ | 193 | $ | 37 | $ | 13 | $ | 243 | |||||||
Total liabilities | $ | 193 | $ | 37 | $ | 13 | $ | 243 | |||||||
December 31, 2013 | |||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Total | ||||||||||||
Assets: | |||||||||||||||
Commodity contracts | $ | 161 | $ | 570 | $ | 57 | $ | 788 | |||||||
Interest rate swaps | — | 67 | — | 67 | |||||||||||
Nuclear decommissioning trust – equity securities (b) | 330 | 191 | — | 521 | |||||||||||
Nuclear decommissioning trust – debt securities (b) | — | 270 | — | 270 | |||||||||||
Total assets | $ | 491 | $ | 1,098 | $ | 57 | $ | 1,646 | |||||||
Liabilities: | |||||||||||||||
Commodity contracts | $ | 231 | $ | 14 | $ | 18 | $ | 263 | |||||||
Interest rate swaps | — | 80 | 1,012 | 1,092 | |||||||||||
Total liabilities | $ | 231 | $ | 94 | $ | 1,030 | $ | 1,355 | |||||||
____________
(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 15. |
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 12 for further discussion regarding derivative instruments, including the termination of certain natural gas hedging agreements shortly after the Bankruptcy Filing.
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Interest rate swaps included variable-to-fixed rate swap instruments that hedged the interest costs of our debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 12 for discussion of the termination of interest rate swaps shortly after the Bankruptcy Filing.
Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.
There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the three and six months ended June 30, 2014 and 2013. See the table of changes in fair values of Level 3 assets and liabilities below for discussion of transfers between Level 2 and Level 3 for the three and six months ended June 30, 2014 and 2013.
The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at June 30, 2014 and December 31, 2013:
June 30, 2014 | ||||||||||||||||||
Fair Value | ||||||||||||||||||
Contract Type (a) | Assets | Liabilities | Total | Valuation Technique | Significant Unobservable Input | Range (b) | ||||||||||||
Electricity purchases and sales | $ | 4 | $ | (2 | ) | $ | 2 | Valuation Model | Illiquid pricing locations (c) | $35 to $50/ MWh | ||||||||
Hourly price curve shape (d) | $20 to $70/ MWh | |||||||||||||||||
Electricity spread options | 7 | (2 | ) | 5 | Option Pricing Model | Gas to power correlation (e) | 40% to 90% | |||||||||||
Power volatility (f) | 10% to 40% | |||||||||||||||||
Electricity congestion revenue rights | 40 | (3 | ) | 37 | Market Approach (g) | Illiquid price differences between settlement points (h) | $0.00 to $25.00 | |||||||||||
Coal purchases | 3 | (5 | ) | (2 | ) | Market Approach (g) | Illiquid price variances between mines (i) | $0.00 to $1.00 | ||||||||||
Probability of default (j) | 0% to 40% | |||||||||||||||||
Recovery rate (k) | 0% to 40% | |||||||||||||||||
Illiquid pricing variances between heat content (l) | $0.30 to $0.40 | |||||||||||||||||
Other (n) | 4 | (1 | ) | 3 | ||||||||||||||
Total | $ | 58 | $ | (13 | ) | $ | 45 | |||||||||||
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December 31, 2013 | ||||||||||||||||||
Fair Value | ||||||||||||||||||
Contract Type (a) | Assets | Liabilities | Total | Valuation Technique | Significant Unobservable Input | Range (b) | ||||||||||||
Electricity purchases and sales | $ | 2 | $ | (2 | ) | $ | — | Valuation Model | Illiquid pricing locations (c) | $25 to $45/ MWh | ||||||||
Hourly price curve shape (d) | $20 to $70/ MWh | |||||||||||||||||
Electricity spread options | 15 | (2 | ) | 13 | Option Pricing Model | Gas to power correlation (e) | 45% to 95% | |||||||||||
Power volatility (f) | 10% to 30% | |||||||||||||||||
Electricity congestion revenue rights | 35 | (2 | ) | 33 | Market Approach (g) | Illiquid price differences between settlement points (h) | $0.00 to $25.00 | |||||||||||
Coal purchases | — | (11 | ) | (11 | ) | Market Approach (g) | Illiquid price variances between mines (i) | $0.00 to $1.00 | ||||||||||
Probability of default (j) | 0% to 40% | |||||||||||||||||
Recovery rate (k) | 0% to 40% | |||||||||||||||||
Interest rate swaps | — | (1,012 | ) | (1,012 | ) | Valuation Model | Nonperformance risk adjustment (m) | 25% to 35% | ||||||||||
Other (n) | 5 | (1 | ) | 4 | ||||||||||||||
Total | $ | 57 | $ | (1,030 | ) | $ | (973 | ) | ||||||||||
____________
(a) | Electricity purchase and sales contracts include hedging positions in the ERCOT West, North and Houston 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. TCEH used interest rate swaps to hedge exposure to its variable rate debt (see Note 12). |
(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) | Estimate of the range of probabilities of default based on past experience and the length of the contract as well as our and counterparties' credit ratings. |
(k) | Estimate of the default recovery rate based on historical corporate rates. |
(l) | Based on historical ranges of forward average prices between different heat contents. |
(m) | Estimate of nonperformance risk adjustment based on TCEH senior secured debt trading values. |
(n) | Other includes contracts for ancillary services, natural gas, diesel options, coal options and weather dependent power options. |
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The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and six months ended June 30, 2014 and 2013.
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Net asset (liability) balance at beginning of period | $ | (897 | ) | $ | 59 | $ | (973 | ) | $ | 29 | |||||
Total unrealized valuation losses | (9 | ) | (26 | ) | (94 | ) | (17 | ) | |||||||
Purchases, issuances and settlements (a): | |||||||||||||||
Purchases | 20 | 56 | 29 | 60 | |||||||||||
Issuances | (1 | ) | (6 | ) | (2 | ) | (6 | ) | |||||||
Settlements/terminations | 933 | 1 | 1,084 | 17 | |||||||||||
Transfers into Level 3 (b) | — | — | — | 1 | |||||||||||
Transfers out of Level 3 (b) | (1 | ) | 4 | 1 | 4 | ||||||||||
Net change (c) | 942 | 29 | 1,018 | 59 | |||||||||||
Net asset balance at end of period | $ | 45 | $ | 88 | $ | 45 | $ | 88 | |||||||
Unrealized valuation losses relating to instruments held at end of period | $ | (9 | ) | $ | (20 | ) | $ | (5 | ) | $ | (7 | ) | |||
____________
(a) | Settlement amounts in 2014 reflect termination of TCEH interest rate swaps and include the nonperformance risk adjustment as discussed in Note 12. Settlements for all periods presented 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. Transfers out during 2013 were driven by a decrease in nonperformance risk adjustments. All Level 3 transfers in 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. Changes in values of interest rate swaps transferred into Level 3 in third quarter 2013 are reported in the condensed statements of consolidated income (loss) in interest expense and related charges (see Note 12). 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. |
12. | 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. We had previously entered into interest rate swaps to manage our interest rate risk exposure. See Note 11 for a discussion of the fair value of derivatives. 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.
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 2015 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.
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Termination of Commodity Hedges and Interest Rate Swaps — These instruments are deemed to be "forward contracts" under the Bankruptcy Code. The Bankruptcy Filing constituted an event of default under the related agreements, 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. The terminated natural gas hedging positions represented approximately 70% of the commodity contracts derivative assets, and the terminated interest rate swaps represented all of the interest rate swap derivative assets and liabilities as of December 31, 2013 as presented in the table below.
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, as well as counterparties to only our interest rate swaps. 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.
The derivative liability related to the TCEH interest rate swaps had included a nonperformance risk adjustment (resulting in a Level 3 valuation). This fair value adjustment reflected the counterparties' exposure to our credit risk. The amount of the adjustment was after consideration of derivative assets related to natural gas hedging positions with the same counterparties. The difference between the net liability arising upon the termination of the interest rate swaps and the natural gas hedging positions and the net derivative assets and liabilities recorded totaled $278 million, substantially all of which represented the nonperformance risk adjustment, and is reported as a noncash charge in reorganization items in the condensed statements of consolidated income (loss) in accordance with ASC 852-10, Reorganizations (see Note 6).
Financial Statement Effects of Derivatives
Substantially all derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of commodity and other derivative contractual assets and liabilities (with the column totals representing the net positions of the contracts) as reported in the condensed consolidated balance sheets at June 30, 2014 and December 31, 2013:
June 30, 2014 | |||||||||||||||||||
Derivative assets | Derivative liabilities | ||||||||||||||||||
Commodity contracts | Interest rate swaps | Commodity contracts | Interest rate swaps | Total | |||||||||||||||
Current assets | $ | 231 | $ | — | $ | — | $ | — | $ | 231 | |||||||||
Noncurrent assets | 9 | — | — | — | 9 | ||||||||||||||
Current liabilities | — | — | (241 | ) | — | (241 | ) | ||||||||||||
Noncurrent liabilities | — | — | (2 | ) | — | (2 | ) | ||||||||||||
Net assets (liabilities) | $ | 240 | $ | — | $ | (243 | ) | $ | — | $ | (3 | ) | |||||||
December 31, 2013 | |||||||||||||||||||
Derivative assets | Derivative liabilities | ||||||||||||||||||
Commodity contracts | Interest rate swaps | Commodity contracts | Interest rate swaps | Total | |||||||||||||||
Current assets | $ | 784 | $ | 67 | $ | — | $ | — | $ | 851 | |||||||||
Noncurrent assets | 4 | — | — | — | 4 | ||||||||||||||
Current liabilities | — | — | (263 | ) | (1,092 | ) | (1,355 | ) | |||||||||||
Net assets (liabilities) | $ | 788 | $ | 67 | $ | (263 | ) | $ | (1,092 | ) | $ | (500 | ) | ||||||
In consideration of the termination rights of counterparties arising from the Bankruptcy Filing, derivative liabilities classified as current at December 31, 2013 include $647 million that otherwise would be classified as noncurrent, essentially all of which relates to interest rate swaps.
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At June 30, 2014 and December 31, 2013, there were no derivative positions accounted for as cash flow or fair value hedges.
The following table presents the pretax effect of derivatives on net income (gains (losses)), including realized and unrealized effects:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Derivative (income statement presentation) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Commodity contracts (Net gain (loss) from commodity hedging and trading activities) (a) | $ | 11 | $ | 157 | $ | (168 | ) | $ | (43 | ) | ||||||
Interest rate swaps (Interest expense and related charges) (b) | (47 | ) | 183 | (128 | ) | 180 | ||||||||||
Interest rate swaps (Reorganization items) (Note 6) | (278 | ) | — | (278 | ) | — | ||||||||||
Net gain (loss) | $ | (314 | ) | $ | 340 | $ | (574 | ) | $ | 137 | ||||||
____________
(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 8). |
The pretax effect (all losses) on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges was immaterial in both the three and six months ended June 30, 2014 and 2013. There were no amounts recognized in OCI for the three and six months ended June 30, 2014 and 2013.
Accumulated other comprehensive income related to cash flow hedges (excluding Oncor's interest rate hedge) totaled $36 million and $37 million in net losses (after-tax) at June 30, 2014 and December 31, 2013, respectively, substantially all of which relates to interest rate swaps previously accounted for as cash flow hedges. We expect that $2 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income at June 30, 2014 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 from period to period.
Margin deposits that contractually offset these derivative instruments are reported separately in the condensed consolidated balance sheets. Margin deposits received from counterparties are either used for working capital or other corporate purposes or are deposited in a separate restricted cash account. At June 30, 2014 and December 31, 2013, 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.
36
The following tables reconcile our derivative assets and liabilities as presented in the condensed consolidated balance sheets to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
June 30, 2014 | ||||||||||||||||
Amounts Presented in Balance Sheet | Offsetting Instruments | Financial Collateral (Received) Pledged (b) | Net Amounts | |||||||||||||
Derivative assets: | ||||||||||||||||
Commodity contracts | $ | 240 | $ | (153 | ) | $ | — | $ | 87 | |||||||
Interest rate swaps | — | — | — | — | ||||||||||||
Total derivative assets | 240 | (153 | ) | — | 87 | |||||||||||
Derivative liabilities: | ||||||||||||||||
Commodity contracts | (243 | ) | 153 | 75 | (15 | ) | ||||||||||
Interest rate swaps | — | — | — | — | ||||||||||||
Total derivative liabilities | (243 | ) | 153 | 75 | (15 | ) | ||||||||||
Net amounts | $ | (3 | ) | $ | — | $ | 75 | $ | 72 | |||||||
December 31, 2013 | ||||||||||||||||
Amounts Presented in Balance Sheet | Offsetting Instruments (a) | Financial Collateral (Received) Pledged (b) | Net Amounts | |||||||||||||
Derivative assets: | ||||||||||||||||
Commodity contracts | $ | 788 | $ | (389 | ) | $ | (299 | ) | $ | 100 | ||||||
Interest rate swaps | 67 | (67 | ) | — | — | |||||||||||
Total derivative assets | 855 | (456 | ) | (299 | ) | 100 | ||||||||||
Derivative liabilities: | ||||||||||||||||
Commodity contracts | (263 | ) | 168 | 70 | (25 | ) | ||||||||||
Interest rate swaps | (1,092 | ) | 288 | — | (804 | ) | ||||||||||
Total derivative liabilities | (1,355 | ) | 456 | 70 | (829 | ) | ||||||||||
Net amounts | $ | (500 | ) | $ | — | $ | (229 | ) | $ | (729 | ) | |||||
____________
(a) | Offsetting instruments at December 31, 2013 with respect to commodity contracts include amounts related to interest rate swaps and vice versa. All amounts presented exclude trade accounts receivable and payable related to settled financial instruments. |
(b) | Financial collateral consists entirely of cash margin deposits. |
37
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes at June 30, 2014 and December 31, 2013:
June 30, 2014 | December 31, 2013 | |||||||||
Derivative type | Notional Volume | Unit of Measure | ||||||||
Interest rate swaps: | ||||||||||
Floating/fixed (a) | $ | — | $ | 32,490 | Million US dollars | |||||
Basis | $ | — | $ | 1,050 | Million US dollars | |||||
Natural gas (b) | 1,506 | 2,150 | Million MMBtu | |||||||
Electricity | 22,340 | 16,482 | GWh | |||||||
Congestion Revenue Rights (c) | 92,010 | 77,799 | GWh | |||||||
Coal | 14 | 9 | Million US tons | |||||||
Fuel oil | 16 | 26 | Million gallons | |||||||
Uranium | 300 | 450 | Thousand pounds | |||||||
____________
(a) | Amounts at December 31, 2013 include notional amount of interest rate swaps that had maturity dates through October 2014 as well as notional amount of swaps effective from October 2014 that had maturity dates through October 2017. |
(b) | Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions. |
(c) | Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT. |
See discussion above regarding termination of natural gas hedging and interest rate swap agreements shortly after the Bankruptcy Filing.
Credit Risk-Related Contingent Features of Derivatives
The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies; however, due to our credit ratings being below investment grade, substantially all of such collateral posting requirements have already been effective.
At June 30, 2014 and December 31, 2013, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully collateralized totaled $6 million and $4 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $5 million and $3 million at June 30, 2014 and December 31, 2013, respectively. All of the credit risk-related contingent features related to these derivatives were triggered upon the Bankruptcy Filing.
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 such contracts had been cancelled at June 30, 2014. At June 30, 2014 and December 31, 2013, the fair value of derivative liabilities subject to such cross-default provisions totaled $9 million and $1.103 billion, respectively, before consideration of the collateral. Amounts at December 31, 2013 were largely related to interest rate swaps. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $8 million and $6 million at June 30, 2014 and December 31, 2013, respectively, and totaled $1.154 billion at December 31, 2013. There was no liquidity exposure associated with these liabilities at June 30, 2014. See Note 7 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, totaled $15 million and $1.107 billion at June 30, 2014 and December 31, 2013, respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets subject to related liens.
38
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.
See discussion at beginning of this note regarding termination of commodity hedges and interest rate swaps.
Concentrations of Credit Risk Related to Derivatives
We have concentrations of credit risk with the counterparties to our derivative contracts. At June 30, 2014, total credit risk exposure to all counterparties related to derivative contracts totaled $329 million (including associated accounts receivable). The net exposure to those counterparties totaled $171 million at June 30, 2014 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $87 million. At June 30, 2014, the credit risk exposure to the banking and financial sector represented 73% of the total credit risk exposure and 54% of the net exposure. The termination of natural gas hedging agreements by counterparties shortly after the Bankruptcy Filing did not significantly affect the net credit risk exposure amount presented.
Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.
We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.
39
13. | 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 June 30, 2014 and 2013 and $20 million and $19 million for the six months ended June 30, 2014 and 2013, respectively. No payments were made in the three and six months ended June 30, 2014, while payments totaled $10 million and $19 million for the three and six months ended June 30, 2013, respectively. 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). |
• | In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of each member of the Sponsor Group have from time to time engaged in commercial banking transactions with us and/or provided financial advisory services to us, in each case in the normal course of business. |
• | Affiliates of GS Capital Partners were parties to certain commodity and interest rate hedging transactions with us in the normal course of business. |
• | Affiliates of the Sponsor Group have sold or acquired, and in the future may sell or acquire, debt or debt securities issued by us in open market transactions or through loan syndications. |
• | TCEH made loans to EFH Corp. in the form of demand notes (TCEH Demand Notes) that were pledged as collateral under the TCEH Senior Secured Facilities for (i) debt principal and interest payments and (ii) other general corporate purposes for EFH Corp. EFH Corp. settled the balance of the TCEH Demand Notes in January 2013 using $680 million of the proceeds from debt issued by EFIH in 2012 that had been held as restricted cash. |
• | 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 June 30, 2014 and December 31, 2013. EFH Corp. held $303 million principal amount of TCEH debt at both June 30, 2014 and December 31, 2013. In the first quarter 2013, EFIH distributed to EFH Corp. $6.360 billion principal amount of EFH Corp. debt previously received by EFIH in debt exchanges; EFH Corp. cancelled the debt instruments. |
• | 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 $225 million and $230 million for the three months ended June 30, 2014 and 2013, respectively, and $465 million and $455 million for the six months ended June 30, 2014 and 2013, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The condensed consolidated balance sheets at June 30, 2014 and December 31, 2013 reflect amounts due currently to Oncor totaling $140 million and $135 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 $7 million for both the three months ended June 30, 2014 and 2013 and $16 million for both the six months ended June 30, 2014 and 2013. |
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• | A subsidiary of EFH Corp. bills TCEH subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges totaled $44 million and $55 million for the three months ended June 30, 2014 and 2013, respectively, and $100 million and $117 million for the six months ended June 30, 2014 and 2013, respectively. |
• | See Note 7 for discussion of a letter of credit issued by TCEH in 2014 to a subsidiary of EFH Corp. to secure its amounts payable to the subsidiary arising from recurring transactions in the normal course. |
• | In April 2014, prior to the Bankruptcy Filing, a subsidiary of EFH Corp. sold information technology assets to TCEH totaling $24 million. TCEH cash settled these transactions in April 2014. The assets are substantially for the use of TCEH and its subsidiaries. |
• | 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 balance sheet, will ultimately be sufficient to fund the actual future decommissioning liability, reported in noncurrent liabilities in our balance sheet. The delivery fee surcharges remitted to TCEH totaled $4 million for both the three months ended June 30, 2014 and 2013 and $8 million for both the six months ended June 30, 2014 and 2013. Income and expenses associated with the trust fund and the decommissioning liability incurred by TCEH are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates. At June 30, 2014 and December 31, 2013, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $442 million and $400 million, respectively, reported in noncurrent liabilities. |
• | We file a consolidated federal income tax return that includes Oncor Holdings' results. Oncor is not a member of our consolidated tax group, but our consolidated federal income tax return includes our portion of Oncor's results due to our equity ownership in Oncor. We also file a consolidated Texas state margin tax return that includes all of Oncor Holdings' and Oncor's results. However, under a Federal and State Income Tax Allocation Agreement, Oncor Holdings' and Oncor's federal income tax and Texas margin tax expense and related balance sheet amounts, including our income taxes receivable from or payable to Oncor Holdings and Oncor, are recorded as if Oncor Holdings and Oncor file their own corporate income tax returns. |
At June 30, 2014, our current amount payable to Oncor Holdings related to federal and state income taxes (included in net payables due to unconsolidated subsidiary) totaled $22 million, which included $23 million payable to Oncor. The payable to Oncor represented a $37 million federal income tax payable net of a $14 million state margin tax receivable. At December 31, 2013, our current amount receivable totaled $7 million, which included $5 million receivable from Oncor. The receivable from Oncor represented a $23 million state margin tax receivable net of an $18 million federal income tax payable.
For the six months ended June 30, 2014, EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $12 million and $135 million, respectively. For the six months ended June 30, 2013, EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $17 million and $36 million, respectively.
• | Certain transmission and distribution utilities in Texas have requirements in place to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, as a result of TCEH's credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, at June 30, 2014 and December 31, 2013, TCEH had posted letters of credit and/or cash in the amount of $10 million and $9 million, respectively, for the benefit of Oncor. |
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• | 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 and OPEB liabilities that are recoverable by Oncor under regulatory rate-setting provisions. As part of the pension plan actions, EFH Corp. fully funded the nonrecoverable 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. EFH Corp. is the sponsor of the OPEB plan and remains liable for the majority of the OPEB plan obligations. Accordingly, EFH Corp.'s balance sheet reflects unfunded pension and OPEB liabilities related to plans that it sponsors, including recoverable and nonrecoverable amounts, 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 June 30, 2014 and December 31, 2013, the receivable amounts totaled $851 million and $838 million, respectively, classified as noncurrent. 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. Net amounts of pension and OPEB expenses recognized in the three and six months ended June 30, 2014 and 2013 are not material. |
• | In the first quarter 2014, a cash contribution totaling $84 million was made to the EFH Corp. retirement plan assets, 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 is 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. |
• | In the second quarter 2014, Oncor and EFH Corp. entered into an agreement whereby Oncor will cease participation in EFH Corp.'s OPEB Plan and establish its own OPEB plan for Oncor’s eligible retirees and their dependents effective July 1, 2014. Participants in the EFH Corp. OPEB plan with split service will become participants in the Oncor plan. The methodology for OPEB cost allocations between EFH Corp. and Oncor is not expected to change, and the agreement is not expected to have a material effect on the net assets or cash flows of EFH Corp. |
• | 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. |
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14. | 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 sales to residential and business customers, all largely in Texas. 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 13 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 nonsegment 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 852-10, 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 Financial Statements in our 2013 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 June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Operating revenues (all Competitive Electric) | $ | 1,406 | $ | 1,419 | $ | 2,924 | $ | 2,679 | |||||||
Equity in earnings of unconsolidated subsidiaries (net of tax) — Regulated Delivery (net of noncontrolling interest of $19, $19, $40 and $37) | $ | 72 | $ | 74 | $ | 152 | $ | 141 | |||||||
Net income (loss): | |||||||||||||||
Competitive Electric | $ | (591 | ) | $ | (238 | ) | $ | (1,158 | ) | $ | (786 | ) | |||
Regulated Delivery | 72 | 74 | 152 | 141 | |||||||||||
Corporate and Other | (255 | ) | 93 | (377 | ) | 5 | |||||||||
Consolidated | $ | (774 | ) | $ | (71 | ) | $ | (1,383 | ) | $ | (640 | ) | |||
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15. | SUPPLEMENTARY FINANCIAL INFORMATION |
Other Income and Deductions
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Other income: | |||||||||||||||
Office space rental income (a) | $ | 3 | $ | 3 | $ | 6 | $ | 6 | |||||||
Insurance/litigation settlements (b) | — | — | — | 2 | |||||||||||
All other | 3 | 4 | 8 | 6 | |||||||||||
Total other income | $ | 6 | $ | 7 | $ | 14 | $ | 14 | |||||||
Other deductions: | |||||||||||||||
Write-off of deferred costs related to cancelled mining projects | $ | 21 | $ | — | $ | 21 | $ | — | |||||||
Ongoing employee retirement benefit expense related to discontinued businesses (a) | — | — | $ | — | $ | (1 | ) | ||||||||
All other | 2 | 1 | 2 | 5 | |||||||||||
Total other deductions | $ | 23 | $ | 1 | $ | 23 | $ | 4 | |||||||
____________
(a) | Reported in Corporate and Other. |
(b) | Reported in Competitive Electric segment. |
Restricted Cash
June 30, 2014 | December 31, 2013 | ||||||||||||||
Current Assets | Noncurrent Assets | Current Assets | Noncurrent Assets | ||||||||||||
Amounts related to TCEH's DIP Facility (Note 5) | $ | — | $ | 53 | $ | — | $ | — | |||||||
Amounts related to TCEH's pre-petition Letter of Credit Facility (Note 7) (a) | — | 582 | 945 | — | |||||||||||
Other | 4 | — | 4 | — | |||||||||||
Total restricted cash | $ | 4 | $ | 635 | $ | 949 | $ | — | |||||||
____________
(a) | At December 31, 2013, in consideration of the Bankruptcy Filing, all amounts were classified as current. See Note 7 for discussion of letter of credit draws in 2014. |
Trade Accounts Receivable
June 30, 2014 | December 31, 2013 | ||||||
Wholesale and retail trade accounts receivable | $ | 785 | $ | 732 | |||
Allowance for uncollectible accounts | (13 | ) | (14 | ) | |||
Trade accounts receivable — net | $ | 772 | $ | 718 | |||
Gross trade accounts receivable at June 30, 2014 and December 31, 2013 included unbilled revenues of $286 million and $272 million, respectively.
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Allowance for Uncollectible Accounts Receivable
Six Months Ended June 30, | |||||||
2014 | 2013 | ||||||
Allowance for uncollectible accounts receivable at beginning of period | $ | 14 | $ | 9 | |||
Increase for bad debt expense | 20 | 13 | |||||
Decrease for account write-offs | (21 | ) | (11 | ) | |||
Allowance for uncollectible accounts receivable at end of period | $ | 13 | $ | 11 | |||
Inventories by Major Category
June 30, 2014 | December 31, 2013 | ||||||
Materials and supplies | $ | 213 | $ | 216 | |||
Fuel stock | 187 | 154 | |||||
Natural gas in storage | 42 | 29 | |||||
Total inventories | $ | 442 | $ | 399 | |||
Other Investments
June 30, 2014 | December 31, 2013 | ||||||
Nuclear plant decommissioning trust | $ | 845 | $ | 791 | |||
Assets related to employee benefit plans, including employee savings programs, net of distributions | 61 | 61 | |||||
Land | 37 | 37 | |||||
Miscellaneous other | 2 | 2 | |||||
Total other investments | $ | 945 | $ | 891 | |||
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 13). The nuclear decommissioning trust fund is not a debtor under the Chapter 11 Cases. A summary of investments in the fund follows:
June 30, 2014 | |||||||||||||||
Cost (a) | Unrealized gain | Unrealized loss | Fair market value | ||||||||||||
Debt securities (b) | $ | 276 | $ | 12 | $ | (1 | ) | $ | 287 | ||||||
Equity securities (c) | 261 | 302 | (5 | ) | 558 | ||||||||||
Total | $ | 537 | $ | 314 | $ | (6 | ) | $ | 845 | ||||||
December 31, 2013 | |||||||||||||||
Cost (a) | Unrealized gain | Unrealized loss | Fair market value | ||||||||||||
Debt securities (b) | $ | 266 | $ | 8 | $ | (4 | ) | $ | 270 | ||||||
Equity securities (c) | 255 | 271 | (5 | ) | 521 | ||||||||||
Total | $ | 521 | $ | 279 | $ | (9 | ) | $ | 791 | ||||||
____________
(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 4.14% and 3.96% at June 30, 2014 and December 31, 2013, respectively, and an average maturity of 6 years at both June 30, 2014 and December 31, 2013. |
(c) | The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index. |
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Debt securities held at June 30, 2014 mature as follows: $101 million in one to five years, $56 million in five to ten years and $130 million after ten years.
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Realized gains | $ | — | $ | 1 | $ | 1 | $ | 1 | |||||||
Realized losses | $ | (1 | ) | $ | — | $ | (1 | ) | $ | — | |||||
Proceeds from sales of securities | $ | 52 | $ | 64 | $ | 85 | $ | 105 | |||||||
Investments in securities | $ | (56 | ) | $ | (67 | ) | $ | (93 | ) | $ | (112 | ) | |||
Property, Plant and Equipment
At June 30, 2014 and December 31, 2013, property, plant and equipment of $17.3 billion and $17.8 billion, respectively, is stated net of accumulated depreciation and amortization of $8.8 billion and $8.2 billion, respectively.
Asset Retirement and Mining Reclamation Obligations
These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of Oncor's delivery fees.
The following table summarizes the changes to these obligations, reported in other current liabilities and other noncurrent liabilities and deferred credits in the condensed consolidated balance sheets, for the six months ended June 30, 2014:
Nuclear Plant Decommissioning | Mining Land Reclamation | Other | Total | ||||||||||||
Liability at December 31, 2013 | $ | 390 | $ | 98 | $ | 36 | $ | 524 | |||||||
Additions: | |||||||||||||||
Accretion | 12 | 12 | — | 24 | |||||||||||
Reductions: | |||||||||||||||
Payments | — | (40 | ) | — | (40 | ) | |||||||||
Adjustment to estimate of reclamation costs | — | (2 | ) | — | (2 | ) | |||||||||
Liability at June 30, 2014 | 402 | 68 | 36 | 506 | |||||||||||
Less amounts due currently | — | (49 | ) | — | (49 | ) | |||||||||
Noncurrent liability at June 30, 2014 | $ | 402 | $ | 19 | $ | 36 | $ | 457 | |||||||
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Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
June 30, 2014 | December 31, 2013 | ||||||
Uncertain tax positions, including accrued interest | $ | 247 | $ | 246 | |||
Retirement plan and other employee benefits (a) | 1,017 | 1,057 | |||||
Asset retirement and mining reclamation obligations | 457 | 440 | |||||
Unfavorable purchase and sales contracts | 578 | 589 | |||||
Nuclear decommissioning cost over-recovery (Note 13) | 442 | 400 | |||||
Other | 13 | 30 | |||||
Total other noncurrent liabilities and deferred credits | $ | 2,754 | $ | 2,762 | |||
____________
(a) | Includes $851 million and $838 million at June 30, 2014 and December 31, 2013, respectively, representing pension and OPEB liabilities related to Oncor (see Note 13). |
Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $6 million and $7 million for the three months ended June 30, 2014 and 2013, respectively, and totaled $12 million and $13 million for the six months ended June 30, 2014 and 2013, respectively. 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 | |||
2014 | $ | 24 | ||
2015 | $ | 24 | ||
2016 | $ | 24 | ||
2017 | $ | 24 | ||
2018 | $ | 24 | ||
Fair Value of Debt
June 30, 2014 | December 31, 2013 | |||||||||||||||
Debt: | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Borrowings under debtor-in-possession credit facilities (Note 5) | $ | 6,825 | $ | 6,866 | $ | — | $ | — | ||||||||
Pre-petition notes, loans and other debt reported as liabilities subject to compromise (Note 7) | 35,860 | 26,817 | — | — | ||||||||||||
Long-term debt, excluding capitalized lease obligations | 141 | 143 | — | — | ||||||||||||
Pre-petition notes, loans and other debt (excluding capital leases) (Note 7) | — | — | 40,200 | 26,050 | ||||||||||||
We determine fair value in accordance with accounting standards as discussed in Note 11, and at June 30, 2014, 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.
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Supplemental Cash Flow Information
Six Months Ended June 30, | |||||||
2014 | 2013 | ||||||
Cash payments related to: | |||||||
Interest paid (a) | $ | 869 | $ | 1,733 | |||
Capitalized interest | (11 | ) | (14 | ) | |||
Interest paid (net of capitalized interest) (a) | $ | 858 | $ | 1,719 | |||
Income taxes | $ | 49 | $ | 51 | |||
Reorganization items (b) | $ | 53 | $ | — | |||
Noncash investing and financing activities: | |||||||
Principal amount of toggle notes issued in lieu of cash interest | $ | — | $ | 83 | |||
Construction expenditures (c) | $ | 51 | $ | 69 | |||
Debt exchange and extension transactions (d) | $ | (85 | ) | $ | (326 | ) | |
Debt assumed related to acquired combustion turbine trust interest | $ | — | $ | (45 | ) | ||
____________
(a) | Net of amounts received under interest rate swap agreements. |
(b) | Represents cash payments for legal and other consulting services. |
(c) | Represents end-of-period accruals. |
(d) | For the six months ended June 30, 2014, represents $1.836 billion principal amount of loans issued under the EFIH DIP Facility in excess of $1.673 billion principal amount of EFIH First Lien Notes exchanged and $78 million of related accrued interest (see Note 5). For the six months ended June 30, 2013 represents $340 million principal amount of term loans issued under the TCEH Term Loan Facilities in consideration of extension of maturity of the facilities, $1.302 billion principal amount of EFIH debt issued in exchange for $1.310 billion principal amount of EFH Corp. and EFIH debt and $89 million principal amount of EFIH debt issued in exchange for $95 million principal amount of EFH Corp. debt. |
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Item 2. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis of our financial condition and results of operations for the three and six months ended June 30, 2014 and 2013 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 ASC 852-10, 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 sales. 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 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 further enhance Oncor's credit quality and 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. We believe, as several major credit rating agencies have acknowledged, that the likelihood of such substantive consolidation of the Oncor Ring-Fenced Entities' assets and liabilities is remote in consideration of the ring-fencing measures and applicable law.
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 14 to 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 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. We intend to conduct our business operations in the normal course and maintain our focus on achieving excellence in customer service and meeting the needs of electricity consumers in Texas.
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 (see Note 12 to Financial Statements). 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.
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Restructuring Support and Lock-Up Agreement (RSA) — As previously disclosed, after a series of discussions with certain creditors that began in 2013 and in anticipation of the Bankruptcy Filing, on April 29, 2014, the Debtors entered into a Restructuring Support and Lock-Up Agreement (RSA) with various stakeholders (Consenting Parties) in order to effect an agreed upon restructuring of the Debtors through a pre-arranged Chapter 11 plan of reorganization.
On July 24, 2014, pursuant to the RSA, each of EFH Corp., EFIH, EFCH, TCEH, EFIH Finance, Inc. and TCEH Finance Inc. provided a notice of termination of the RSA in accordance with its terms to the Consenting Parties. The RSA termination became effective on July 31, 2014.
The Debtors believe that the RSA provided significant benefit to the Debtors, including, without limitation, (a) enabling the TCEH Debtors to obtain the support of holders of the TCEH first lien secured claims for the TCEH debtor-in-possession financing facility and (b) providing a framework for the restructuring transactions involving EFH Corp. and EFIH described in the RSA, which prompted competing proposals (including, among others, an alternative proposal from NextEra Energy, Inc.).
Each of the Debtors remain committed to the tax-free spin of TCEH and its subsidiaries described in the RSA. Moreover, the TCEH first lien creditors who were party to the RSA have advised the Debtors that, notwithstanding the RSA termination, they intend to continue to work cooperatively with the Debtors and other parties in interest to pursue transactions that can be achieved expeditiously, including a possible tax-free spin of the TCEH Debtors, which will maximize the value of the TCEH Debtors' estates and resolve the Chapter 11 Cases.
In cooperation with various stakeholders, the Debtors have focused, and will continue to focus, on formulating and implementing an effective and efficient plan of reorganization for each of the Debtors under Chapter 11 of the Bankruptcy Code that maximizes enterprise value. The Debtors intend to conduct a court supervised bid process with respect to the restructuring of EFH Corp. and EFIH to maximize their respective enterprise values for all stakeholders. In addition, EFH Corp. and EFIH intend to negotiate with each party that has submitted or does submit a bid with respect to the reorganization of EFH Corp. and EFIH.
EFIH Settlement of First Lien Notes and Related Exchanges — Pursuant to the RSA, certain holders of EFIH First Lien Notes agreed to voluntary settlements of such notes. In June 2014, the Bankruptcy Court issued an order approving this settlement, the EFIH DIP Facility and the settlement of remaining EFIH First Lien Notes, all of which were completed as described in Note 5 to Financial Statements.
The RSA termination does not impact or cancel the EFIH First Lien Notes settlement since such settlement was completed prior to the RSA termination. See Note 9 to Financial Statements for a discussion of litigation regarding alleged makewhole claims of holders of EFIH First Lien Notes in connection with the EFIH First Lien Notes settlement.
Private Letter Ruling — Pursuant to the RSA, on June 10, 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, (ii) the transfer by the Debtors to Reorganized TCEH of certain operating 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. Notwithstanding the termination of the RSA, the Debtors intend to continue to pursue the Private Letter Ruling in connection with any Chapter 11 plan of reorganization that is ultimately proposed.
Operation and Implications of the Chapter 11 Cases — The accompanying consolidated financial statements contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Our ability to continue as a going concern is contingent upon our ability to comply with the financial and other covenants contained in the debtor-in-possession financing (DIP Facilities, described in Note 5 to Financial Statements), the Bankruptcy Court's approval of the Chapter 11 plan of reorganization ultimately proposed by the Debtors and our ability to successfully implement such Chapter 11 plan and obtain new financing, among other factors. As a result of the Chapter 11 Cases, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession under Chapter 11, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Facilities), for amounts other than those reflected in the accompanying consolidated financial statements.
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A Chapter 11 plan of reorganization determines the rights and satisfaction of claims of various creditors and security holders and is subject to the ultimate outcome of negotiations and Bankruptcy Court decisions ongoing through the date on which the Chapter 11 plan is confirmed. The Debtors currently expect that any proposed Chapter 11 plan of reorganization will provide, among other things, mechanisms for settlement of claims against the Debtors' estates, treatment of EFH Corp.'s existing equity holders and the Debtors' respective existing debt holders, potential income tax liabilities and certain corporate governance and administrative matters pertaining to a reorganized EFH Corp. Any proposed Chapter 11 plan of reorganization will be subject to revision prior to submission to the Bankruptcy Court based upon discussions with the Debtors' creditors and other interested parties, and thereafter in response to creditor claims and objections and the requirements of the Bankruptcy Code or the Bankruptcy Court. There can be no assurance that the Debtors will be able to secure approval for any Chapter 11 plan of reorganization it ultimately proposes from the Bankruptcy Court or that any Chapter 11 plan will be accepted by the Debtors' creditors.
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, which will enable each of the Debtors to transition from the Chapter 11 Cases into reorganized companies conducting ordinary course operations outside of bankruptcy. In connection with an exit from bankruptcy, TCEH and EFIH will require a new credit facility, or "exit financing." TCEH's and EFIH's ability to obtain such approval, and TCEH's and EFIH's ability to obtain such financing will depend on, among other things, the timing and outcome of various ongoing matters in the Chapter 11 Cases.
In general, the Debtors have received final bankruptcy court orders with respect to "first day motions" that allow the Debtors to operate their businesses in the ordinary course of business, 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 programs at our retail electricity sales 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 June 2014, the Bankruptcy Court issued orders approving the TCEH and EFIH DIP Facilities and the exchange and settlement of the EFIH First Lien Notes as described in Note 5 to Financial Statements.
Pre-Petition Claims — Holders of pre-petition claims will be required to file proofs of claims by the "bar dates" 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 has not yet established the bar date. Differences between liability amounts recorded by the company as liabilities subject to compromise and claims filed by creditors will be investigated and, if necessary, the Bankruptcy Court will make a final determination of the allowable claim. Differences between those final allowed claims and the liabilities recorded in the condensed consolidated balance sheet will be recognized as reorganization items in our condensed statement 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. 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 the company's financial statements.
Regulatory Requirements Related to the Bankruptcy Filing — 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. In addition, the Debtors will seek all necessary and appropriate regulatory approvals necessary to complete any transactions proposed in the Chapter 11 plan. 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.
Natural Gas Hedging Program and Termination of Positions — In previous years TCEH had entered into long-term market transactions involving natural gas-related financial instruments designed to mitigate the effect of natural gas price changes on future electricity revenues. These instruments are deemed to be "forward contracts" under the Bankruptcy Code. The Bankruptcy Filing constituted an event of default under the natural gas hedging agreements, and in accordance with the contractual terms, counterparties terminated the hedging positions 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 shortly after the Bankruptcy Filing. These positions represented the substantial majority of the positions in the program. See discussion below regarding termination of interest rate swaps with the same counterparties and related contractual netting arrangements.
The terminated positions, which would have all matured by December 31, 2014, represented forward sales totaling approximately 88 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 10,000 GWh at an assumed 8.5 market heat rate) at a weighted average hedge price of $7.83 per MMBtu.
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The natural gas positions have resulted in realized and unrealized net gains (losses), reported in net gain (loss) from commodity hedging and trading activities, as provided in the table below. Realized net gains presented below for the three and six months ended June 30, 2014 represent amounts settled in cash and therefore do not include $117 million of realized net gains that are included (as an offset) in the net settlement liability arising from the terminations of interest rate swap and natural gas hedging positions as discussed below. (Corresponding amount is excluded from unrealized net losses.)
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Realized net gains | $ | 232 | $ | 224 | $ | 345 | $ | 480 | |||||||
Unrealized net losses including reversals of previously recorded amounts related to positions settled | (269 | ) | (116 | ) | (433 | ) | (482 | ) | |||||||
Total | $ | (37 | ) | $ | 108 | $ | (88 | ) | $ | (2 | ) | ||||
See "Results of Operations" for discussion of the results of all hedging and trading activity, including the results of the natural gas hedging program.
TCEH Interest Rate Swaps and Terminations of Positions — TCEH had employed interest rate swaps to hedge exposure to its variable rate debt. TCEH had also entered into interest rate basis swap transactions that further reduced the fixed borrowing costs achieved through the interest rate swaps. These instruments are deemed to be "forward contracts" under the Bankruptcy Code. The Bankruptcy Filing constituted an event of default under the interest rate swap agreements, and in accordance with the contractual terms, the counterparties terminated all the TCEH agreements shortly after the Bankruptcy Filing. All of the TCEH interest rate swaps 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.
The table below presents information for the interest rate swaps terminated:
Fixed Rates | Expiration Dates | Notional Amount | ||||||||||
5.5 | % | - | 9.3% | October 2014 | $ | 18.077 | billion | |||||
6.8 | % | - | 9.0% | October 2015 through October 2017 | $ | 12.600 | billion | |||||
Basis swaps totaled $1.05 billion notional amount. The remaining basis swaps had expiration dates in August 2014.
The interest rate swaps have resulted in realized and unrealized net gains (losses), reported in interest expense and related charges, as presented in the table below. Realized net losses presented below for the three and six months ended June 30, 2014 represent amounts settled in cash and therefore do not include $1.225 billion of realized net losses that are included in the net liability arising from the terminations and $127 million in realized losses on matured positions that have not been settled as discussed immediately below. (Corresponding amounts are excluded from unrealized net gains.)
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Realized net loss | $ | — | $ | (155 | ) | $ | (66 | ) | $ | (306 | ) | ||||
Unrealized net gain including reversals related to realized net loss amounts | 1 | 338 | 65 | 486 | |||||||||||
Total | $ | 1 | $ | 183 | $ | (1 | ) | $ | 180 | ||||||
Net First-Lien Liability for Terminated Natural Gas Hedging Positions and Interest Rate Swaps — 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, as well as counterparties to only our interest rate swaps. The net liability recorded upon termination of the interest rate swaps and natural gas hedges totaled $1.108 billion, which represents the $1.225 billion realized loss related to the terminated interest rate swaps net of the $117 million realized gain related to the terminated natural gas hedging positions. In addition, net accounts payable amounts related to matured interest rate swaps, which totaled $127 million at June 30, 2014, are secured by the first-lien 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. Further, as noted in Note 8 to Financial Statements, the net liability is subject to adequate protection payments during the pendency of the Chapter 11 Cases.
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Overall Hedged Generation Position — Taking together forward wholesale and retail electricity sales with all hedging positions, at June 30, 2014 and December 31, 2013, we had effectively hedged an estimated 76% and 95%, respectively, of the price exposure, on a natural gas equivalent basis, related to our expected generation output for 2014 (assuming an 8.5 market heat rate). The majority of our hedges are financial natural gas positions and at December 31, 2013 included those long-term positions entered into in previous years and since terminated, as discussed above, as well as more recent short-term hedges. The decline in the overall hedged position was primarily due to the termination of the natural gas hedging positions.
Commodity Price Sensitivities — The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas prices, market heat rates and diesel fuel prices on realized pretax earnings for the periods presented. The estimates related to price sensitivity are based on our unhedged position and forward prices at June 30, 2014, 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 2014 | 2015 | ||
$1.00/MMBtu change in natural gas price (a)(b) | $ ~51 | $ ~360 | |
0.1/MMBtu/MWh change in market heat rate (c) | $ ~4 | $ ~25 | |
$1.00/gallon change in diesel fuel price | $ ~3 | $ ~35 | |
___________
(a) | Balance of 2014 is from August 1, 2014 through December 31, 2014. |
(b) | Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally being on the margin 75% to 90% of the time in the ERCOT market (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated). Excludes the impact of economic backdown. |
(c) | Based on Houston Ship Channel natural gas prices at June 30, 2014. |
Environmental Matters — See Note 9 to Financial Statements for a discussion of the CSAPR and other EPA actions as well as related litigation.
Greenhouse Gas Emissions — In June 2014, the EPA proposed guidelines that address greenhouse gas (GHG) emissions from existing electricity generation plants. The proposed guidelines would establish state-specific emission rate goals to reduce nationwide carbon dioxide (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. The comment period on the proposal closes October 16, 2014, and the EPA is expected to finalize the guidelines by June 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.
In June 2014, the US Supreme Court issued its opinion regarding the EPA's determination that its regulation of GHG emissions from motor vehicles triggered greenhouse gas permitting requirements for stationary sources under the Clean Air Act (CAA). The US Supreme Court affirmed in part and reversed in part the D.C. Circuit Court's decision. The US Supreme Court reversed the D.C. Circuit Court in holding that the EPA exceeded its statutory authority under the CAA when it determined that stationary source emissions of GHG's, alone, trigger permitting obligations under the Prevention of Significant Deterioration (PSD) and Title V programs. The US Supreme Court affirmed the D.C. Circuit Court's ruling that "best available control technology" (BACT) under PSD and Title V can be applied to GHG emissions if the source has otherwise triggered PSD permitting due to other emissions. We were not a party to that case. It is uncertain how, if at all, the decision and any subsequent proceedings will affect our results of operations, liquidity or financial condition.
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Mercury and Air Toxics Standard (MATS) — In December 2011, the EPA finalized the MATS rule, which regulates the emissions of mercury, nonmercury metals, hazardous organic compounds and acid gases. Any additional control equipment retrofits on our lignite/coal fueled generation units required to comply with the MATS rule as finalized would need to be installed within three to four years from the April 2012 effective date of the rule. In April 2012, we filed a petition for review of the MATS rule in the D.C. Circuit Court. Certain states and industry participants have also filed petitions for review in the D.C. Circuit Court and the D.C. Circuit Court heard oral arguments in December 2013. In April 2014, the D.C. Circuit Court issued its ruling upholding the MATS rule and dismissing all challenges. In July 2014, certain parties, including the Utility Air Regulatory Group and the National Mining Association, filed petitions for certiorari with the US Supreme Court. We cannot predict whether the US Supreme Court will accept review of the case. In November 2012, the EPA proposed revised standards for new coal fired generation units and other minor changes to the MATS rule, including changes to the work practice standards affecting all units. In March 2013, the EPA finalized the revised standards for new coal fired units and certain other minor changes but did not address the work practice standards. In June 2013, the EPA solicited comments on certain proposed changes to these work practice standards. We cannot predict the outcome of this rulemaking or the EPA's timing to issue the final work practice standards. In 2013, the TCEQ approved one-year MATS compliance extensions for our Big Brown and Sandow 4 generation plants.
Regional Haze — SO2 and NOX reductions required under the EPA's Regional Haze (Visibility) Program rule addressing best available retrofit technology (BART) apply to electricity generation units built between 1962 and 1977. The reductions are required either on a unit-by-unit basis or 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, which we believe would not have a material impact on our generation facilities. In December 2011, the EPA proposed a limited disapproval of the Regional Haze SIP due to its reliance on the CAIR and a Federal Implementation Plan (FIP) for Texas providing that the inclusion in the CSAPR programs meets the BART program's regional haze requirements for SO2 and NOX reductions. In June 2012, the EPA finalized the limited disapproval of the Regional Haze SIP to the extent it relies on CAIR, but did not finalize a FIP for Texas, stating that it needed more time to review the Regional Haze SIP. 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 held in abeyance. Following the US Supreme Court's ruling in the CSAPR described in Note 9 to Financial Statements, the D.C. Circuit Court ordered the parties to file motions to govern further proceedings on July 30, 2014. We and other parties to those proceedings are conferring regarding how further proceedings should be governed.
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. In May 2013, the D.C. Circuit amended the consent decree and extended the dates for the EPA to propose and finalize a decision on the Regional Haze SIP to May and December 2014, respectively. In June 2014, the D.C. Circuit Court 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 requesting this extension, the EPA indicated that it needed time to evaluate the reasonable progress goal provisions of the Regional Haze Program. As part of this evaluation, a number of power companies in Texas, including Luminant, have received requests for information regarding SO2 controls. We cannot predict whether or when the EPA will fully approve the Regional Haze SIP or finalize a FIP for Texas regarding regional haze, or a FIP's impact on our results of operations, liquidity or financial condition.
Water — In May 2014, the EPA adopted Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities. Although the rule does not mandate a certain control technology, it does require site-specific assessments of technology feasibility on a case-by-case basis at the state level. Compliance with this rule requires assessments and reports six months following implementation of the rule, but allows up to eight full years following promulgation for full compliance. Compliance with the rule is not anticipated to have a material effect on our results of operations, liquidity or financial condition.
Recent PUCT/ERCOT Actions — A scheduled increase to the ERCOT system-wide offer cap was implemented effective June 2014, raising the cap from $5,000 per MWh to $7,000 per MWh. In addition, the operating reserve demand curve (ORDC) was implemented in the ERCOT market effective June 2014. The ORDC provides for a price adder to real-time wholesale electricity prices as reserves decline, subject to a $9,000 per MWh energy price cap. We cannot predict the frequency of market conditions in the ERCOT market that could result in these prices, which would likely be due to extreme weather and/or reduced generation availability, among other factors.
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Oncor Matters with the PUCT — Transmission Cost Recovery and Rates (PUCT Docket Nos. 42558) — 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 May 2014, Oncor filed an application to update the TCRF, which will become effective September 1, 2014. This application was designed to increase Oncor's billings for the period from September 2014 through February 2015 by $71 million.
Transmission Interim Rate Update Applications (PUCT Docket Nos. 42706) — 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 July 2014, Oncor filed an application for an interim update of its TCOS rate. Oncor anticipates PUCT approval of the new rate in September 2014. Oncor's annualized revenues are expected to increase by an estimated $12 million with approximately $8 million of this increase recoverable through transmission costs charged to wholesale customers and $4 million recoverable from REPs through the TCRF component of Oncor's delivery rates.
Application for 2015 Energy Efficiency Cost Recovery Factor Surcharge (PUCT Docket No. 42559) — In May 2014, Oncor filed an application with the PUCT to request approval of the energy efficiency cost recovery factor (EECRF) for 2015. PUCT rules require Oncor to make an annual EECRF filing by the first business day in June in each year for implementation on March 1 of the next calendar year. The requested 2015 EECRF was $68 million as compared to $73 million established for 2014, and would result in a monthly charge for residential customers of $1.03 as compared to the 2014 residential charge of $1.01 per month. The 2015 EECRF is designed to recover $50 million of Oncor's costs for the 2015 program year, a $23 million performance bonus based on Oncor's 2013 results and a $5 million decrease for over-recovery of 2013 costs.
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RESULTS OF OPERATIONS
Consolidated Financial Results — Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013
See "Competitive Electric Segment – Financial Results" below for a discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain (loss) from commodity hedging and trading activities; operating costs; depreciation and amortization; SG&A expenses and franchise and revenue-based taxes.
See Note 15 to Financial Statements for details of other income and deductions.
Results include fees for legal and other professional services associated with our debt restructuring activities prior to the Petition Date, which totaled $21 million in 2014 and $23 million in 2013 and are reported in SG&A expenses. Of the 2014 amount, $12 million is included in the Competitive Electric segment results and $9 million is included in Corporate and Other activities. Of the 2013 amount, $21 million is included in the Competitive Electric segment results and $2 million is included in Corporate and Other activities. Legal and other professional services costs associated 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 $27 million to $571 million in 2014. The decrease reflected:
• | $552 million in lower interest expense on pre-petition debt due to the cessation of interest upon the Bankruptcy Filing and the termination of the interest rate swap agreements shortly after the Bankruptcy Filing, and |
• | $35 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
• | $338 million in lower mark-to-market net gains on interest rate swaps due to the termination of the agreements; |
• | $211 million in expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of secured creditors, and |
• | $14 million in interest expense on debtor-in-possession financing. |
See Note 8 to Financial Statements for details of interest expense and related charges.
Reorganization items totaled $665 million for the quarter and year-to-date and included a $278 million liability adjustment arising from termination of interest rate swap agreements and natural gas hedging positions (see Note 12 to Financial Statements), $185 million in fees associated with completion of the TCEH and EFIH DIP facilities (see Note 5 to Financial Statements) and a $108 million net loss on exchange and settlement of the EFIH First Lien Notes. See Note 6 to Financial Statements for additional discussion.
Income tax benefit totaled $398 million and $351 million in 2014 and 2013, respectively. Excluding the $183 million income tax benefit recorded in 2013 related to resolution of IRS audit matters, the effective tax benefit rate was 32.0% and 33.9% in 2014 and 2013, respectively. The decrease in the effective tax rate was driven by higher nondeductible legal and other professional services costs related to the Chapter 11 Cases.
Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) decreased $2 million to $72 million in 2014. The decrease in equity earnings of Oncor reflected decreased revenue from lower average consumption driven by the effects of milder weather and higher depreciation and property taxes, partially offset by increased revenue from higher transmission rates and growth in points of delivery and lower interest expense. See Note 3 to Financial Statements.
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Net loss for EFH Corp. increased $703 million to $774 million in 2014.
• | Net loss for the Competitive Electric segment increased $353 million to $591 million. |
• | Earnings from the Regulated Delivery segment decreased $2 million to $72 million as discussed above. |
• | After-tax net expenses from Corporate and Other activities totaled $255 million in 2014 compared to net income of $93 million in 2013. The change reflects a $204 million income tax benefit in 2013 related to the Corporate and Other portion of the $183 million income tax benefit related to resolution of IRS audit matters referred to above, and charges of $156 million, or $242 million pre-tax, for the Corporate and Other portion of reorganization items discussed above, partially offset by $29 million, or $44 million pre-tax, in lower interest expense. The amounts in 2014 and 2013 include recurring interest expense on outstanding debt, as well as corporate general and administrative expenses. |
Consolidated Financial Results — Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
See "Competitive Electric Segment – Financial Results" below for a discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain (loss) from commodity hedging and trading activities; operating costs; depreciation and amortization; SG&A expenses and franchise and revenue-based taxes.
See Note 15 to Financial Statements for details of other income and deductions.
Results include fees for legal and other professional services associated with our debt restructuring activities prior to the Petition Date, which totaled $50 million in 2014 and $36 million in 2013 and are reported in SG&A expenses. Of the 2014 amount, $28 million is included in the Competitive Electric segment results and $22 million is included in Corporate and Other activities. Of the 2013 amount, $34 million is included in the Competitive Electric segment results and $2 million is included in Corporate and Other activities. Legal and other professional services costs associated with the Chapter 11 Cases since the Petition Date are now being reported in reorganization items as discussed above.
Interest expense and related charges increased $54 million to $1.436 billion in 2014. The increase reflected:
• | $423 million in lower mark-to-market net gains on interest rate swaps due to the termination of the agreements; |
• | $211 million in expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of secured creditors; and |
• | $14 million in interest expense on debtor-in-possession financing, |
partially offset by
• | $550 million in lower interest expense on pre-petition debt due to the cessation of interest upon the Bankruptcy Filing and the termination of the interest rate swap agreements shortly after the Bankruptcy Filing, and |
• | $38 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. |
See Note 8 to Financial Statements for details of interest expense and related charges.
Income tax benefit totaled $759 million and $825 million in 2014 and 2013, respectively. Excluding the $267 million income tax benefit recorded in 2013 related to resolution of IRS audit matters, the effective tax benefit rate was 33.1% and 34.7% in 2014 and 2013, respectively. The decrease in the effective tax rate was driven by higher nondeductible legal and other professional services costs related to the Chapter 11 Cases.
Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) increased $11 million to $152 million in 2014. The increase in equity earnings of Oncor reflected increased revenue from higher transmission rates, higher average consumption driven by the effects of colder winter weather in the first quarter and growth in points of delivery. These favorable effects were partially offset by higher income taxes reflecting the $11 million favorable tax effect in 2013 due to resolution of certain income tax positions and an increase in non-deductible amortization of regulatory assets, higher depreciation and higher property taxes. See Note 3 to Financial Statements.
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Net loss for EFH Corp. increased $743 million to $1.383 billion in 2014.
• | Net loss for the Competitive Electric segment increased $372 million to $1.158 billion. |
• | Earnings from the Regulated Delivery segment increased $11 million to $152 million as discussed above. |
• | After-tax net expenses from Corporate and Other activities totaled $377 million in 2014 compared to net income of $5 million in 2013. The change reflects a $227 million income tax benefit in 2013 related to the Corporate and Other portion of the $267 million income tax benefit related to resolution of IRS audit matters referred to above, charges of $156 million, or $242 million pre-tax, for the Corporate and Other portion of reorganization items discussed above, and $13 million, or $20 million pre-tax, in higher legal and other professional fees for the Corporate and Other portion of our debt restructuring activities, partially offset by $27 million, or $41 million pre-tax, in lower interest expense. The amounts in 2014 and 2013 include recurring interest expense on outstanding debt, as well as corporate general and administrative expenses. |
Competitive Electric Segment
Financial Results
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Operating revenues | $ | 1,406 | $ | 1,419 | $ | 2,924 | $ | 2,679 | |||||||
Fuel, purchased power costs and delivery fees | (656 | ) | (687 | ) | (1,388 | ) | (1,323 | ) | |||||||
Net gain (loss) from commodity hedging and trading activities | 27 | 168 | (192 | ) | (29 | ) | |||||||||
Operating costs | (242 | ) | (266 | ) | (455 | ) | (496 | ) | |||||||
Depreciation and amortization | (329 | ) | (337 | ) | (656 | ) | (681 | ) | |||||||
Selling, general and administrative expenses | (151 | ) | (169 | ) | (328 | ) | (327 | ) | |||||||
Franchise and revenue-based taxes | (18 | ) | (16 | ) | (36 | ) | (33 | ) | |||||||
Other income | 2 | 3 | 7 | 6 | |||||||||||
Other deductions | (23 | ) | (1 | ) | (24 | ) | (4 | ) | |||||||
Interest income | — | 1 | — | 5 | |||||||||||
Interest expense and related charges | (456 | ) | (439 | ) | (1,155 | ) | (1,060 | ) | |||||||
Reorganization items | (423 | ) | — | (423 | ) | — | |||||||||
Loss before income taxes | (863 | ) | (324 | ) | (1,726 | ) | (1,263 | ) | |||||||
Income tax benefit | 272 | 86 | 568 | 477 | |||||||||||
Net loss | $ | (591 | ) | $ | (238 | ) | $ | (1,158 | ) | $ | (786 | ) | |||
58
Competitive Electric Segment
Sales Volume and Customer Count Data
Three Months Ended June 30, | % Change | Six Months Ended June 30, | % Change | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
Sales volumes: | |||||||||||||||||
Retail electricity sales volumes – (GWh): | |||||||||||||||||
Residential | 5,070 | 5,475 | (7.4 | )% | 10,245 | 10,080 | 1.6 | % | |||||||||
Small business (a) | 1,393 | 1,332 | 4.6 | % | 2,661 | 2,522 | 5.5 | % | |||||||||
Large business and other customers | 2,650 | 2,481 | 6.8 | % | 4,921 | 4,799 | 2.5 | % | |||||||||
Total retail electricity | 9,113 | 9,288 | (1.9 | )% | 17,827 | 17,401 | 2.4 | % | |||||||||
Wholesale electricity sales volumes (b) | 7,201 | 8,467 | (15.0 | )% | 17,002 | 17,536 | (3.0 | )% | |||||||||
Total sales volumes | 16,314 | 17,755 | (8.1 | )% | 34,829 | 34,937 | (0.3 | )% | |||||||||
Average volume (kilowatt-hours) per residential customer (c) | 3,361 | 3,556 | (5.5 | )% | 6,768 | 6,518 | 3.8 | % | |||||||||
Weather (North Texas average) – percent of normal (d): | |||||||||||||||||
Cooling degree days | 100.1 | % | 97.9 | % | 2.2 | % | 98.8 | % | 98.2 | % | 0.6 | % | |||||
Heating degree days | 179.8 | % | 312.2 | % | (42.4 | )% | 121.9 | % | 104.1 | % | 17.1 | % | |||||
Customer counts: | |||||||||||||||||
Retail electricity customers (end of period, in thousands) (e): | |||||||||||||||||
Residential | 1,511 | 1,532 | (1.4 | )% | |||||||||||||
Small business (a) | 177 | 176 | 0.6 | % | |||||||||||||
Large business and other customers | 20 | 17 | 17.6 | % | |||||||||||||
Total retail electricity customers | 1,708 | 1,725 | (1.0 | )% | |||||||||||||
____________
(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. |
59
Competitive Electric Segment
Revenue and Commodity Hedging and Trading Activities
Three Months Ended June 30, | % Change | Six Months Ended June 30, | % Change | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||||
Operating revenues: | |||||||||||||||||||||
Retail electricity revenues: | |||||||||||||||||||||
Residential | $ | 690 | $ | 714 | (3.4 | )% | $ | 1,373 | $ | 1,311 | 4.7 | % | |||||||||
Small business (a) | 168 | 168 | — | % | 330 | 326 | 1.2 | % | |||||||||||||
Large business and other customers | 187 | 176 | 6.3 | % | 347 | 337 | 3.0 | % | |||||||||||||
Total retail electricity revenues | 1,045 | 1,058 | (1.2 | )% | 2,050 | 1,974 | 3.9 | % | |||||||||||||
Wholesale electricity revenues (b)(c) | 291 | 297 | (2.0 | )% | 720 | 571 | 26.1 | % | |||||||||||||
Amortization of intangibles (d) | 6 | 6 | — | % | 12 | 11 | 9.1 | % | |||||||||||||
Other operating revenues | 64 | 58 | 10.3 | % | 142 | 123 | 15.4 | % | |||||||||||||
Total operating revenues | $ | 1,406 | $ | 1,419 | (0.9 | )% | $ | 2,924 | $ | 2,679 | 9.1 | % | |||||||||
Net gain (loss) from commodity hedging and trading activities: | |||||||||||||||||||||
Realized net gains | $ | 328 | $ | 214 | $ | 363 | $ | 510 | |||||||||||||
Unrealized net losses | (301 | ) | (46 | ) | (555 | ) | (539 | ) | |||||||||||||
Total | $ | 27 | $ | 168 | $ | (192 | ) | $ | (29 | ) | |||||||||||
____________
(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. As a result, these line item amounts include a noncash component that we deem "unrealized." (The offsetting differences between contract and market prices are reported in net gain (loss) from commodity hedging and trading activities.) These amounts are as follows: |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Reported in revenues | $ | — | $ | — | $ | — | $ | (1 | ) | ||||||
Reported in fuel and purchased power costs | 1 | 4 | 5 | 11 | |||||||||||
Net gain | $ | 1 | $ | 4 | $ | 5 | $ | 10 | |||||||
(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 power sales agreements resulting from purchase accounting. |
60
Competitive Electric Segment
Production, Purchased Power and Delivery Cost Data
Three Months Ended June 30, | % Change | Six Months Ended June 30, | % Change | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||||
Fuel, purchased power costs and delivery fees ($ millions): | |||||||||||||||||||||
Fuel for nuclear facilities | $ | 36 | $ | 39 | (7.7 | )% | $ | 79 | $ | 84 | (6.0 | )% | |||||||||
Fuel for lignite/coal facilities | 172 | 208 | (17.3 | )% | 385 | 401 | (4.0 | )% | |||||||||||||
Total nuclear and lignite/coal facilities | 208 | 247 | (15.8 | )% | 464 | 485 | (4.3 | )% | |||||||||||||
Fuel for natural gas facilities and purchased power costs (a) | 74 | 71 | 4.2 | % | 159 | 125 | 27.2 | % | |||||||||||||
Amortization of intangibles (b) | 11 | 10 | 10.0 | % | 20 | 19 | 5.3 | % | |||||||||||||
Other costs | 53 | 49 | 8.2 | % | 125 | 98 | 27.6 | % | |||||||||||||
Fuel and purchased power costs | 346 | 377 | (8.2 | )% | 768 | 727 | 5.6 | % | |||||||||||||
Delivery fees (c) | 310 | 310 | — | % | 620 | 596 | 4.0 | % | |||||||||||||
Total | $ | 656 | $ | 687 | (4.5 | )% | $ | 1,388 | $ | 1,323 | 4.9 | % | |||||||||
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh: | |||||||||||||||||||||
Nuclear facilities | $ | 8.04 | $ | 8.43 | (4.6 | )% | $ | 8.23 | $ | 8.45 | (2.6 | )% | |||||||||
Lignite/coal facilities (d) | $ | 20.01 | $ | 20.25 | (1.2 | )% | $ | 20.52 | $ | 20.31 | 1.0 | % | |||||||||
Natural gas facilities and purchased power (e) | $ | 46.58 | $ | 47.50 | (1.9 | )% | $ | 49.94 | $ | 46.84 | 6.6 | % | |||||||||
Delivery fees per MWh | $ | 33.92 | $ | 33.22 | 2.1 | % | $ | 34.64 | $ | 34.09 | 1.6 | % | |||||||||
Production and purchased power volumes (GWh): | |||||||||||||||||||||
Nuclear facilities | 4,505 | 4,666 | (3.5 | )% | 9,571 | 9,897 | (3.3 | )% | |||||||||||||
Lignite/coal facilities (f) | 10,841 | 12,244 | (11.5 | )% | 23,254 | 23,530 | (1.2 | )% | |||||||||||||
Total nuclear and lignite/coal facilities | 15,346 | 16,910 | (9.2 | )% | 32,825 | 33,427 | (1.8 | )% | |||||||||||||
Natural gas facilities | 142 | 187 | (24.1 | )% | 334 | 242 | 38.0 | % | |||||||||||||
Purchased power (g) | 826 | 658 | 25.5 | % | 1,670 | 1,268 | 31.7 | % | |||||||||||||
Total energy supply volumes | 16,314 | 17,755 | (8.1 | )% | 34,829 | 34,937 | (0.3 | )% | |||||||||||||
Capacity factors: | |||||||||||||||||||||
Nuclear facilities | 89.7 | % | 92.9 | % | (3.4 | )% | 95.8 | % | 99.1 | % | (3.3 | )% | |||||||||
Lignite/coal facilities (f) | 61.9 | % | 69.9 | % | (11.4 | )% | 66.8 | % | 67.6 | % | (1.2 | )% | |||||||||
Total | 68.1 | % | 75.0 | % | (9.2 | )% | 73.3 | % | 74.6 | % | (1.7 | )% | |||||||||
____________
(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 delivery fee charges from Oncor. |
(d) | 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 previous page. |
(e) | Excludes volumes related to line loss and power imbalances and unrealized amounts referenced in footnote (d) immediately above. |
(f) | Includes the estimated effects of production backdown (including seasonal operations) of lignite/coal fueled units totaling 4,550 GWh and 2,580 GWh for the three months ended June 30, 2014 and 2013, respectively, and 8,290 GWh and 6,930 GWh for the six months ended June 30, 2014 and 2013, respectively. |
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(g) | Includes amounts related to line loss and power imbalances. |
Competitive Electric Segment — Financial Results — Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013
Operating revenues decreased $13 million, or 1%, to $1.406 billion in 2014.
Retail electricity revenues decreased $13 million, or 1%, to $1.045 billion in 2014 reflecting a $20 million decrease in sales volumes, partially offset by $7 million in higher average prices. Sales volumes decreased 2%. Residential volumes decreased 7% reflecting milder weather and a 1% decrease in customer counts. Business markets volumes increased 6% reflecting changes in customer mix and higher customer counts. Overall average retail pricing increased 1% reflecting higher residential pricing due to higher wholesale electricity prices and higher delivery fees incurred and passed on to customers.
Wholesale electricity revenues decreased $6 million, or 2%, to $291 million in 2014 reflecting a $45 million decrease in sales volumes, substantially offset by a $39 million increase in higher average prices. Wholesale sales volumes decreased 15% reflecting lower generation volumes. Higher average prices reflected an increase in natural gas prices.
Fuel, purchased power costs and delivery fees decreased $31 million to $656 million in 2014 driven by $36 million in decreased lignite/coal fuel costs. Lower lignite/coal fuel costs reflected lower generation volumes and increased lignite in the fuel blend, partially offset by higher lignite mining costs and purchased coal prices.
An 11% decrease in lignite/coal fueled generation volumes reflected production backdown due to rail congestion that reduced deliveries of purchased coal. A 3% decrease in nuclear fueled generation volumes reflected an increase in planned outage days.
Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $27 million and $168 million in net gains for the three months ended June 30, 2014 and 2013, respectively, and includes the natural gas hedging positions discussed above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Hedging Program and Termination of Positions," as well as other hedging positions.
Three Months Ended June 30, 2014 | |||||||||||
Net Realized Gains | Net Unrealized Gains (Losses) | Total | |||||||||
Hedging positions | $ | 328 | $ | (304 | ) | $ | 24 | ||||
Trading positions | — | 3 | 3 | ||||||||
Total | $ | 328 | $ | (301 | ) | $ | 27 | ||||
Three Months Ended June 30, 2013 | |||||||||||
Net Realized Gains (Losses) | Net Unrealized Gains (Losses) | Total | |||||||||
Hedging positions | $ | 252 | $ | (81 | ) | $ | 171 | ||||
Trading positions | (38 | ) | 35 | (3 | ) | ||||||
Total | $ | 214 | $ | (46 | ) | $ | 168 | ||||
Net realized gains on hedging positions for the three months ended June 30, 2014 includes $117 million arising from the termination by counterparties of natural gas hedging positions, which is reflected in the net liability for terminations of interest rate swaps as discussed above. The liability is secured by a first-lien interest.
Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $1 million and $4 million in net gains in 2014 and 2013, respectively (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).
Operating costs decreased $24 million, or 9%, to $242 million in 2014. The decrease was driven by lower maintenance and other costs at lignite/coal fueled generation units due to fewer planned and unplanned outage days.
Depreciation and amortization expenses decreased $8 million, or 2%, to $329 million reflecting useful lives of certain lignite/coal generation equipment being longer than originally estimated.
62
SG&A expenses decreased $18 million, or 11%, to $151 million in 2014 reflecting $9 million in lower legal and other professional services costs associated with our debt restructuring activities prior to the Petition Date and $6 million in lower other professional services costs. Legal and other professional services costs associated with the Chapter 11 Cases since the Petition Date are now being reported in reorganization items as discussed below.
Other deductions totaled $23 million in 2014 and $1 million in 2013. Other deductions in 2014 include $21 million related to write-off of deferred costs related to cancelled mining projects.
Interest expense and related charges increased $17 million, or 4%, to $456 million in 2014. The increase reflected:
• | $337 million in lower mark-to-market net gains on interest rate swaps due to the termination of the agreements; |
• | $211 million in expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of secured creditors; and |
• | $6 million in interest expense on debtor-in-possession financing, |
partially offset by
• | $489 million in lower interest expense on pre-petition debt due to the cessation of interest upon the Bankruptcy Filing and the termination of the interest rate swap agreements shortly after the Bankruptcy Filing, and |
• | $46 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. |
Reorganization items in the quarter and year-to-date totaled $423 million and included a $277 million liability adjustment arising from termination of interest rate swap agreements and natural gas hedging positions (see Note 12 to Financial Statements) and $92 million in fees associated with completion of the TCEH DIP Facility (see Note 5 to Financial Statements). See Note 6 to Financial Statements for additional discussion.
Income tax benefit totaled $272 million and $86 million on pretax losses in 2014 and 2013, respectively. Excluding the $21 million income tax expense recorded in 2013 related to resolution of IRS audit matters, the effective tax benefit rate was 31.5% and 33.0% in 2014 and 2013, respectively. The decrease in the effective tax rate was driven by higher nondeductible legal and other professional services costs related to the Chapter 11 Cases.
Net loss increased $353 million to $591 million in 2014. The change reflected reorganization items and lower net gains from commodity hedging and trading activities.
63
Competitive Electric Segment — Financial Results — Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
Operating revenues increased $245 million, or 9%, to $2.924 billion in 2014.
Retail electricity revenues increased $76 million, or 4%, to $2.050 billion in 2014 reflecting a $48 million increase in sales volumes and $28 million in higher average prices. Sales volumes increased 2%. Residential volumes increased 2% driven by colder weather in the first quarter, partially offset by a 1% decrease in customer counts. Business markets volumes increased 4% reflecting changes in customer mix and higher customer counts. Overall average retail pricing increased 1% reflecting higher residential pricing due to higher wholesale electricity prices and higher delivery fees incurred and passed on to customers.
Wholesale electricity revenues increased $149 million, or 26%, to $720 million in 2014 reflecting a $166 million increase due to higher average prices, partially offset by a $17 million decrease in sales volumes. Higher average prices reflected an increase in natural gas prices. Wholesale sales volumes decreased 3% reflecting lower generation volumes.
Fuel, purchased power costs and delivery fees increased $65 million to $1.388 billion in 2014. Fuel for natural gas facilities and purchased power costs increased $34 million reflecting the effect of colder weather on natural gas prices and purchased power costs in the first quarter. Delivery fees increased $24 million reflecting higher retail volumes and rates. These increases were partially offset by $16 million in lower lignite/coal fuel costs reflecting lower generation volumes and higher lignite in the fuel blend.
A 3% decrease in nuclear fueled generation volumes reflected an increase in planned and unplanned outage days in 2014. A 1% decrease in lignite/coal fueled generation volumes reflected an 11% decrease in the second quarter reflecting production backdown due to rail congestion that reduced deliveries of purchased coal, substantially offset by a 10% increase in the first quarter reflecting decreased economic-driven production backdown due to higher wholesale electricity prices.
Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $192 million and $29 million in net losses for the six months ended June 30, 2014 and 2013, respectively, and includes the natural gas hedging positions discussed above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Hedging Program and Termination of Positions," as well as other hedging positions.
Six Months Ended June 30, 2014 | |||||||||||
Net Realized Gains (Losses) | Net Unrealized Gains (Losses) | Total | |||||||||
Hedging positions | $ | 368 | $ | (561 | ) | $ | (193 | ) | |||
Trading positions | (5 | ) | 6 | 1 | |||||||
Total | $ | 363 | $ | (555 | ) | $ | (192 | ) | |||
Six Months Ended June 30, 2013 | |||||||||||
Net Realized Gains (Losses) | Net Unrealized Gains (Losses) | Total | |||||||||
Hedging positions | $ | 547 | $ | (562 | ) | $ | (15 | ) | |||
Trading positions | (37 | ) | 23 | (14 | ) | ||||||
Total | $ | 510 | $ | (539 | ) | $ | (29 | ) | |||
Net realized gains on hedging positions for the six months ended June 30, 2014 includes $117 million arising from the termination by counterparties of natural gas hedging positions, which is reflected in the net liability for terminations of interest rate swaps as discussed above. The liability is secured by a first-lien interest. In addition, unrealized losses related to hedging positions in the six months ended June 30, 2014 reflected the effect of increased natural gas prices on the valuations of unsettled positions.
Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $5 million and $10 million in net gains in 2014 and 2013, respectively (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).
Operating costs decreased $41 million, or 8%, to $455 million in 2014. The decrease was driven by lower maintenance and other costs at lignite/coal fueled generation units due to fewer planned and unplanned outage days in 2014.
64
Depreciation and amortization expenses decreased $25 million, or 4%, to $656 million reflecting useful lives of certain lignite/coal generation equipment being longer than originally estimated.
SG&A expenses increased $1 million to $328 million in 2014 reflecting $12 million in higher employee compensation and benefit costs and $7 million in higher retail bad debt expense, substantially offset by $10 million in lower allocated Sponsor Group management fees and $6 million in lower legal and other professional services costs associated with our debt restructuring activities prior to the Petition Date. Payments of Sponsor Group management fees and associated cost allocations have been suspended (see Note 13 to Financial Statements). Legal and other professional services costs associated with the Chapter 11 Cases are now being reported in reorganization items as discussed below.
Other deductions totaled $24 million in 2014 and $4 million in 2013. Other deductions in 2014 include $21 million related to write-off of deferred costs related to cancelled mining projects.
Interest expense and related charges increased $95 million, or 9%, to $1.155 billion in 2014. The increase reflected:
• | $421 million in lower mark-to-market net gains on interest rate swaps due to the termination of the agreements; |
• | $211 million in expense related to adequate protection payments approved by the Bankruptcy Court for the benefit of secured creditors; and |
• | $6 million in interest expense on debtor-in-possession financing, |
partially offset by
• | $493 million in lower interest expense on pre-petition debt due to the cessation of interest upon the Bankruptcy Filing and the termination of the interest rate swap agreements shortly after the Bankruptcy Filing, and |
• | $45 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. |
See above for discussion of reorganization items for both the three and six months ended June 30, 2014.
Income tax benefit totaled $568 million and $477 million on pretax losses in 2014 and 2013, respectively. Excluding the $40 million income tax benefit recorded in 2013 related to resolution of IRS audit matters, the effective tax benefit rate was 32.9% and 34.6% in 2014 and 2013, respectively. The decrease in the effective tax rate was driven by higher nondeductible legal and other professional services costs related to the Chapter 11 Cases.
Net loss increased $372 million to $1.158 billion in 2014. The change reflected reorganization items, higher net loss from commodity hedging and trading activities, the income tax benefit recorded in 2013 related to resolution of IRS audit matters and increased interest expense, partially offset by the effect of higher electricity prices on wholesale revenues.
65
Competitive Electric Segment — Energy-Related Commodity Contracts and Mark-to-Market Activities
The table below summarizes the changes in commodity contract assets and liabilities for the six months ended June 30, 2014 and 2013. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $550 million and $530 million in unrealized net losses in 2014 and 2013, respectively, 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.
Six Months Ended June 30, | |||||||
2014 | 2013 | ||||||
Commodity contract net asset at beginning of period | $ | 525 | $ | 1,664 | |||
Settlements/termination of positions (a) | (382 | ) | (487 | ) | |||
Changes in fair value of positions in the portfolio (b) | (168 | ) | (43 | ) | |||
Other activity (c) | 22 | 24 | |||||
Commodity contract net asset (liability) at end of period | $ | (3 | ) | $ | 1,158 | ||
____________
(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. See discussion above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Hedging Program and Termination of Positions." |
(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 liability arising from recognition of fair values at June 30, 2014, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
Maturity dates of unrealized commodity contract net liability at June 30, 2014 | ||||||||||||
Source of fair value | Less than 1 year | 1-3 years | Total | |||||||||
Prices actively quoted | $ | (75 | ) | $ | — | $ | (75 | ) | ||||
Prices provided by other external sources | 27 | — | 27 | |||||||||
Prices based on models | 38 | 7 | 45 | |||||||||
Total | $ | (10 | ) | $ | 7 | $ | (3 | ) | ||||
The "prices actively quoted" category reflects only exchange-traded contracts for which active quotes are readily available. The "prices provided by other external sources" category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT's North Hub that are deemed active markets extend through 2015 and over-the-counter quotes for natural gas generally extend through 2017, depending upon delivery point. The "prices based on models" category contains the value of all non-exchange-traded options valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 11 to Financial Statements for fair value disclosures and discussion of fair value measurements.
66
FINANCIAL CONDITION
Cash Flows — Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013 — Cash used in operating activities totaled $182 million and $621 million in 2014 and 2013, respectively. The decrease in cash used of $439 million was driven by lower cash interest payments.
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 $79 million and $82 million for the six months ended June 30, 2014 and 2013, 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 provided by financing activities totaled $2.286 billion in 2014 and cash used in financing activities totaled $52 million in 2013. The increase of $2.338 billion in cash provided in 2014 reflected:
• | $1.425 billion in borrowings from the TCEH DIP Facility, and |
• | $3.564 billion in borrowings from the EFIH DIP Facility, |
partially offset by
• | $2.438 billion in repayments of EFIH First Lien Notes; |
• | $180 million in payments for fees associated with completion of the TCEH and EFIH DIP Facilities. |
Cash provided by investing activities totaled $81 million and $323 million in 2014 and 2013, respectively. The decrease of $242 million in cash provided in 2014 was largely driven by a change in restricted cash activity of $314 million. Cash provided by restricted cash activity in 2014 reflected $363 million released from an escrow account when certain letters of credit were drawn (see Note 7 to Financial Statements), partially offset by a $53 million increase in restricted cash supporting new letters of credit issued under the TCEH DIP Facility. Cash provided by restricted cash activity in 2013 reflected $680 million released from an escrow account to repay the balance of the TCEH Demand Notes (see Note 13 to Financial Statements). The decrease in cash provided related to restricted cash was partially offset by a reduction in capital expenditures (including nuclear fuel purchases) of $76 million, to $225 million, due to timing of both capital projects and payments and the effect of $40 million in cash used in 2013 to acquire the owner participant interest in a trust established to lease six natural gas-fired combustion turbines to TCEH.
Debt Activity — Debt activities during the six months ended June 30, 2014 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):
Borrowings | Settlements | ||||||
TCEH (a) | $ | 1,425 | $ | (209 | ) | ||
EFCH | — | (3 | ) | ||||
EFIH (b) | 5,400 | (3,985 | ) | ||||
EFH Corp. (c) | — | (4 | ) | ||||
Total | $ | 6,825 | $ | (4,201 | ) | ||
___________
(a) | Settlements include $203 million of pollution control revenue bonds tendered, $1 million of payments of principal at scheduled maturity dates and $5 million of payments of capital lease liabilities. |
(b) | Settlements include $2.312 billion cash and $1.673 billion noncash exchange (see Note 5 to Financial Statements). |
(c) | Settlements are noncash. |
See Notes 5 and 7 to Financial Statements for further detail of debtor-in-possession borrowing facilities and pre-petition debt.
67
Available Liquidity — The following table summarizes changes in available liquidity for the six months ended June 30, 2014:
Available Liquidity | |||||||||||
June 30, 2014 | December 31, 2013 | Change | |||||||||
Cash and cash equivalents – EFH Corp. (parent entity) | $ | 339 | $ | 229 | $ | 110 | |||||
Cash and cash equivalents – EFIH | 1,185 | 242 | 943 | ||||||||
Cash and cash equivalents – TCEH (a) | 1,878 | 746 | 1,132 | ||||||||
Total cash and cash equivalents | 3,402 | 1,217 | 2,185 | ||||||||
TCEH DIP Revolving Credit Facility | 1,950 | — | 1,950 | ||||||||
TCEH pre-petition Letter of Credit Facility | — | 195 | (195 | ) | |||||||
Total liquidity | $ | 5,352 | $ | 1,412 | $ | 3,940 | |||||
___________
(a) | Cash and cash equivalents at June 30, 2014 and December 31, 2013 exclude $635 million and $945 million, respectively, of restricted cash held for letter of credit support. The June 30, 2014 restricted cash balance includes $582 million under the TCEH pre-petition Letter of Credit Facility and $53 million under the TCEH DIP Facility. |
The increase in available liquidity of $3.940 billion in the six months ended June 30, 2014 was driven by cash borrowings and available capacity under the $3.375 billion TCEH DIP Facility and the cash borrowings under the EFIH DIP Facility of $1.038 billion, net of fees related to both facilities of $180 million (see Note 5 to Financial Statements), partially offset by $225 million in capital expenditures, including nuclear fuel purchases, and $182 million in cash used in operating activities. See discussion of cash flows above.
Subject to certain exceptions under the Bankruptcy Code, the Bankruptcy Filing automatically enjoined, or stayed, the continuation of most pending judicial or administrative proceedings and the filing of other actions against the Debtors or their property to recover on, collect or secure a claim arising prior to the date of the Bankruptcy Filing (including with respect to our pre-petition debt instruments).
The Bankruptcy Court approved final orders in June 2014 authorizing the TCEH DIP Facility and the EFIH DIP Facility (see Note 5 to Financial Statements). The TCEH DIP Facility provides for up to $3.375 billion in senior secured, super-priority financing. The EFIH DIP Facility provides for up to $5.4 billion in senior secured, super-priority financing.
We have incurred and expect to continue to incur significant costs associated with the Bankruptcy Filing and our reorganization, but we cannot accurately predict the effect the Bankruptcy Filing 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 set forth in the TCEH DIP Facility, 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 set forth in the EFIH DIP Facility, EFIH to incur incremental junior lien subordinated debt in an aggregate amount not to exceed $3 billion.
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Distributions of Earnings from Oncor Holdings and Related Considerations — Oncor Holdings' distributions of earnings to us totaled $77 million and $80 million for the six months ended June 30, 2014 and 2013, respectively. On July 31, 2014, we received a distribution of $51 million from Oncor Holdings. See Note 3 to Financial Statements for discussion of limitations on amounts Oncor can distribute to its members.
As a result of the Bankruptcy Filing, Oncor had credit risk exposure to trade accounts receivable from TCEH, which related to delivery services provided by Oncor to TCEH's retail electricity operations. At the Petition Date, these accounts receivable totaled $109 million. In June 2014, the Bankruptcy Court authorized the Debtors to pay all pre-petition delivery charges due Oncor, and such amounts were paid in full.
Oncor has additional credit risk exposure to EFH Corp. and certain of its subsidiaries totaling approximately $20 million at the Petition Date, including an $18 million federal income tax receivable from EFH Corp. under the Federal and State Income Tax Allocation Agreement. Additional income tax receivable amounts may arise in the normal course under that agreement.
Because Oncor would not seek regulatory rate recovery for such credit losses, Oncor's earnings could be reduced by the amount (after-tax) of any nonpayment by EFH Corp. and its subsidiaries of amounts owed to Oncor.
Oncor has not established any reserves related to this exposure.
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 5 to 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 variance margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other corporate purposes, including reducing borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. At June 30, 2014, all cash collateral held was unrestricted. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted.
At June 30, 2014, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:
• | $94 million in cash has been posted with counterparties as compared to $93 million posted at December 31, 2013; |
• | $3 million in cash has been received from counterparties as compared to $302 million received at December 31, 2013. This decrease was driven by termination of positions in the natural gas hedging program as discussed above; |
• | $358 million in letters of credit have been posted with counterparties, as compared to $317 million posted at December 31, 2013, and |
• | $3 million in letters of credit have been received from counterparties, as compared to $3 million received at December 31, 2013. |
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 12 to Financial Statements for discussion of agreements terminated subsequent to the Bankruptcy Filing.
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.
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EFH Corp. and 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 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 $45 million, and no payments or refunds of federal income taxes are expected. Income tax payments totaled $49 million ($46 million related to Texas margin tax) and $51 million (all Texas margin tax) for the six months ended June 30, 2014 and 2013, respectively. In April 2014, EFH Corp. paid the IRS for interest in the amount of $3.4 million, thus settling all contested issues related to the 1997 through 2002 open tax years.
Financial Covenants — The Bankruptcy Filing constituted an event of default 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 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 1.26 to 1.00 at June 30, 2014 and TCEH is in compliance with this covenant. Consolidated Superpriority Secured Net Debt consists of outstanding term loans and revolving credit exposure under the TCEH DIP Facility less unrestricted cash. TCEH's Consolidated EBITDA (as used in the covenant contained in the agreement governing the TCEH DIP Facility) for the six and twelve months ended June 30, 2014 totaled $912 million and $1.712 billion, respectively. See Exhibit 99(b) for a reconciliation of TCEH's net income (loss) to Consolidated EBITDA. The EFIH DIP Facility also includes a minimum liquidity covenant pursuant to which EFIH cannot allow unrestricted cash (as defined in the EFIH DIP Facility) to be less than $150 million. EFIH is in compliance with this covenant.
See Note 5 to 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 land 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. 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. Our most recent estimate of future costs to complete reclamation of land that we have mined as well as land we are currently mining totals approximately $200 million on an undiscounted basis.
Certain transmission and distribution utilities in Texas are required to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, as a result of TCEH's below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. At June 30, 2014, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $21 million, with $9 million of this amount posted for the benefit of Oncor.
The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at June 30, 2014, TCEH posted letters of credit in the amount of $62 million, which are subject to adjustments.
ERCOT has rules in place to assure adequate creditworthiness of parties that participate in the day-ahead, real-time and congestion revenue rights markets operated by ERCOT. Under these rules, TCEH has posted collateral support, in the form of cash and letters of credit, totaling $132 million at June 30, 2014 (which is subject to daily adjustments based on settlement activity with ERCOT).
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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 $37 million in remaining lease payments at June 30, 2014 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 $39 million in remaining lease payments at June 30, 2014 and terminates in 2029, if payment obligations of TCEH in excess of $200 million in the aggregate to third-party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease. Under the Bankruptcy Code, the lessors are stayed from taking any action against the Debtors as a result of the default.
Guarantees — See Note 9 to Financial Statements for discussion of guarantees.
OFF–BALANCE SHEET ARRANGEMENTS
See Notes 3 and 9 to Financial Statements regarding VIEs and guarantees, respectively.
COMMITMENTS AND CONTINGENCIES
See Note 9 to Financial Statements for discussion of commitments and contingencies.
CHANGES IN ACCOUNTING STANDARDS
In May 2014, the FASB and IASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), Revenue from Contracts with Customers. The ASU is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2016 for public entities. Early application is not permitted. The amendments in ASU 2014-09 create a new Accounting Standards Codification (ASC) Topic 606, Revenue from Contracts with Customers, which supersedes revenue recognition requirements in ASC 605, Revenue Recognition. ASU 2014-09 requires that an entity recognize revenues as performance obligations embedded in sales agreements with customers are satisfied by the entity. The rule is intended to eliminate inconsistencies in revenue recognition and thereby improve comparability across entities, industries and capital markets. We are in the process of assessing the effects of the application of the new guidance on our financial statements.
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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 owned 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 and spark spreads (differences between the market price of electricity and its cost of production).
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.
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Trading VaR — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts entered into for trading purposes based on a 95% confidence level and an assumed holding period of five days.
June 30, 2014 | December 31, 2013 | ||||||
Month-end average Trading VaR: | $ | 2 | $ | 2 | |||
Month-end high Trading VaR: | $ | 3 | $ | 4 | |||
Month-end low Trading VaR: | $ | 1 | $ | 1 | |||
VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period of five to 60 days.
June 30, 2014 | December 31, 2013 | ||||||
Month-end average MtM VaR: | $ | 68 | $ | 69 | |||
Month-end high MtM VaR: | $ | 129 | $ | 97 | |||
Month-end low MtM VaR: | $ | 36 | $ | 43 | |||
Earnings at Risk (EaR) — This measurement estimates the potential reduction of pretax earnings for the periods presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities), based on a 95% confidence level and an assumed holding period of five to 60 days.
June 30, 2014 | December 31, 2013 | ||||||
Month-end average EaR: | $ | 34 | $ | 36 | |||
Month-end high EaR: | $ | 60 | $ | 71 | |||
Month-end low EaR: | $ | 20 | $ | 23 | |||
The increase in the month end high MtM VaR risk measure above reflected increases in natural gas prices and higher market volatility.
Credit Risk
Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty's financial condition, credit rating and other quantitative and qualitative credit criteria and authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties' financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and setoff. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Further, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. 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. This process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.
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 $700 million at June 30, 2014. The components of this exposure are discussed in more detail below.
Assets subject to credit risk at June 30, 2014 include $525 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $56 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.
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The remaining credit exposure arises from wholesale trade receivables, commodity contracts and hedging and trading activities arising from derivative instruments. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. At June 30, 2014, the exposure to credit risk from these counterparties totaled $175 million taking into account the netting provisions of the master agreements described above but before taking into account $4 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $171 million decreased $32 million in the six months ended June 30, 2014.
Of this $171 million net exposure, essentially all is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies' published ratings and our internal credit evaluation process. 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 on this basis.
The following table presents the distribution of credit exposure at June 30, 2014. 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 2014) 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 12 to 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 | $ | 158 | $ | — | $ | 158 | |||||
Below investment grade | 17 | 4 | 13 | ||||||||
Totals | $ | 175 | $ | 4 | $ | 171 | |||||
Investment grade | 90.3 | % | 92.4 | % | |||||||
Below investment grade | 9.7 | % | 7.6 | % | |||||||
In addition to the exposures in the table above, contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform. Nonperformance could have a material impact on future results of operations, liquidity and financial condition.
Significant (10% or greater) concentration of credit exposure exists with two counterparties, which represented 51% and 24% of the $171 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.
The termination of natural gas hedging agreements by counterparties shortly after the Bankruptcy Filing (as discussed in Note 12 to Financial Statements) did not significantly affect the net credit risk exposure presented in the table above.
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FORWARD-LOOKING STATEMENTS
This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including such matters as activities related to our bankruptcy, financial or operational projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated," "should," "projection," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under Item 1A, "Risk Factors" in our 2013 Form 10-K, Form 10-Q for the quarterly period ended March 31, 2014 and this report, the discussion under Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:
• | the termination of the RSA as well as any one or more of the Debtors entering into of any new agreement for alternative restructuring transactions; |
• | our ability to propose a Chapter 11 restructuring plan that will receive the necessary votes from the required creditors and stakeholders and the approval from the Bankruptcy Court; |
• | our ability to obtain the approval of the Bankruptcy Court with respect to the Debtors' motions in the bankruptcy proceedings, including such approvals not being overturned on appeal or being stayed for any extended period of time; |
• | the effectiveness of the overall restructuring activities pursuant to the Bankruptcy Filing and any additional strategies we employ to address our liquidity and capital resources; |
• | the terms and conditions of any bankruptcy plan that is ultimately approved by the Bankruptcy Court; |
• | the extent to which the Bankruptcy Filing causes 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 operations or to fund any bankruptcy plan and meet future obligations; |
• | 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 bankruptcy proceedings that may be inconsistent with our plans; |
• | the length of time that the Debtors will be debtors-in-possession under the Bankruptcy Code; |
• | the actions and decisions of regulatory authorities relative to our bankruptcy plan; |
• | 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 a bankruptcy plan; |
• | the outcome of potential litigation regarding whether note holders are entitled to make-whole premiums in connection with the treatment of their claims in bankruptcy; |
• | prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the 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; |
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◦ | development, construction and operation of facilities; |
◦ | decommissioning costs; |
◦ | present or prospective wholesale and retail competition; |
◦ | changes in tax laws and policies; |
◦ | changes in and compliance with environmental and safety laws and policies, including the CSAPR, the Mercury and Air Toxics Standard, 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 make intercompany loans or otherwise transfer funds among different entities in our corporate structure; |
• | our ability to generate sufficient cash flow to make interest or adequate protection payments, or refinance, our debt instruments, including 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 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; |
• | actions by credit rating agencies; |
• | our ability to effectively execute our operational strategy, and |
• | our ability to implement cost reduction initiatives. |
Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. As such, you should not unduly rely on such forward-looking statements.
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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 |
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. Based on the evaluation performed, our management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective. During the most recent fiscal quarter covered by this quarterly report, there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
Item 1. | LEGAL PROCEEDINGS |
Reference is made to the discussion in Note 9 to 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 2013 Form 10-K, as amended, and in Part II, "Item 1A. Risk Factors" in our Form 10-Q for the period ended March 31, 2014 except for the risk factors discussed more fully below and the information disclosed elsewhere in this Form 10-Q that provides factual updates to risk factors contained in our 2013 Form 10-K, as amended, and Form 10-Q for the period ended March 31, 2014. The risks described in such reports are not the only risks facing our company.
There is no assurance regarding the outcome of any litigation regarding whether note holders are entitled to makewhole premiums in connection with the treatment of their claims in bankruptcy.
On May 15, 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 redemption premium in connection with the cash repayment of the EFIH First Lien Notes and that such redemption premium is an allowed secured claim (EFIH First Lien Makewhole Claims). In the EFIH First Lien Makewhole Claim, the amount of such claims is alleged to be equal to approximately $432 million plus reimbursement of expenses. On June 16, 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 redemption premium in connection with any repayment of the EFIH Second Lien Notes and that such redemption premium would be an allowed secured claim (the EFIH Second Lien Makewhole Claims and, together with the EFIH First Lien Makewhole Claims, the Makewhole Claims). In the EFIH Second Lien Makewhole Claim, as of July 31, 2014, the amount of such claims alleged would have been equal to approximately $675 million plus reimbursement of expenses. The EFIH Debtors expect to seek to obtain entry of orders from the Bankruptcy Court disallowing each of the Makewhole Claims.
In addition, creditors may make additional claims in the Chapter 11 Cases for redemption premiums in connection with repayments or settlement of other pre-petition debt. There can be no assurance regarding the outcome of this litigation or the Bankruptcy Court's determination regarding the validity or the amounts payable in respect of each of the Makewhole Claims or other claims for redemption premiums.
Due to the termination of the RSA, the Debtors are now subject to a bankruptcy proceeding which, without the contractual support of key creditors, could ultimately result in a more lengthy, costly and contentious Chapter 11 Case.
As a result of the termination of the RSA, the Debtors are now subject to a bankruptcy proceeding, which could be more lengthy, costly and contentious, and have a more pronounced adverse effect on our business than the pre-arranged plan contemplated by the RSA. Such bankruptcy proceeding could involve contested issues with multiple stakeholders.
The uncertainty surrounding a prolonged restructuring could also have other adverse effects on us. For example, it could also adversely affect:
• | our ability to raise additional capital; |
• | our liquidity; |
• | how our business is viewed by regulators, investors, lenders, credit ratings agencies and other stakeholders, and |
• | our enterprise value. |
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Item 4. | MINE SAFETY DISCLOSURES |
We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RCT and Office of Surface Mining. The MSHA inspects US mines, including ours, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders and proposed assessments are provided in Exhibit 95(a) to this quarterly report on Form 10-Q.
Item 5. | OTHER INFORMATION |
None.
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. | ||||
(10) | Material Contracts | |||||||
Credit Agreements and Related Agreements | ||||||||
10(a) | 1-12833 Form 8-K (filed May 7, 2014) | 10.1 | — | Senior Secured Superpriority Debtor-in-Possession Credit Agreement dated as of May 5, 2014 among EFCH, as Parent Guarantor, TCEH, as Borrower, the Several Lenders from Time to Time Parties Thereto, Citibank, N.A., as Administrative Agent and Collateral Agent, the Co-Syndication Agents Parties Thereto, the Co-Documentation Agents Parties thereto and the Joint Lead Arrangers and Joint Bookrunners Parties thereto. | ||||
10(b) | 1-12833 Form 8-K (filed May 13, 2014) | 99.1 | — | First Amendment to the Restructuring Support and Lock-Up Agreement dated May 7, 2014, among EFH Corp. and the parties thereto. | ||||
10(c) | 1-12833 Form 8-K (filed May 27, 2014) | 99.2 | — | Second Amendment to the Restructuring Support and Lock-Up Agreement dated May 16, 2014, among the Reorganizing Entities and the other parties thereto. | ||||
10(d) | 1-12833 Form 8-K (filed June 25, 2014) | 10(a) | — | Senior Secured Superpriority Debtor-In-Possession Credit Agreement, dated as of June 19, 2014, among the EFIH Debtors, the lenders party thereto, Deutsche Bank AG New York Branch, as Administrative Agent and Collateral Agent, Citibank, N.A., Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents, Barclays Bank PLC, Royal Bank of Canada and Union Bank, N.A., as Co-Documentation Agents, Deutsche Bank Securities Inc., Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley Senior Funding, Inc., Barclays Bank PLC, RBC Capital Markets and Union Bank, N.A., as Joint Lead Arrangers and Joint Bookrunners, and Loop Capital Markets, LLC and Williams Capital Group, LLC, as Co-Managers. | ||||
10(e) | 1-12833 Form 8-K (filed June 25, 2014) | 10(b) | — | Pledge Agreement, dated as of June 19, 2014, by and among the EFIH Debtors and Deutsche Bank AG New York Branch, as collateral agent. | ||||
10(f) | 1-12833 Form 8-K (filed June 25, 2014) | 10(c) | — | Security Agreement, dated as of June 19, 2014, by and among the EFIH Debtors and Deutsche Bank AG New York Branch, as collateral agent. | ||||
10(g) | 1-12833 Form 8-K (filed June 25, 2014) | 10(d) | — | Amendment No. 1 to the TCEH DIP Credit Agreement, dated May 13, 2014, among the TCEH Debtors and the other parties thereto. | ||||
10(h) | 1-12833 Form 8-K (filed June 25, 2014) | 10(e) | — | Amendment No. 2 to the TCEH DIP Credit Agreement, dated June 12, 2014, among the TCEH Debtors and the other parties thereto. | ||||
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Exhibits | Previously Filed With File Number* | As Exhibit | ||||||
(31) | Rule 13a - 14(a)/15d-14(a) Certifications | |||||||
31(a) | — | Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||||
31(b) | — | Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||||
(32) | Section 1350 Certifications | |||||||
32(a) | — | Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||||||
32(b) | — | Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||||||
(95) | Mine Safety Disclosures | |||||||
95(a) | — | Mine Safety Disclosures | ||||||
(99) | Additional Exhibits | |||||||
99(a) | — | Condensed Statement of Consolidated Income – Twelve Months Ended June 30, 2014. | ||||||
99(b) | — | Texas Competitive Electric Holdings Company LLC Consolidated EBITDA reconciliation for the six and twelve months ended June 30, 2014 | ||||||
XBRL Data Files | ||||||||
101.INS | — | XBRL Instance Document | ||||||
101.SCH | — | XBRL Taxonomy Extension Schema Document | ||||||
101.CAL | — | XBRL Taxonomy Extension Calculation Document | ||||||
101.DEF | — | XBRL Taxonomy Extension Definition Document | ||||||
101.LAB | — | XBRL Taxonomy Extension Labels Document | ||||||
101.PRE | — | XBRL Taxonomy Extension Presentation Document | ||||||
____________
* | Incorporated herein by reference |
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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/ STANLEY J. SZLAUDERBACH | |||
Name: | Stanley J. Szlauderbach | |||
Title: | Senior Vice President and Controller | |||
(Principal Accounting Officer) | ||||
Date: August 1, 2014
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