Attached files
| file | filename |
|---|---|
| EX-31.B - CERTIFICATION OF PAUL M. KEGLEVIC - Energy Future Holdings Corp /TX/ | efh-2016331xexhibit31b.htm |
| EX-95.A - MINE SAFETY DISCLOSURES - Energy Future Holdings Corp /TX/ | efh-2016331xexhibit95a.htm |
| EX-32.A - CERTIFICATION OF JOHN F. YOUNG - Energy Future Holdings Corp /TX/ | efh-2016331xexhibit32a.htm |
| EX-99.A - TWELVE MONTHS ENDED MARCH 31, 2016 STATEMENT OF INCOME - Energy Future Holdings Corp /TX/ | efh-2016331xexhibit99a.htm |
| EX-31.A - CERTIFICATION OF JOHN F. YOUNG - Energy Future Holdings Corp /TX/ | efh-2016331xexhibit31a.htm |
| EX-99.B - CONSOLIDATED EBITDA RECONCILIATION TEXAS COMPETITIVE ELECTRIC HOLDINGS COMPANY - Energy Future Holdings Corp /TX/ | efh-2016331xexhibit99b.htm |
| EX-32.B - CERTIFICATION OF PAUL M. KEGLEVIC - Energy Future Holdings Corp /TX/ | efh-2016331xexhibit32b.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 MARCH 31, 2016
— OR —
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-12833
Energy Future Holdings Corp.
(Exact name of registrant as specified in its charter)
Texas | 46-2488810 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
1601 Bryan Street, Dallas, TX 75201-3411 | (214) 812-4600 | |
(Address of principal executive offices) (Zip Code) | (Registrant's telephone number, including area code) | |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o Accelerated filer o Non-Accelerated filer x (Do not check if a smaller reporting company)
Smaller reporting company o
Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
At May 9, 2016, there were 1,669,861,379 shares of common stock, without par value, outstanding of Energy Future Holdings Corp. (substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.’s parent holding company, and none of which is publicly traded).
TABLE OF CONTENTS
PAGE | ||
PART I. | ||
Item 1. | ||
Item 2. | ||
Item 3. | ||
Item 4. | ||
PART II. | ||
Item 1. | ||
Item 1A. | ||
Item 4. | ||
Item 6. | ||
Energy Future Holdings Corp.'s (EFH Corp.) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the EFH Corp. website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on EFH Corp.'s website shall not be deemed a part of, or incorporated by reference into, this quarterly report on Form 10-Q. The representations and warranties contained in any agreement that we have filed as an exhibit to this quarterly report on Form 10-Q, or that we have or may publicly file in the future, may contain representations and warranties made by and to the parties thereto at specific dates. Such representations and warranties may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent the parties' risk allocation in the particular transaction, or may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes.
This quarterly report on Form 10-Q and other Securities and Exchange Commission filings of EFH Corp. and its subsidiaries occasionally make references to EFH Corp. (or "we," "our," "us" or "the Company"), EFCH, EFIH, TCEH, TXU Energy, Luminant, Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent company's financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.
i
GLOSSARY
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
2015 Form 10-K | EFH Corp.'s Annual Report on Form 10-K for the year ended December 31, 2015 | |
Chapter 11 Cases | Cases being heard in the US Bankruptcy Court for the District of Delaware (Bankruptcy Court) concerning voluntary petitions for relief under Chapter 11 of the US Bankruptcy Code (Bankruptcy Code) filed on April 29, 2014 by the Debtors | |
Competitive Electric segment | the EFH Corp. business segment that consists principally of TCEH | |
Consolidated EBITDA | Consolidated EBITDA means TCEH EBITDA adjusted to exclude noncash items, unusual items and other adjustments allowable under the agreement governing the TCEH DIP Facility. See the definition of EBITDA below. Consolidated EBITDA and EBITDA are not recognized terms under US GAAP and, thus, are non-GAAP financial measures. We are providing Consolidated EBITDA in this Form 10-Q (see reconciliation in Exhibit 99(b)) solely because of the important role that Consolidated EBITDA plays in respect of covenants contained in the agreement governing the TCEH DIP Facility. We do not intend for Consolidated EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with US GAAP. Additionally, we do not intend for Consolidated EBITDA (or EBITDA) to be used as a measure of free cash flow available for management's discretionary use, as the measure excludes certain cash requirements such as adequate assurance payments, interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Consolidated EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies. | |
CSAPR | the final Cross-State Air Pollution Rule issued by the EPA in July 2011 | |
DIP Facilities | Refers, collectively, to TCEH's debtor-in-possession financing and EFIH's debtor-in-possession financing. See Note 10 to the Financial Statements. | |
Debtors | EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities | |
Disclosure Statement | Disclosure Statement for the Debtors' Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code filed by the Debtors with the Bankruptcy Court in May 2016 | |
D.C. Circuit Court | US Court of Appeals for the District of Columbia Circuit | |
EBITDA | earnings (net income) before interest expense, income taxes, depreciation and amortization | |
EFCH | Energy Future Competitive Holdings Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context | |
EFH Corp. | Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context, whose major subsidiaries include TCEH and Oncor | |
EFH Debtors | EFH Corp. and its subsidiaries that are Debtors in the Chapter 11 Cases, excluding the TCEH Debtors | |
EFIH | Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings | |
EFIH Debtors | EFIH and EFIH Finance | |
EFIH DIP Facility | EFIH's and EFIH Finance's $5.4 billion debtor-in-possession financing facility. See Note 10 to the Financial Statements. | |
EFIH Finance | EFIH Finance Inc., a direct, wholly owned subsidiary of EFIH, formed for the sole purpose of serving as co-issuer with EFIH of certain debt securities | |
EFIH First Lien Notes | EFIH's and EFIH Finance's 6.875% Senior Secured First Lien Notes and 10.000% Senior Secured First Lien Notes exchanged or settled in June 2014 as discussed in Note 10 to the Financial Statements, collectively | |
EFIH Second Lien Notes | EFIH's and EFIH Finance's $322 million principal amount of 11% Senior Secured Second Lien Notes and $1.389 billion principal amount of 11.75% Senior Secured Second Lien Notes, collectively | |
ii
EPA | US Environmental Protection Agency | |
ERCOT | Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas | |
ERISA | Employee Retirement Income Security Act of 1974, as amended | |
Federal and State Income Tax Allocation Agreements | EFH Corp. and certain of its subsidiaries (including EFCH, EFIH and TCEH, but not including Oncor Holdings and Oncor) are parties to a Federal and State Income Tax Allocation Agreement, executed in May 2012 but effective as of January 2010. EFH Corp., Oncor Holdings, Oncor, Texas Transmission, and Oncor Management Investment LLC are parties to a separate Federal and State Income Tax Allocation Agreement dated November 2008. See Note 6 to the Financial Statements and Management's Discussion and Analysis, under Financial Condition. | |
FERC | US Federal Energy Regulatory Commission | |
Fifth Circuit Court | US Court of Appeals for the Fifth Circuit | |
GAAP | generally accepted accounting principles | |
GHG | greenhouse gas | |
GWh | gigawatt-hours | |
ICE | the IntercontinentalExchange, an electronic commodity derivative exchange | |
IRS | US Internal Revenue Service | |
LIBOR | London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market | |
LSTC | liabilities subject to compromise | |
Luminant | subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management, all largely in Texas | |
market heat rate | Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors. | |
MATS | the Mercury and Air Toxics Standard established by the EPA | |
Merger | the transaction referred to in the Agreement and Plan of Merger under which Texas Holdings agreed to acquire EFH Corp., which was completed on October 10, 2007 | |
MMBtu | million British thermal units | |
MW | megawatts | |
MWh | megawatt-hours | |
NOX | nitrogen oxide | |
NRC | US Nuclear Regulatory Commission | |
NYMEX | the New York Mercantile Exchange, a commodity derivatives exchange | |
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 | |
iii
Oncor Holdings | Oncor Electric Delivery Holdings Company LLC, a direct, wholly owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context | |
Oncor Ring-Fenced Entities | Oncor Holdings and its direct and indirect subsidiaries, including Oncor | |
OPEB | postretirement employee benefits other than pensions | |
Petition Date | April 29, 2014, the date the Debtors made the Bankruptcy Filing | |
Plan of Reorganization | Joint Plan of Reorganization filed by the Debtors with the Bankruptcy Court in May 2016 | |
Plan Support Agreement | Third Amendment to the Amended and Restated Plan Support Agreement, entered into in December 2015, amending and restating the Plan Support Agreement | |
PUCT | Public Utility Commission of Texas | |
purchase accounting | The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or "purchase price" of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill. | |
Regulated Delivery segment | the EFH Corp. business segment that consists primarily of our investment in Oncor | |
REP | retail electric provider | |
RCT | Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas | |
S&P | Standard & Poor's Ratings (a credit rating agency) | |
SEC | US Securities and Exchange Commission | |
Securities Act | Securities Act of 1933, as amended | |
SG&A | selling, general and administrative | |
Settlement Agreement | Amended and Restated Settlement Agreement among the Debtors, the Sponsor Group, settling TCEH first lien creditors, settling TCEH second lien creditors, settling TCEH unsecured creditors and the official committee of unsecured creditors of TCEH (collectively, the Settling Parties), approved by the Bankruptcy Court in December 2015. See Note 2 to the Financial Statements. | |
SO2 | sulfur dioxide | |
Sponsor Group | Refers, collectively, to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Global, LLC (together with its affiliates, TPG) and GS Capital Partners, an affiliate of Goldman, Sachs & Co., that have an ownership interest in Texas Holdings. | |
TCEH | Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy market activities, and whose major subsidiaries include Luminant and TXU Energy | |
TCEH Debtors | EFCH, TCEH and the subsidiaries of TCEH that are Debtors in the Chapter 11 Cases | |
TCEH DIP Facility | TCEH's $3.375 billion debtor-in-possession financing facility. See Note 10 to the Financial Statements. | |
TCEH Finance | TCEH Finance, Inc., a direct, wholly owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities | |
TCEH Senior Secured Facilities | Refers, collectively, to the TCEH First Lien Term Loan Facilities, TCEH First Lien Revolving Credit Facility and TCEH First Lien Letter of Credit Facility with a total principal amount of $22.616 billion. | |
TCEH Senior Secured Notes | TCEH's and TCEH Finance's $1.750 billion principal amount of 11.5% First Lien Senior Secured Notes | |
TCEQ | Texas Commission on Environmental Quality | |
iv
Terminated Plan | Sixth Amended Joint Plan of Reorganization filed by the Debtors in November 2015, as amended, confirmed by the Bankruptcy Court in December 2015, which became null and void in May 2016 | |
Texas Holdings | Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group, that owns substantially all of the common stock of EFH Corp. | |
Texas Holdings Group | Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities | |
Texas Transmission | Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor and is not affiliated with EFH Corp., any of EFH Corp.'s subsidiaries or any member of the Sponsor Group | |
TXU Energy | TXU Energy Retail Company LLC, a direct, wholly owned subsidiary of TCEH that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers | |
US | United States of America | |
VIE | variable interest entity | |
v
PART I. FINANCIAL INFORMATION
Item 1. | FINANCIAL STATEMENTS |
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION
CONDENSED STATEMENTS OF CONSOLIDATED LOSS
(Unaudited)
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
(millions of dollars) | |||||||
Operating revenues | $ | 1,049 | $ | 1,272 | |||
Fuel, purchased power costs and delivery fees | (554 | ) | (613 | ) | |||
Net gain from commodity hedging and trading activities | 64 | 103 | |||||
Operating costs | (219 | ) | (193 | ) | |||
Depreciation and amortization | (141 | ) | (218 | ) | |||
Selling, general and administrative expenses | (156 | ) | (179 | ) | |||
Impairment of goodwill (Note 5) | — | (700 | ) | ||||
Impairment of long-lived assets (Note 7) | — | (676 | ) | ||||
Other income (Note 18) | 5 | 8 | |||||
Other deductions (Note 18) | (21 | ) | (60 | ) | |||
Interest expense and related charges (Note 8) | (394 | ) | (609 | ) | |||
Reorganization items (Note 9) | (70 | ) | (138 | ) | |||
Loss before income taxes and equity in earnings of unconsolidated subsidiaries | (437 | ) | (2,003 | ) | |||
Income tax benefit (Note 6) | 127 | 401 | |||||
Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 4) | 62 | 75 | |||||
Net loss | $ | (248 | ) | $ | (1,527 | ) | |
See Notes to the Financial Statements.
CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE LOSS
(Unaudited)
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
(millions of dollars) | |||||||
Net loss | $ | (248 | ) | $ | (1,527 | ) | |
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 | ) | |||
Cash flow hedges derivative value net loss related to hedged transactions recognized during the period (net of tax benefit of $— in all periods) | — | 1 | |||||
Net effects related to Oncor — reported in equity in earnings of unconsolidated subsidiaries (net of tax) | — | 1 | |||||
Total other comprehensive loss | (1 | ) | — | ||||
Comprehensive loss | $ | (249 | ) | $ | (1,527 | ) | |
See Notes to the Financial Statements.
1
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) | |||||||
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
(millions of dollars) | |||||||
Cash flows — operating activities: | |||||||
Net loss | $ | (248 | ) | $ | (1,527 | ) | |
Adjustments to reconcile net loss to cash used in operating activities: | |||||||
Depreciation and amortization | 170 | 254 | |||||
Deferred income tax benefit, net | (123 | ) | (339 | ) | |||
Impairment of goodwill (Note 5) | — | 700 | |||||
Impairment of long-lived assets (Note 7) | — | 676 | |||||
Contract claims adjustments (Note 9) | 1 | 32 | |||||
Fees paid on EFIH Second Lien Notes repayment and EFIH DIP Facility (Notes 10 and 11) (reported as financing activities) | 14 | 28 | |||||
Unrealized net (gain) loss from mark-to-market valuations of commodity positions | 41 | (102 | ) | ||||
Equity in earnings of unconsolidated subsidiaries | (62 | ) | (75 | ) | |||
Distributions of earnings from unconsolidated subsidiaries (Note 4) | 40 | 74 | |||||
Write-off of intangible and other assets (Note 18) | 20 | 59 | |||||
Other, net | 15 | 18 | |||||
Changes in operating assets and liabilities: | |||||||
Margin deposits, net | 17 | 79 | |||||
Accrued interest | 4 | (3 | ) | ||||
Payables due to unconsolidated subsidiary | (26 | ) | (59 | ) | |||
Other operating assets and liabilities, including liabilities subject to compromise | (133 | ) | (222 | ) | |||
Cash used in operating activities | (270 | ) | (407 | ) | |||
Cash flows — financing activities: | |||||||
Repayments/repurchases of debt (Note 10) | (12 | ) | (454 | ) | |||
Fees paid on EFIH Second Lien Notes repayment and EFIH DIP Facility (Note 10 and 11) | (14 | ) | (28 | ) | |||
Other, net | — | (1 | ) | ||||
Cash used in financing activities | (26 | ) | (483 | ) | |||
Cash flows — investing activities: | |||||||
Capital expenditures | (83 | ) | (121 | ) | |||
Nuclear fuel purchases | (10 | ) | (5 | ) | |||
Changes in restricted cash | (142 | ) | 28 | ||||
Proceeds from sales of nuclear decommissioning trust fund securities (Note 18) | 67 | 23 | |||||
Investments in nuclear decommissioning trust fund securities (Note 18) | (71 | ) | (27 | ) | |||
Other, net | 2 | 1 | |||||
Cash used in investing activities | (237 | ) | (101 | ) | |||
Net change in cash and cash equivalents | (533 | ) | (991 | ) | |||
Cash and cash equivalents — beginning balance | 2,286 | 3,428 | |||||
Cash and cash equivalents — ending balance | $ | 1,753 | $ | 2,437 | |||
See Notes to the Financial Statements.
2
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) | |||||||
March 31, 2016 | December 31, 2015 | ||||||
(millions of dollars) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 1,753 | $ | 2,286 | |||
Restricted cash (Note 18) | 666 | 524 | |||||
Trade accounts receivable — net (Note 18) | 447 | 533 | |||||
Inventories (Note 18) | 448 | 428 | |||||
Commodity and other derivative contractual assets (Note 15) | 499 | 465 | |||||
Other current assets | 124 | 87 | |||||
Total current assets | 3,937 | 4,323 | |||||
Restricted cash (Note 18) | 507 | 507 | |||||
Investment in unconsolidated subsidiary (Note 4) | 6,086 | 6,064 | |||||
Other investments (Note 18) | 1,005 | 984 | |||||
Property, plant and equipment — net (Note 18) | 9,350 | 9,430 | |||||
Goodwill (Note 5) | 152 | 152 | |||||
Identifiable intangible assets — net (Note 5) | 1,156 | 1,166 | |||||
Accumulated deferred income taxes | 733 | 609 | |||||
Other noncurrent assets | 100 | 95 | |||||
Total assets | $ | 23,026 | $ | 23,330 | |||
LIABILITIES AND EQUITY | |||||||
Current liabilities: | |||||||
Borrowings under debtor-in-possession credit facilities (Note 10) | $ | 6,825 | $ | 6,825 | |||
Long-term debt due currently (Note 10) | 33 | 35 | |||||
Trade accounts payable | 367 | 413 | |||||
Net payables due to unconsolidated subsidiary (Note 16) | 178 | 204 | |||||
Commodity and other derivative contractual liabilities (Note 15) | 261 | 203 | |||||
Margin deposits related to commodity contracts | 176 | 152 | |||||
Accrued taxes | 108 | 134 | |||||
Accrued interest | 124 | 121 | |||||
Other current liabilities | 350 | 425 | |||||
Total current liabilities | 8,422 | 8,512 | |||||
Long-term debt, less amounts due currently (Note 10) | 55 | 60 | |||||
Liabilities subject to compromise (Note 11) | 37,786 | 37,786 | |||||
Other noncurrent liabilities and deferred credits (Note 18) | 2,073 | 2,033 | |||||
Total liabilities | 48,336 | 48,391 | |||||
Commitments and Contingencies (Note 12) | |||||||
Total equity (Note 13) | (25,310 | ) | (25,061 | ) | |||
Total liabilities and equity | $ | 23,026 | $ | 23,330 | |||
See Notes to the Financial Statements.
3
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES, A DEBTOR-IN-POSSESSION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. | BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES |
Description of Business
References in this report to "we," "our," "us" and "the Company" are to EFH Corp. and/or its subsidiaries, as apparent in the context. See Glossary for defined terms.
EFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through its TCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management, and retail electricity operations. TCEH is a wholly owned subsidiary of EFCH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Oncor Holdings, a holding company that holds an approximate 80% equity interest in Oncor, is a wholly owned subsidiary of EFIH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor Holdings and its subsidiaries (the Oncor Ring-Fenced Entities) are not consolidated in EFH Corp.'s financial statements in accordance with consolidation accounting standards related to variable interest entities (VIEs) (see Note 4).
Various ring-fencing measures have been taken to enhance the credit quality of Oncor. Such measures include, among other things: the ownership of a 19.75% equity interest in Oncor by Texas Transmission; maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor's board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or contractual obligations of any member of the Texas Holdings Group. Oncor's operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.
Consistent with the ring-fencing measures discussed above, the assets and liabilities of the Oncor Ring-Fenced Entities have not been, and are not expected to be, substantively consolidated with the assets and liabilities of the Debtors in the Chapter 11 Cases.
We have two reportable segments: the Competitive Electric segment, consisting largely of TCEH, and the Regulated Delivery segment, consisting largely of our investment in Oncor. See Note 17 for further information concerning reportable business segments.
Bankruptcy Proceeding
On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities (collectively, the Debtors), filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). See Note 2 for further discussion regarding the Chapter 11 Cases, the Plan of Reorganization and the Disclosure Statement.
4
Basis of Presentation, Including Application of Bankruptcy Accounting
The condensed consolidated financial statements have been prepared in accordance with US GAAP. The condensed consolidated financial statements have been prepared as if EFH Corp. is a going concern and contemplate the realization of assets and liabilities in the normal course of business. The condensed consolidated financial statements reflect the application of Financial Accounting Standards Board Accounting Standards Codification 852, Reorganizations (ASC 852). During the pendency of the Chapter 11 Cases, the Debtors will operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. ASC 852 applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. See Notes 9 and 11 for discussion of these accounting and reporting changes.
Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method (see Note 4). Adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in our 2015 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements and estimates of expected allowed claims. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.
Changes in Accounting Standards
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2016-2 (ASU 2016-02), Leases. The ASU amends previous GAAP to require the recognition of lease assets and liabilities for operating leases. The ASU will be effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Retrospective application to comparative periods presented will be required in the year of adoption. We are currently evaluating the impact of this ASU on our financial statements.
In March 2016, the FASB issued Accounting Standards Update 2016-08 (ASU 2016-08), Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). ASU 2016-08 clarifies the implementation guidance for principal versus agent considerations related to ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which provides the core principle and key steps in determining the recognition of revenue. The effective date for these updates has been deferred to fiscal years beginning after December 15, 2017. We are currently assessing the impact of these ASUs on our financial statements.
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2. CHAPTER 11 CASES
On the Petition Date, EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. During the pendency of the Chapter 11 Cases, the Debtors will operate their businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.
Plan of Reorganization
The Terminated Plan was confirmed by the Bankruptcy Court in December 2015. As described below, in May 2016, certain first lien creditors of TCEH delivered a Plan Support Termination Notice (as defined in the Plan Support Agreement) to the Debtors and the other parties to the Plan Support Agreement notifying such parties of the occurrence of a Plan Support Termination Event (as defined in the Plan Support Agreement). The delivery of the Plan Support Termination Notice caused the Terminated Plan to become null and void.
Following the occurrence of the Plan Support Termination Event as described above and termination of the Merger and Purchase Agreement as described below, the Debtors filed the Plan of Reorganization and the Disclosure Statement with the Bankruptcy Court in May 2016.
The Plan of Reorganization provides that the confirmation and effective date of the Plan of Reorganization with respect to the TCEH Debtors may occur separate from, and independent of, the confirmation and effective date of the Plan of Reorganization with respect to the Debtors other than the TCEH Debtors (the EFH Debtors). The Plan of Reorganization, subject to certain conditions and required regulatory approvals, provides for, among other things:
• | with respect to the TCEH Debtors, either (i) a tax-free spin-off from EFH Corp. (the Reorganized TCEH Spin-Off), including a transaction that will result in a partial step-up in the tax basis of certain TCEH assets, or (ii) a taxable transaction that results in the assets of the TCEH Debtors being distributed to Reorganized TCEH, and |
• | with respect to the EFH Debtors, the reorganization of EFH Corp. and EFIH (Reorganized EFH) either pursuant to (a) an equity investment (which may be from existing creditors or third-party investors) or (b) pursuant to a standalone plan of reorganization, in which creditors receive certain allocated pro rata shares of common stock of Reorganized EFH. |
Information contained in the Plan of Reorganization and the Disclosure Statement is subject to change, whether as a result of amendments to the Plan of Reorganization, requirements by the Bankruptcy Court, actions of third parties, or otherwise.
The Bankruptcy Code does not permit solicitation of acceptances of a plan of reorganization until the Bankruptcy Court approves the applicable disclosure statement relating to such plan of reorganization. Accordingly, this quarterly report on Form 10-Q is not intended to be a solicitation for a vote on the Plan of Reorganization. There can be no assurance that the Bankruptcy Court will approve the Disclosure Statement, that the Debtors' stakeholders will vote to accept the Plan of Reorganization, or that the Bankruptcy Court will confirm the Plan of Reorganization. The Debtors will emerge from bankruptcy if and when a plan of reorganization receives the requisite approval from holders of claims, the Bankruptcy Court enters an order confirming such plan of reorganization, and certain conditions to the effectiveness of such plan of reorganization are satisfied.
Plan Support Agreement
In August 2015 (as amended in September 2015 and November 2015), each of the Debtors entered into a Plan Support Agreement (Plan Support Agreement) with various of their respective creditors, the Sponsor Group, the official committee of TCEH unsecured creditors and the Investor Group in order to effect an agreed upon restructuring of the Debtors pursuant to the Terminated Plan along with, upon certain events, an Alternative Restructuring (as defined in the Plan Support Agreement), which includes the Plan of Reorganization. The Bankruptcy Court approved the Debtors' entry into the Plan Support Agreement in September 2015.
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In May 2016, certain first lien creditors of TCEH (the Required TCEH First Lien Creditors) delivered a Plan Support Termination Notice to the Debtors and the other parties to the Plan Support Agreement notifying such parties of the occurrence of a Plan Support Termination Event pursuant to Section 11(g) of the Plan Support Agreement. The Plan Support Termination Notice stated that the Plan Support Outside Date can only be extended beyond April 30, 2016 if: (i) all required approvals from the PUCT with respect to the consummation of the Terminated Plan had been obtained before such date, or (ii) the Required Investor Parties (as defined in the Plan Support Agreement) submit a written request, which is received by the Required TCEH First Lien Creditors no later than April 30, 2016, to extend the Plan Support Outside Date for thirty days. The Plan Support Termination Notice stated that neither of the foregoing extensions had been triggered as of the date of the Plan Support Termination Notice. The delivery of the Plan Support Termination Notice caused the Terminated Plan to become null and void. The delivery of the Plan Support Termination Notice does not terminate the obligations of certain of the parties thereto to not object to or interfere with an Alternative Restructuring (including the Plan of Reorganization), subject to certain conditions.
The parties' obligations with respect to such Alternative Restructuring, which remain in effect, may be terminated upon the occurrence of certain events described in the Plan Support Agreement. In addition, under the Plan Support Agreement, the supporting parties have committed to support the inclusion of releases with respect to the claims described in the Settlement Agreement (described below) in the context of an alternative plan (which would become effective when a plan of reorganization contemplating an Alternative Restructuring, such as the Plan of Reorganization, becomes effective).
Settlement Agreement
The Settling Parties entered into a settlement agreement (the Settlement Agreement) in August 2015 (as amended in September 2015) to compromise and settle, among other things (a) intercompany claims among the Debtors, (b) claims and causes of actions against holders of first lien claims against TCEH and the agents under the TCEH Senior Secured Facilities, (c) claims and causes of action against holders of interests in EFH Corp. and certain related entities and (d) claims and causes of action against each of the Debtors' current and former directors, the Sponsor Group, managers and officers and other related entities. The Settlement Agreement remains effective, notwithstanding the termination of the Terminated Plan. The Bankruptcy Court approved the Settlement Agreement in December 2015.
Termination of Merger and Purchase Agreement
In August 2015, EFH Corp. and EFIH entered into a Purchase Agreement and Agreement and Plan of Merger (Merger and Purchase Agreement) with two acquisition entities, Ovation Acquisition I, L.L.C. (OV1) and Ovation Acquisition II, L.L.C. (together with OV1, the Purchasers), which are controlled by a consortium (collectively, the Investor Group) consisting of certain TCEH creditors, an affiliate of Hunt Consolidated, Inc. and certain other investors designated by Hunt Consolidated, Inc., pursuant to which the Purchasers agreed to acquire Reorganized EFH. In May 2016, following receipt of the Plan Support Termination Notice described above, EFH Corp. and EFIH delivered a written notice to the Purchasers terminating the Merger and Purchase Agreement due to the occurrence of a Plan Support Termination Event under the Plan Support Agreement. EFH Corp. and EFIH are entitled to reimbursement by the Purchasers of certain fees and expenses incurred by EFH Corp. and EFIH or paid by EFH Corp. or EFIH to, or on behalf of, the Purchasers prior to, and as a result of, the termination of the Merger Agreement.
As a result of the termination of the Merger and Purchase Agreement, each of the (i) equity commitment letter delivered by each member of the Investor Group in favor of EFH Corp., EFIH and the Purchasers in connection with the execution of the Merger and Purchase Agreement and (ii) Backstop Agreement (Backstop Agreement) between EFH Corp. and EFIH and certain investors named therein and their permitted assignees (Backstop Purchasers) and OV1, pursuant to which the Backstop Purchasers agreed to backstop approximately $5.087 billion of equity rights offered to certain holders of claims against the Debtors, automatically terminated.
Texas Transmission Acquisition
EFH Corp. instituted an adversary proceeding in the Bankruptcy Court to enforce certain rights against Texas Transmission under the Investor Rights Agreement, dated November 2008 among Oncor and certain of its direct and indirect equity holders, including EFH Corp. and Texas Transmission (Investor Rights Agreement), including with respect to Texas Transmission's obligations to participate in a sale of EFH Corp.'s interests in Oncor. In April 2016, the Bankruptcy Court ruled in favor of EFH Corp. in this proceeding (see Note 12).
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Regulatory Approvals
In May 2016, the TCEH Debtors received approval from the NRC with respect to its change of control application contemplated by the Plan of Reorganization.
Scheduling Matters
The Debtors filed a proposed scheduling order with respect to the Disclosure Statement and the Plan of Reorganization in May 2016. The Bankruptcy Court is scheduled to hold a hearing later in May 2016 to consider the Debtors' scheduling request with respect to the timing of the hearing to consider approval of the Disclosure Statement, confirmation of the Plan of Reorganization and related discovery protocols. The timelines set forth in the proposed scheduling order are subject to revision by the Bankruptcy Court, and may change based on subsequent orders entered by the Bankruptcy Court (on its own, upon the motion of a party, or upon the Debtors' request).
Tax Matters
In June 2014, EFH Corp. filed a request with the IRS for a private letter ruling, which request has been supplemented from time to time in response to requests from the IRS for information or as required by changes in the contemplated transactions (as supplemented, the Private Letter Ruling). It is expected that, among other things, the Private Letter Ruling, if obtained, will provide for certain rulings regarding the qualification of (i) the transfer of certain assets and ordinary course operating liabilities to a newly-formed entity wholly-owned by TCEH (Reorganized TCEH) and (ii) the distribution of the equity of Reorganized TCEH, the cash proceeds from Reorganized TCEH debt, the cash proceeds from the sale of preferred stock in a newly-formed entity, and the right to receive payments under a tax receivables agreement (if any), to holders of TCEH first lien claims as a reorganization qualifying for tax-free treatment to the extent of the Reorganized TCEH stock received. The Debtors intend to continue to pursue the Private Letter Ruling to support the Plan of Reorganization.
Implications of the Chapter 11 Cases
Our ability to continue as a going concern is contingent upon, among other factors, our ability to comply with the financial and other covenants contained in the DIP Facilities described in Note 10, our ability to obtain new debtor in possession financing in the event the DIP Facilities were to expire during the pendency of the Chapter 11 Cases, our ability to complete a Chapter 11 plan of reorganization in a timely manner, including obtaining creditor and Bankruptcy Court approval of such plan, obtaining applicable regulatory approvals required for such plan and our ability to obtain any exit financing needed to implement such plan. These circumstances and uncertainties inherent in the bankruptcy proceedings raise substantial doubt about our ability to continue as a going concern.
Pre-Petition Claims
Holders of the substantial majority of pre-petition claims were required to file proofs of claims by the bar date established by the Bankruptcy Court. A bar date is the date by which certain claims against the Debtors must be filed if the claimants wish to receive any distribution in the Chapter 11 Cases. The Bankruptcy Court established a bar date of October 27, 2014 for the substantial majority of claims. In addition, in July 2015, the Bankruptcy Court entered an order establishing December 14, 2015 as the bar date for certain asbestos claims that arose or are deemed to have arisen before the Petition Date, except for certain specifically exempt claims.
Since the Petition Date and prior to the applicable bar dates (which have expired), we have received approximately 41,300 filed pre-petition claims, including approximately 30,900 in filed asbestos claims. We have substantially completed the process of reconciling all non-asbestos claims that were filed and have recorded such claims at the expected allowed amount. As of May 9, 2016, approximately 5,700 of those claims have been settled, withdrawn or expunged. We continue to work with creditors regarding certain non-asbestos claims to determine the ultimate amount of the allowed claims. Differences between those final allowed claims and the liabilities recorded in the condensed consolidated balance sheets will be recognized as reorganization items in our condensed statements of consolidated loss as they are resolved. The resolution of such claims could result in material adjustments to our financial statements.
Certain claims filed or reflected in our schedules of assets and liabilities will be resolved on the effective date of the Plan of Reorganization, including certain claims filed by holders of funded debt and contract counterparties. Claims that remain unresolved or unreconciled through the filing of this report have been estimated based upon management's best estimate of the likely claim amounts that the Bankruptcy Court will ultimately allow.
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PUCT Approval of Acquisition of Reorganized EFH
In March 2016, the PUCT approved the acquisition of Reorganized EFH contemplated by the Merger and Purchase Agreement. The order approving the acquisition is subject to a number of material conditions and commitments. The PUCT issued the final order related to the acquisition in March 2016. In April 2016, prior to the termination of the Merger and Purchase Agreement, the Investor Group requested a rehearing by the PUCT with respect to certain conditions and commitments set forth in the PUCT's final order. The PUCT will consider the Investor Group's request for a rehearing later in May 2016. We cannot predict the outcome of this request.
3. | PURCHASE OF LA FRONTERA HOLDINGS, LLC |
In April 2016, Luminant purchased all of the membership interests in La Frontera Holdings, LLC, the indirect owner of two natural gas fueled generation facilities representing nearly 3,000 MW of capacity located in ERCOT, from La Frontera Ventures, LLC, a subsidiary of NextEra Energy, Inc. The facility in Forney, Texas has a capacity of 1,912 MW and the facility in Paris, Texas has a capacity of 1,076 MW. The aggregate purchase price under the agreement was approximately $1.313 billion, which included the repayment of approximately $950 million of existing project financing indebtedness of La Frontera Holdings, LLC and its subsidiaries at the closing of the transaction, plus approximately $240 million for cash and net working capital subject to final settlement. The purchase price was funded by cash-on-hand and additional borrowings under the TCEH DIP Facility totaling $1.1 billion. The acquired entities are subsidiary guarantors under the TCEH DIP agreement.
We are currently in the process of completing our purchase price allocation for the assets acquired and the liabilities assumed in the acquisition. We will provide the pro forma financial results in our quarterly report on Form 10-Q for the period ending June 30, 2016.
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4. | VARIABLE INTEREST ENTITIES |
A variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. Accounting standards require consolidation of a VIE if we have (a) the power to direct the significant activities of the VIE and (b) the right or obligation to absorb profit and loss from the VIE (i.e., we are the primary beneficiary of the VIE). In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE.
Oncor Holdings, an indirect wholly owned subsidiary of EFH Corp. that holds an approximate 80% interest in Oncor, is not consolidated in EFH Corp.'s financial statements, and instead is accounted for as an equity method investment, because the structural and operational ring-fencing measures discussed in Note 1 prevent us from having power to direct the significant activities of Oncor Holdings or Oncor. In accordance with accounting standards, we account for our investment in Oncor Holdings under the equity method, as opposed to the cost method, based on our level of influence over its activities. See below for additional information about our equity method investment in Oncor Holdings. There are no other material investments accounted for under the equity or cost method. The maximum exposure to loss from our interests in VIEs does not exceed our carrying value.
Non-Consolidation of Oncor and Oncor Holdings
Our investment in unconsolidated subsidiary as presented in the condensed consolidated balance sheets totaled $6.086 billion and $6.064 billion at March 31, 2016 and December 31, 2015, respectively, and consists almost entirely of our interest in Oncor Holdings, which we account for under the equity method as described above. Oncor provides services, principally electricity distribution, to TCEH's retail operations, and the related revenues represented 23% and 25% of Oncor Holdings' consolidated operating revenues for the three months ended March 31, 2016 and 2015, respectively.
See Note 16 for discussion of Oncor Holdings' and Oncor's transactions with EFH Corp. and its other subsidiaries.
Distributions from Oncor Holdings and Related Considerations — Oncor Holdings' distributions of earnings to us totaled $40 million and $74 million for the three months ended March 31, 2016 and 2015, respectively. Distributions may not be paid except to the extent Oncor maintains a required regulatory capital structure as discussed below. At March 31, 2016, $54 million was eligible to be distributed to Oncor's members after taking into account the regulatory capital structure limit, of which approximately 80% relates to our ownership interest in Oncor. The boards of directors of each of Oncor and Oncor Holdings can withhold distributions to the extent the applicable board determines in good faith that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings.
Oncor's distributions are limited by its regulatory capital structure, which is required to be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. At March 31, 2016, Oncor's regulatory capitalization ratio was 59.7% debt to 40.3% equity. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes bonds issued by Oncor Electric Delivery Transition Bond Company LLC, which were issued in 2003 and 2004 to recover specific generation-related regulatory assets and other qualified costs. Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of accounting for the Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization).
EFH Corp., Oncor Holdings, Oncor and Oncor's minority investor are parties to a Federal and State Income Tax Allocation Agreement. Additional income tax amounts receivable or payable may arise in the normal course under that agreement.
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Oncor Holdings Financial Statements — Condensed statements of consolidated income of Oncor Holdings and its subsidiaries for the three months ended March 31, 2016 and 2015 are presented below:
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Operating revenues | $ | 943 | $ | 946 | |||
Operation and maintenance expenses | (401 | ) | (380 | ) | |||
Depreciation and amortization | (211 | ) | (217 | ) | |||
Taxes other than income taxes | (113 | ) | (111 | ) | |||
Other income and (deductions) — net | (5 | ) | (1 | ) | |||
Interest expense and related charges | (84 | ) | (81 | ) | |||
Income before income taxes | 129 | 156 | |||||
Income tax expense | (51 | ) | (61 | ) | |||
Net income | 78 | 95 | |||||
Net income attributable to noncontrolling interests | (16 | ) | (20 | ) | |||
Net income attributable to Oncor Holdings | $ | 62 | $ | 75 | |||
Assets and liabilities of Oncor Holdings at March 31, 2016 and December 31, 2015 are presented below:
March 31, 2016 | December 31, 2015 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 21 | $ | 26 | |||
Restricted cash | 60 | 38 | |||||
Trade accounts receivable — net | 382 | 388 | |||||
Trade accounts and other receivables from affiliates | 101 | 118 | |||||
Income taxes receivable from EFH Corp. | 102 | 107 | |||||
Inventories | 100 | 82 | |||||
Prepayments and other current assets | 100 | 88 | |||||
Total current assets | 866 | 847 | |||||
Other investments | 94 | 97 | |||||
Property, plant and equipment — net | 13,234 | 13,024 | |||||
Goodwill | 4,064 | 4,064 | |||||
Regulatory assets — net | 1,163 | 1,194 | |||||
Other noncurrent assets | 41 | 31 | |||||
Total assets | $ | 19,462 | $ | 19,257 | |||
LIABILITIES | |||||||
Current liabilities: | |||||||
Short-term borrowings | $ | 1,054 | $ | 840 | |||
Long-term debt due currently | 41 | 41 | |||||
Trade accounts payable — nonaffiliates | 197 | 150 | |||||
Income taxes payable to EFH Corp. | 24 | 20 | |||||
Accrued taxes other than income | 67 | 181 | |||||
Accrued interest | 67 | 82 | |||||
Other current liabilities | 141 | 144 | |||||
Total current liabilities | 1,591 | 1,458 | |||||
Accumulated deferred income taxes | 2,010 | 1,985 | |||||
Long-term debt, less amounts due currently | 5,648 | 5,646 | |||||
Other noncurrent liabilities and deferred credits | 2,310 | 2,306 | |||||
Total liabilities | $ | 11,559 | $ | 11,395 | |||
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5. | GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS |
Goodwill
The following table provides information regarding our goodwill balance, all of which relates to the Competitive Electric segment and arose in connection with accounting for the Merger. None of the goodwill is being deducted for tax purposes.
Goodwill before impairment charges | $ | 18,342 | |
Accumulated noncash impairment charges | (18,190 | ) | |
Balance at March 31, 2016 and December 31, 2015 | 152 | ||
Goodwill Impairments
Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (we have selected a December 1 test date) or whenever events or changes in circumstances indicate an impairment may exist.
During the three months ended March 31, 2015, we experienced an impairment indicator related to decreases in forward wholesale electricity prices when compared to those prices reflected in our December 1, 2014 goodwill impairment testing analysis. As a result, the likelihood of a goodwill impairment had increased, and we initiated further testing of goodwill. Our testing of goodwill for impairment as of March 31, 2015 resulted in an impairment charge totaling $700 million, which we reported in the Competitive Electric segment results.
Identifiable Intangible Assets
Identifiable intangible assets, including amounts that arose in connection with accounting for the Merger, are comprised of the following:
March 31, 2016 | December 31, 2015 | |||||||||||||||||||||||
Identifiable Intangible Asset | Gross Carrying Amount | Accumulated Amortization | Net | Gross Carrying Amount | Accumulated Amortization | Net | ||||||||||||||||||
Retail customer relationship | $ | 463 | $ | 445 | $ | 18 | $ | 463 | $ | 442 | $ | 21 | ||||||||||||
Capitalized in-service software | 370 | 226 | 144 | 362 | 214 | 148 | ||||||||||||||||||
Other identifiable intangible assets (a) | 58 | 24 | 34 | 72 | 35 | 37 | ||||||||||||||||||
Total identifiable intangible assets subject to amortization | $ | 891 | $ | 695 | 196 | $ | 897 | $ | 691 | 206 | ||||||||||||||
Retail trade name (not subject to amortization) | 955 | 955 | ||||||||||||||||||||||
Mineral interests (not currently subject to amortization) | 5 | 5 | ||||||||||||||||||||||
Total identifiable intangible assets | $ | 1,156 | $ | 1,166 | ||||||||||||||||||||
____________
(a) | Includes favorable purchase and sales contracts, environmental allowances and credits and mining development costs. See discussion below regarding impairment charges recorded in the three months ended March 31, 2015 related to other identifiable intangible assets. |
At March 31, 2016 and December 31, 2015, amounts related to fully amortized assets that are expired, or of no economic value, have been excluded from both the gross carrying and accumulated amortization amounts in the table above.
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Amortization expense related to finite-lived identifiable intangible assets (including the condensed statements of consolidated loss line item) consisted of:
Identifiable Intangible Asset | Condensed Statements of Consolidated Loss Line | Segment | Three Months Ended March 31, | |||||||||
2016 | 2015 | |||||||||||
Retail customer relationship | Depreciation and amortization | Competitive Electric | $ | 3 | $ | 4 | ||||||
Capitalized in-service software | Depreciation and amortization | Competitive Electric and Corporate and Other | 13 | 11 | ||||||||
Other identifiable intangible assets | Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization | Competitive Electric | 3 | 5 | ||||||||
Total amortization expense (a) | $ | 19 | $ | 20 | ||||||||
____________
(a) | Amounts recorded in depreciation and amortization totaled $18 million and $15 million for the three months ended March 31, 2016 and 2015, respectively. |
Intangible Impairments
The impairments of our generation facilities in March 2015 (see Note 7) resulted in the impairment of the SO2 allowances under the Clean Air Act's acid rain cap-and-trade program that are associated with those facilities to the extent they are not projected to be used at other sites. The fair market values of the SO2 allowances were estimated to be de minimis based on Level 3 fair value estimates (see Note 14). Accordingly, in the three months ended March 31, 2015, we recorded noncash impairment charges of $51 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions (see Note 18) related to our existing environmental allowances and credits intangible asset.
During the three months ended March 31, 2015, we determined that certain intangible assets related to favorable power purchase contracts should be evaluated for impairment. That conclusion was based on further declines in wholesale electricity prices in ERCOT experienced during the three months ended March 31, 2015. Our fair value measurement was based on a discounted cash flow analysis of the contracts that compared the contractual price and terms of the contract to forecasted wholesale electricity and renewable energy credit (REC) prices in ERCOT. As a result of the analysis, we recorded a noncash impairment charge of $8 million in our Competitive Electric segment (before deferred income tax benefit) in other deductions (see Note 18).
Estimated Amortization of Identifiable Intangible Assets
The estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as follows:
Year | Estimated Amortization Expense | |||
2016 | $ | 77 | ||
2017 | $ | 56 | ||
2018 | $ | 36 | ||
2019 | $ | 18 | ||
2020 | $ | 10 | ||
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6. | INCOME TAXES |
EFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. EFH Corp. is the corporate member of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH is classified as a disregarded entity for US federal income tax purposes. Oncor is a partnership for US federal income tax purposes and is not a corporate member of the EFH Corp. consolidated group. Pursuant to applicable US Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.
EFH Corp. and certain of its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) are parties to a Federal and State Income Tax Allocation Agreement, which provides, among other things, that any corporate member or disregarded entity in the EFH Corp. group is required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. The Plan of Reorganization provides that upon the effective date of the plan the Debtors will reject this agreement. Additionally, under the terms of the Settlement Agreement, no further cash payments among the Debtors will be made in respect of federal income taxes. We have elected to continue to allocate federal income taxes among the entities that are parties to the Federal and State Income Tax Allocation Agreement. The Settlement Agreement did not alter the allocation and payment for state income taxes, which will continue to be settled.
EFH Corp., Oncor Holdings, Oncor and Oncor's minority investors are parties to a separate Federal and State Income Tax Allocation Agreement, which governs the computation of federal income tax liability among such parties, and similarly provides, among other things, that each of Oncor Holdings and Oncor will pay EFH Corp. its share of an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. The Settlement Agreement had no impact on the tax sharing agreement among EFH, Oncor Holdings and Oncor.
The calculation of our effective tax rate is as follows:
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Loss before income taxes and equity in earnings of unconsolidated subsidiaries | $ | (437 | ) | $ | (2,003 | ) | |
Income tax benefit | $ | 127 | $ | 401 | |||
Effective tax rate | 29.1 | % | 20.0 | % | |||
For the three months ended March 31, 2016, the effective tax rate of 29.1% related to our income tax benefit was lower than the US Federal statutory rate of 35% due primarily to nondeductible legal and other professional services costs related to the Chapter 11 Cases.
For the three months ended March 31, 2015, the effective tax rate of 20.0% related to our income tax benefit was lower than the US Federal statutory rate of 35% due primarily to the nondeductible goodwill impairment charge (see Note 5) and nondeductible legal and other professional services costs related to the Chapter 11 Cases, offset by the difference in the forecasted effective tax rate and the statutory rate applied to long-lived and intangible asset impairment charges (see Notes 5 and 7).
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7. | IMPAIRMENT OF LONG-LIVED ASSETS |
Impairment of Lignite/Coal Fueled Generation and Mining Assets
We evaluated our generation assets for impairment during March 2015 as a result of an impairment indicator related to the continued decline in forecasted wholesale electricity prices in ERCOT. Our evaluation concluded that an impairment existed, and the carrying value at our Big Brown generation facility and related mining facility was reduced by $676 million.
Our fair value measurement for these assets was determined based on an income approach that utilized probability-weighted estimates of discounted future cash flows, which were Level 3 fair value measurements (see Note 14). Key inputs into the fair value measurement for these assets included current forecasted wholesale electricity prices in ERCOT, forecasted fuel prices, capital and operating expenditure forecasts and discount rates.
Additional material impairments may occur in the future for our other generation facilities if forward wholesale electricity prices continue to decline or forecasted costs of producing electricity at our generation facilities increase, including increased costs of compliance with new and/or proposed environmental regulations.
8. | INTEREST EXPENSE AND RELATED CHARGES |
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Interest paid/accrued on debtor-in-possession financing | $ | 74 | $ | 73 | |||
Adequate protection amounts paid/accrued | 322 | 302 | |||||
Interest paid/accrued on pre-petition debt (a) | 1 | 237 | |||||
Capitalized interest | (3 | ) | (3 | ) | |||
Total interest expense and related charges | $ | 394 | $ | 609 | |||
____________
(a) | For the three months ended March 31, 2015, amount includes $235 million in post-petition interest related to the EFIH Second Lien Notes (see Note 11). For the three months ended March 31, 2016 and 2015, includes interest paid/accrued on long-term debt not subject to compromise. |
Interest expense for the three months ended March 31, 2016 and 2015 reflects interest paid and accrued on debtor-in-possession financing (see Note 10), adequate protection amounts paid and accrued, as approved by the Bankruptcy Court in June 2014 for the benefit of secured creditors of (a) $22.616 billion principal amount of outstanding borrowings from the TCEH Senior Secured Facilities, (b) $1.750 billion principal amount of outstanding TCEH Senior Secured Notes and (c) the $1.243 billion net liability related to the TCEH first lien interest rate swaps and natural gas hedging positions terminated shortly after the Bankruptcy Filing (see Note 15), in exchange for their consent to the senior secured, super-priority liens contained in the TCEH DIP Facility and any diminution in value of their interests in the pre-petition collateral from the Petition Date, and interest paid on the EFIH Second Lien Notes as approved by the Bankruptcy Court in March 2015 (see Note 11). The interest rate applicable to the adequate protection amounts paid/accrued for the three months ended March 31, 2016 was 4.92% (one-month LIBOR plus 4.50%). The amount of adequate protection payments may be adjusted to reflect the valuation of the TCEH Debtors determined in connection with confirmation of the Plan of Reorganization by the Bankruptcy Court. In addition, upon completion of the Plan of Reorganization, amounts of adequate protection payments may be re-characterized as payments of principal.
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The Bankruptcy Code generally restricts payment of interest on pre-petition debt, subject to certain exceptions. The Bankruptcy Court approved post-petition interest payments on the EFIH Second Lien Notes in March 2015 as discussed in Note 11. Additional interest payments may also be made upon approval by the Bankruptcy Court (see Note 12). Other than amounts ordered or approved by the Bankruptcy Court, effective on the Petition Date, we discontinued recording interest expense on outstanding pre-petition debt classified as LSTC. The table below shows contractual interest amounts, which are amounts due under the contractual terms of the outstanding debt, including debt subject to compromise during the Chapter 11 Cases. Interest expense reported in the condensed statements of consolidated loss for the three months ended March 31, 2016 and 2015 does not include $336 million and $288 million, respectively, in contractual interest on pre-petition debt classified as LSTC, which has been stayed by the Bankruptcy Court effective on the Petition Date. For the three months ended March 31, 2016 and 2015, adequate protection paid/accrued presented below excludes $15 million and $14 million, respectively, related to interest paid/accrued on the TCEH first-lien interest rate and commodity hedge claims (see Note 15), as such amounts are not included in contractual interest amounts below.
Three Months Ended March 31, 2016 | Three Months Ended March 31, 2015 | |||||||||||||||||||||||||||||||
Entity: | Contractual Interest on Debt Classified as LSTC | Adequate Protection Paid/Accrued | Approved Interest Paid/Accrued | Contractual Interest on Debt Classified as LSTC Not Paid/Accrued | Contractual Interest on Debt Classified as LSTC | Adequate Protection Paid/Accrued | Approved Interest Paid/Accrued (a) | Contractual Interest on Debt Classified as LSTC Not Paid/Accrued | ||||||||||||||||||||||||
EFH Corp. | $ | 11 | $ | — | $ | — | $ | 11 | $ | 31 | $ | — | $ | — | $ | 31 | ||||||||||||||||
EFIH | 101 | — | — | 101 | 111 | — | 50 | 61 | ||||||||||||||||||||||||
EFCH | — | — | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||
TCEH | 531 | 307 | — | 224 | 513 | 288 | — | 225 | ||||||||||||||||||||||||
Eliminations (b) | — | — | — | — | (31 | ) | — | — | (31 | ) | ||||||||||||||||||||||
Total | $ | 643 | $ | 307 | $ | — | $ | 336 | $ | 626 | $ | 288 | $ | 50 | $ | 288 | ||||||||||||||||
___________
(a) | For the three months ended March 31, 2015 represents portion of interest related to the EFIH Second Lien Notes that was repaid based on the approval of the Bankruptcy Court; however, excludes $185 million of post-petition interest paid in 2015 that contractually related to 2014 and default interest (see Note 11). |
(b) | Represents contractual interest on affiliate debt held by EFH Corp. and EFIH that is classified as LSTC. |
9. | REORGANIZATION ITEMS |
Expenses and income directly associated with the Chapter 11 Cases are reported separately in the condensed statements of consolidated loss as reorganization items as required by ASC 852, Reorganizations. Reorganization items also include adjustments to reflect the carrying value of LSTC at their estimated allowed claim amounts, as such adjustments are determined. The following table presents reorganization items incurred in the three months ended March 31, 2016 and 2015 as reported in the condensed statements of consolidated loss:
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Expenses related to legal advisory and representation services | $ | 31 | $ | 50 | |||
Expenses related to other professional consulting and advisory services | 24 | 28 | |||||
Contract claims adjustments | 1 | 32 | |||||
Fees associated with extension of EFIH DIP Facility | 14 | — | |||||
Fees associated with repayment of EFIH Second Lien Notes (Note 11) | — | 28 | |||||
Total reorganization items | $ | 70 | $ | 138 | |||
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10. | DEBTOR-IN-POSSESSION BORROWING FACILITIES AND LONG-TERM DEBT NOT SUBJECT TO COMPROMISE |
TCEH DIP Facility — The Bankruptcy Court approved the TCEH DIP Facility in June 2014. The TCEH DIP Facility currently provides for up to $3.375 billion in senior secured, super-priority financing consisting of a revolving credit facility of up to $1.950 billion (TCEH DIP Revolving Credit Facility) and a term loan facility of up to $1.425 billion (TCEH DIP Term Loan Facility). The TCEH DIP Facility is a Senior Secured, Super-Priority Credit Agreement by and among the TCEH Debtors, the lenders that are party thereto from time to time and an administrative and collateral agent.
The TCEH DIP Facility and related available capacity at March 31, 2016 are presented below. In the March 31, 2016 condensed consolidated balance sheet, the borrowings under the TCEH DIP Facility are reported as current liabilities. The maturity date of the TCEH DIP Facility is the earlier of (a) November 2016 or (b) the effective date of any plan of reorganization of TCEH. TCEH's cash collateral order expires sixty days after the date of the Plan Support Termination Notice, provided that the TCEH Debtors do not otherwise cause an event of default under the cash collateral order. The TCEH Debtors are currently in discussions with TCEH first lien creditors regarding the terms of an extension of the cash collateral order. The TCEH DIP Facility must be repaid in full prior to the TCEH Debtors emergence from the Chapter 11 Cases.
March 31, 2016 | ||||||||||||
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 | — | 139 | |||||||||
Total TCEH DIP Facility | $ | 3,375 | $ | 1,950 | $ | 139 | ||||||
___________
(a) | Facility used for general corporate purposes. No amounts were borrowed at March 31, 2016. Pursuant to an order of the Bankruptcy Court, the TCEH Debtors may not have more than $1.650 billion of TCEH DIP Revolving Credit Facility cash borrowings outstanding without written consent of the TCEH committee of unsecured creditors and the ad hoc group of TCEH unsecured noteholders or further order of the Bankruptcy Court. |
(b) | Facility used for general corporate purposes, including but not limited to, $800 million for issuing letters of credit. |
At both March 31, 2016 and December 31, 2015, all $1.425 billion of the TCEH DIP Term Loan Facility has been borrowed. Of this borrowing, $800 million represents amounts that support issuances of letters of credit and have been funded to a collateral account. Of the collateral account amount at March 31, 2016, $139 million is reported as cash and cash equivalents and $661 million is reported as restricted cash, which represents the amount of outstanding letters of credit. As discussed in Note 3, the acquisition of La Frontera Holdings, LLC in April 2016 was funded by cash-on-hand and $1.1 billion in additional cash borrowings under the TCEH DIP Revolving Credit Facility. After completing the acquisition, we repaid approximately $230 million of borrowings under the TCEH DIP Revolving Credit Facility utilizing cash acquired in the transaction.
Amounts borrowed under the TCEH DIP Term Loan Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 3%. At both March 31, 2016 and December 31, 2015, the interest rate on outstanding borrowings was 3.75%. The TCEH DIP Facility also provides for certain additional fees payable to the agents and lenders, as well as availability fees payable with respect to any unused portions of the available TCEH DIP Facility.
The TCEH Debtors' obligations under the TCEH DIP Facility are secured by a lien covering substantially all of the TCEH Debtors' assets, rights and properties (including the assets acquired in the La Frontera acquisition), subject to certain exceptions set forth in the TCEH DIP Facility. The TCEH DIP Facility provides that all obligations thereunder constitute administrative expenses in the Chapter 11 Cases, with administrative priority and senior secured status under the Bankruptcy Code and, subject to certain exceptions set forth in the TCEH DIP Facility, have priority over any and all administrative expense claims, unsecured claims and costs and expenses in the Chapter 11 Cases. EFCH is a guarantor to the agreement governing the TCEH DIP Facility along with substantially all of TCEH’s subsidiaries, including all subsidiaries that are Debtors in the Chapter 11 Cases.
The TCEH DIP Facility also permits certain hedging agreements to be secured on a pari-passu basis with the TCEH DIP Facility in the event those hedging agreements meet certain criteria set forth in the TCEH DIP Facility.
In June 2014, the RCT agreed to accept a collateral bond from TCEH of up to $1.1 billion to secure mining land reclamation obligations. The collateral bond is a $1.1 billion carve-out from the super-priority liens under the TCEH DIP Facility that will enable the RCT to be paid before the TCEH DIP Facility lenders.
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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. Consolidated Superpriority Secured Net Debt consists of outstanding term loans and revolving credit exposure under the TCEH DIP Facility less unrestricted cash. As of March 31, 2016, we are in compliance with this financial covenant. Upon the existence of an event of default, the TCEH DIP Facility provides that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.
EFIH DIP Facility, EFIH First Lien Notes Settlement and EFIH Second Lien Notes Repayment — The Bankruptcy Court approved the EFIH DIP Facility in June 2014. The EFIH DIP Facility provides for a $5.4 billion first-lien debtor-in-possession financing facility. In March 2015, $750 million of cash borrowings were used to repay $445 million principal amount of EFIH Second Lien Notes (including accrued and unpaid pre-petition interest of $55 million and post-petition interest of $235 million) and certain fees (see Note 11).
As of March 31, 2016, remaining cash on hand from borrowings under the EFIH DIP Facility, net of fees, totaled approximately $300 million, which was held as cash and cash equivalents. In the March 31, 2016 condensed consolidated balance sheet, the borrowings under the EFIH DIP Facility are reported as current liabilities. In January 2016, the EFIH Debtors paid a $14 million extension fee to extend the maturity date of the EFIH DIP Facility to December 2016. The terms of the EFIH DIP Facility were otherwise unchanged. The EFIH DIP Facility must be repaid in full prior to the EFIH Debtors emergence from the Chapter 11 Cases.
The principal amounts outstanding under the EFIH DIP Facility bear interest based on applicable LIBOR rates, subject to a 1% floor, plus 3.25%. At both March 31, 2016 and December 31, 2015, outstanding borrowings under the EFIH DIP Facility totaled $5.4 billion at an annual interest rate of 4.25%. The EFIH DIP Facility is a non-amortizing loan that may, subject to certain limitations, be voluntarily prepaid by the EFIH Debtors, in whole or in part, without any premium or penalty.
The EFIH DIP Facility will mature on the earlier of (a) the effective date of any plan of reorganization, (b) upon the event of the sale of substantially all of EFIH's assets or (c) December 2016.
EFIH's obligations under the EFIH DIP Facility are secured by a first lien covering substantially all of EFIH's assets, rights and properties, subject to certain exceptions set forth in the EFIH DIP Facility. The EFIH DIP Facility provides that all obligations thereunder constitute administrative expenses in the Chapter 11 Cases, with administrative priority and senior secured status under the Bankruptcy Code and, subject to certain exceptions set forth in the EFIH DIP Facility, will have priority over any and all administrative expense claims, unsecured claims and costs and expenses in the Chapter 11 Cases.
The EFIH DIP Facility provides for affirmative and negative covenants applicable to EFIH and EFIH Finance, including affirmative covenants requiring EFIH and EFIH Finance to provide financial information, budgets and other information to the agents under the EFIH DIP Facility, and negative covenants restricting EFIH's and EFIH Finance's ability to incur additional indebtedness, grant liens, dispose of assets, pay dividends or take certain other actions, in each case except as permitted in the EFIH DIP Facility. The EFIH DIP Facility also includes a minimum liquidity covenant pursuant to which EFIH cannot allow the amount of its unrestricted cash (as defined in the EFIH DIP Facility) to be less than $150 million. As of March 31, 2016, EFIH was in compliance with this minimum liquidity covenant. The Oncor Ring-Fenced Entities are not restricted subsidiaries for purposes of the EFIH DIP Facility.
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The EFIH DIP Facility provides for certain customary events of default, including events of default resulting from non-payment of principal, interest or other amounts when due, material breaches of representations and warranties, material breaches of covenants in the EFIH DIP Facility or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against EFIH. Upon the existence of an event of default, the EFIH DIP Facility provides that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.
The EFIH DIP Facility permits, subject to certain terms, conditions and limitations set forth in the EFIH DIP Facility, EFIH to incur incremental junior lien subordinated debt in an aggregate amount not to exceed $3 billion.
Long-Term Debt Not Subject to Compromise — Amounts presented in the table below represent pre-petition liabilities that are not subject to compromise due to the debt being fully collateralized or specific orders from the Bankruptcy Court approving repayment of the debt.
March 31, 2016 | December 31, 2015 | ||||||
EFH Corp. (parent entity) | |||||||
8.82% Non-Debtor Building Financing due semiannually through February 11, 2022 | $ | 33 | $ | 35 | |||
Unamortized fair value premium (a) | 5 | 6 | |||||
Total EFH Corp. | 38 | 41 | |||||
EFCH | |||||||
9.58% Fixed Notes due in annual installments through December 4, 2019 (b) | 13 | 13 | |||||
8.254% Fixed Notes due in quarterly installments through December 31, 2021 (b) | 23 | 24 | |||||
Unamortized fair value discount (a) | (2 | ) | (2 | ) | |||
Total EFCH | 34 | 35 | |||||
TCEH | |||||||
7.48% Fixed Secured Facility Bonds with amortizing payments through January 2017 (c) | 10 | 13 | |||||
Capital lease obligations | 4 | 5 | |||||
Other | 2 | 2 | |||||
Unamortized discount | — | (1 | ) | ||||
Total TCEH | 16 | 19 | |||||
Total EFH Corp. consolidated | 88 | 95 | |||||
Less amounts due currently | (33 | ) | (35 | ) | |||
Total long-term debt not subject to compromise | $ | 55 | $ | 60 | |||
____________
(a) | Amount represents unamortized fair value adjustments recorded under purchase accounting. |
(b) | Approved by the Bankruptcy Court for repayment. |
(c) | Debt issued by trust and secured by assets held by the trust. |
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11. | LIABILITIES SUBJECT TO COMPROMISE (LSTC) |
The amounts classified as LSTC reflect the company's estimate of pre-petition liabilities and other expected allowed claims to be addressed in the Chapter 11 Cases and may be subject to future adjustment as the Chapter 11 Cases proceed. Amounts classified to LSTC do not include pre-petition liabilities that are fully collateralized by letters of credit or cash deposits. The following table presents LSTC as reported in the condensed consolidated balance sheets at March 31, 2016 and December 31, 2015:
March 31, 2016 | December 31, 2015 | ||||||
Notes, loans and other debt per the following table | $ | 35,560 | $ | 35,560 | |||
Accrued interest on notes, loans and other debt | 745 | 745 | |||||
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements (Note 15) | 1,243 | 1,243 | |||||
Trade accounts payable and other expected allowed claims | 238 | 238 | |||||
Total liabilities subject to compromise | $ | 37,786 | $ | 37,786 | |||
Pre-Petition Notes, Loans and Other Debt Reported as LSTC
Amounts presented below represent principal amounts of pre-petition notes, loans and other debt reported as LSTC.
March 31, 2016 | December 31, 2015 | ||||||
EFH Corp. (parent entity) | |||||||
9.75% Fixed Senior Notes due October 15, 2019 | $ | 2 | $ | 2 | |||
10% Fixed Senior Notes due January 15, 2020 | 3 | 3 | |||||
10.875% Fixed Senior Notes due November 1, 2017 | 33 | 33 | |||||
11.25% / 12.00% Senior Toggle Notes due November 1, 2017 | 27 | 27 | |||||
5.55% Fixed Series P Senior Notes due November 15, 2014 | 89 | 89 | |||||
6.50% Fixed Series Q Senior Notes due November 15, 2024 | 198 | 198 | |||||
6.55% Fixed Series R Senior Notes due November 15, 2034 | 288 | 288 | |||||
Total EFH Corp. | 640 | 640 | |||||
EFIH | |||||||
11% Fixed Senior Secured Second Lien Notes due October 1, 2021 | 322 | 322 | |||||
11.75% Fixed Senior Secured Second Lien Notes due March 1, 2022 | 1,389 | 1,389 | |||||
11.25% / 12.25% Senior Toggle Notes due December 1, 2018 | 1,530 | 1,530 | |||||
9.75% Fixed Senior Notes due October 15, 2019 | 2 | 2 | |||||
Total EFIH | 3,243 | 3,243 | |||||
EFCH | |||||||
Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 | 1 | 1 | |||||
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037 | 8 | 8 | |||||
Total EFCH | 9 | 9 | |||||
TCEH | |||||||
Senior Secured Facilities: | |||||||
TCEH Floating Rate Term Loan Facilities due October 10, 2014 | 3,809 | 3,809 | |||||
TCEH Floating Rate Letter of Credit Facility due October 10, 2014 | 42 | 42 | |||||
TCEH Floating Rate Revolving Credit Facility due October 10, 2016 | 2,054 | 2,054 | |||||
TCEH Floating Rate Term Loan Facilities due October 10, 2017 | 15,691 | 15,691 | |||||
TCEH Floating Rate Letter of Credit Facility due October 10, 2017 | 1,020 | 1,020 | |||||
11.5% Fixed Senior Secured Notes due October 1, 2020 | 1,750 | 1,750 | |||||
15% Fixed Senior Secured Second Lien Notes due April 1, 2021 | 336 | 336 | |||||
15% Fixed Senior Secured Second Lien Notes due April 1, 2021, Series B | 1,235 | 1,235 | |||||
10.25% Fixed Senior Notes due November 1, 2015 | $ | 1,833 | $ | 1,833 | |||
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March 31, 2016 | December 31, 2015 | ||||||
10.25% Fixed Senior Notes due November 1, 2015, Series B | 1,292 | 1,292 | |||||
10.50% / 11.25% Senior Toggle Notes due November 1, 2016 | 1,749 | 1,749 | |||||
Pollution Control Revenue Bonds: | |||||||
Brazos River Authority: | |||||||
5.40% Fixed Series 1994A due May 1, 2029 | 39 | 39 | |||||
7.70% Fixed Series 1999A due April 1, 2033 | 111 | 111 | |||||
7.70% Fixed Series 1999C due March 1, 2032 | 50 | 50 | |||||
8.25% Fixed Series 2001A due October 1, 2030 | 71 | 71 | |||||
8.25% Fixed Series 2001D-1 due May 1, 2033 | 171 | 171 | |||||
6.30% Fixed Series 2003B due July 1, 2032 | 39 | 39 | |||||
6.75% Fixed Series 2003C due October 1, 2038 | 52 | 52 | |||||
5.40% Fixed Series 2003D due October 1, 2029 | 31 | 31 | |||||
5.00% Fixed Series 2006 due March 1, 2041 | 100 | 100 | |||||
Sabine River Authority of Texas: | |||||||
6.45% Fixed Series 2000A due June 1, 2021 | 51 | 51 | |||||
5.20% Fixed Series 2001C due May 1, 2028 | 70 | 70 | |||||
5.80% Fixed Series 2003A due July 1, 2022 | 12 | 12 | |||||
6.15% Fixed Series 2003B due August 1, 2022 | 45 | 45 | |||||
Trinity River Authority of Texas: | |||||||
6.25% Fixed Series 2000A due May 1, 2028 | 14 | 14 | |||||
Other | 1 | 1 | |||||
Total TCEH | 31,668 | 31,668 | |||||
Total EFH Corp. consolidated notes, loans and other debt | $ | 35,560 | $ | 35,560 | |||
TCEH Letter of Credit Facility Activity
Borrowings under the TCEH Letter of Credit Facility have been recorded by TCEH as restricted cash that supports issuances of letters of credit. At both March 31, 2016 and December 31, 2015, the restricted cash related to the pre-petition TCEH Letter of Credit Facility totaled $507 million, and there were no outstanding letters of credit related to the pre-petition TCEH Letter of Credit Facility. Due to the default under the pre-petition TCEH Senior Secured Facilities, the letter of credit capacity is no longer available.
Repayment of EFIH Notes
In March 2015, with the approval of the Bankruptcy Court, EFIH used some of its cash to repay (Repayment) $735 million, including interest at contractual rates, in amounts outstanding under EFIH's pre-petition 11.00% Fixed Senior Secured Second Lien Notes due October 1, 2021 (11.00% Notes) and 11.75% Fixed Senior Secured Second Lien Notes due March 1, 2022 (11.75% Notes) and $15 million in certain fees and expenses of the trustee for such notes. The Repayment resulted in an $84 million reduction in the principal amount of the 11.00% Notes, a $361 million reduction in the principal amount of the 11.75% Notes and the payment of $235 million and $55 million of accrued and unpaid post-petition and pre-petition interest, respectively, at contractual rates. The Repayment required the requisite consent of the lenders under EFIH's DIP Facility. EFIH received such consent from approximately 97% of the lenders under the EFIH DIP Facility in consideration of an aggregate consent fee equal to approximately $13 million.
Information Regarding Significant Pre-Petition Debt
See Note 13 to the Financial Statements in our 2015 Form 10-K for information regarding our pre-petition debt. There have been no changes in pre-petition debt since December 31, 2015.
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12. | COMMITMENTS AND CONTINGENCIES |
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Material guarantees are discussed below.
See Notes 10 and 11 for discussion of guarantees and security for certain of our post-petition and pre-petition debt.
Letters of Credit
At March 31, 2016, TCEH had outstanding letters of credit under the TCEH DIP Facility totaling $661 million as follows:
• | $377 million to support commodity risk management and trading margin requirements in the normal course of business, including over-the-counter and exchange-traded hedging transactions and collateral postings with ERCOT; |
• | $66 million to support executory contracts and insurance agreements; |
• | $55 million to support TCEH's REP financial requirements with the PUCT, and |
• | $163 million for other credit support requirements, including $131 million to support our purchase and sale agreement with La Frontera Holdings, LLC. |
The automatic stay under the Bankruptcy Code does not apply to letters of credit issued under the pre-petition credit facility and third parties may draw if the terms of a particular letter of credit so provide.
Litigation
Aurelius Derivative Claim — Aurelius Capital Master, Ltd. and ACP Master, Ltd. (Aurelius) filed a lawsuit in March 2013, amended in May 2013, in the US District Court for the Northern District of Texas (Dallas Division) against EFCH as a nominal defendant and each of the current directors and a former director of EFCH. In the lawsuit, Aurelius, as a creditor under the TCEH Senior Secured Facilities and certain TCEH secured bonds, both of which are guaranteed by EFCH, filed a derivative claim against EFCH and its directors. Aurelius alleged that the directors of EFCH breached their fiduciary duties to EFCH and its creditors, including Aurelius, by permitting TCEH to make certain loans "without collecting fair and reasonably equivalent value." The lawsuit sought recovery for the benefit of EFCH. In January 2014, the district court granted EFCH's and the directors' motion to dismiss and in February 2014 dismissed the lawsuit. Aurelius has appealed the district court's judgment to the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court). The appeal was automatically stayed as a result of the Bankruptcy Filing. We cannot predict the outcome of this proceeding, including the financial effects, if any.
Make-whole Claims — In May 2014, the indenture trustee for the EFIH 10% First Lien Notes initiated litigation in the Bankruptcy Court seeking, among other things, a declaratory judgment that EFIH is obligated to pay a make-whole premium in connection with the cash repayment of the EFIH First Lien Notes and that such make-whole premium is an allowed secured claim, or in the alternative, an allowed secured or unsecured claim for breach of contract (EFIH First Lien Make-whole Claims). The indenture trustee has alleged that the EFIH First Lien Make-whole Claims are valued at approximately $432 million plus reimbursement of expenses. In separate rulings in March and July 2015, the Bankruptcy Court found that no make-whole premium is due with respect to the EFIH 10% First Lien Notes. In February 2016, the US District Court for the District of Delaware affirmed the Bankruptcy Court's rulings. In February 2016, the Indenture Trustee appealed the District Court's ruling to the US Court of Appeals for the Third Circuit. The EFIH Debtors intend to vigorously defend against this appeal. We cannot predict the outcome of this appeal.
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In June 2014, the indenture trustee for the EFIH Second Lien Notes initiated litigation in the Bankruptcy Court seeking similar relief with respect to the EFIH Second Lien Notes, including among other things, that EFIH is obligated to pay a make-whole premium in connection with any repayment of the EFIH Second Lien Notes and that such make-whole premium would be an allowed secured claim, or in the alternative, an allowed secured or unsecured claim for breach of contract (the EFIH Second Lien Make-whole Claims). If, as of March 31, 2016, the EFIH Second Lien Make-whole Claims were allowed, the amount of such claims would have been approximately $356 million plus reimbursement of expenses. In October 2015, the Bankruptcy Court issued a ruling and order in favor of the EFIH Debtors. The order and ruling found that no make-whole premium is due with respect to the EFIH Second Lien Notes. In April 2016, the US District Court for the District of Delaware issued a ruling and order affirming the Bankruptcy Court's decision. The indenture trustee has appealed that decision to the US Court of Appeals for the Third Circuit, and that court has consolidated the appeal with the appeal filed by the indenture trustee for the EFIH 10% First Lien Notes described above for the purposes of oral argument, if any, and final disposition. The EFIH Debtors intend to vigorously defend against this appeal. We cannot predict the outcome of this appeal.
In July 2015, the EFIH Debtors filed a claim objection with the Bankruptcy Court regarding the EFIH PIK noteholders' claims for a redemption or make-whole premium and post-petition interest at the contract rate under the EFIH PIK Notes. In October 2015, the Bankruptcy Court issued opinions in favor of the EFIH Debtors. One opinion found that no make-whole premium is due with respect to the EFIH PIK Notes. The second opinion found that the EFIH PIK noteholders' allowed claim does not, as a matter of law, include post-petition interest whether at the contract rate or the Federal Judgment Rate. This opinion did find, however, that, in connection with the confirmation of a plan of reorganization, the Bankruptcy Court could, at its discretion, grant post-petition interest as part of the EFIH PIK noteholders' allowed claim under general principals of equity and that such grant could be at the contract rate, the Federal Judgment Rate or any other amount that the Bankruptcy Court determines to be equitable. In November 2015, a majority of the EFIH PIK Noteholders settled their claims contingent on the Terminated Plan becoming effective. These settling noteholders have appealed both of the Bankruptcy Court's rulings to the US District Court for the District of Delaware. Those appeals were stayed pending the effective date of the Terminated Plan. Now that the Terminated Plan is null and void, some or all of these appeals may be revived. Some EFIH PIK Noteholders have not settled their claims. They have appealed the Bankruptcy Court's ruling on post-petition interest to the US District Court for the District of Delaware. That appeal has also been stayed pending an equitable proceeding. The non-settling EFIH PIK Noteholders have also sought to be awarded post-petition interest through an equitable proceeding suggested by the Bankruptcy Court’s second opinion. No briefing schedule has been set for that equitable proceeding. The non-settling EFIH PIK Noteholders' appeal may be revived in connection with an equitable proceeding. The EFIH Debtors intend to vigorously defend against the award of post-petition interest at a rate higher than the Federal Judgment Rate. We cannot predict the outcome of either of these appeals or any equitable proceeding seeking the award of post-petition interest.
In October 2015, EFH Corp. filed a claim objection with the Bankruptcy Court with respect to the EFH Corp. Series P, Q and R Senior Notes (collectively, the EFH Legacy Notes) noteholders' claims for, among other things, make-whole premiums and post-petition interest. If, as of March 31, 2016, a make-whole claim and a post-petition interest claim were allowed, such claims would be $235 million and $77 million, respectively. In October 2015, the indenture trustee for the EFH Legacy Notes filed a response to this claim objection. No argument date has been set by the Bankruptcy Court regarding the EFH Legacy Notes claim objection. In November 2015, these claims were settled contingent on the Terminated Plan becoming effective. Now that the Terminated Plan is null and void, the claims related to the EFH Legacy Notes may be revived. In that case, EFH Corp. would vigorously pursue its claim objection. We cannot predict the outcome of this proceeding.
In October 2015, EFH Corp. filed a claim objection with the Bankruptcy Court with respect to the EFH Corp. 10.875% Senior Notes and 11.25%/12% Senior Toggle Notes (collectively, the EFH LBO Notes) noteholders' claims for, among other things, optional redemption payment and post-petition interest. If, as of March 31, 2016, a redemption claim and a post-petition interest claim were allowed, such claims would be zero and $15 million, respectively. The indenture trustee for the EFH LBO Notes has not yet filed a response to this claim objection. No argument date has been set by the Bankruptcy Court regarding the EFH LBO Notes claim objection. In November 2015, these claims were settled contingent on the Terminated Plan becoming effective. Now that the Terminated Plan is null and void, the claims related to the EFH LBO Notes may be revived. In that case, EFH Corp. would vigorously pursue its claim objection. We cannot predict the outcome of this proceeding.
In addition, creditors may make additional claims in the Chapter 11 Cases for make-whole or redemption premiums in connection with repayments or settlement of other pre-petition debt. These claims could be material. There can be no assurance regarding the outcome of any of the litigation regarding the validity or, if deemed valid, the amount of these make-whole or redemption claims.
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Adversary Complaint against Texas Transmission — In October 2015, EFH Corp. filed with the Bankruptcy Court an adversary complaint against Texas Transmission seeking a judgment from the Bankruptcy Court regarding the obligations of Texas Transmission under the Investor Rights Agreement to participate in a sale of EFH Corp.'s interests in Oncor. In April 2016, the Bankruptcy Court announced it would approve EFH Corp. and the Purchasers' motion for summary judgment in full and denied Texas Transmission's motion for a determination that the court lacks authority to enter a final judgment or order in the proceeding. A written opinion and order regarding these rulings is pending.
Litigation Related to EPA Reviews — In June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of the Clean Air Act (CAA). The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. In April 2013, we received an additional information request from the EPA under Section 114 related to the Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to the Sandow 4 generation facility.
In July 2012, the EPA sent us a notice of violation alleging noncompliance with the CAA's New Source Review Standards and the air permits at our Martin Lake and Big Brown generation facilities. In July 2013, the EPA sent us a second notice of violation alleging noncompliance with the CAA's New Source Review Standards at our Martin Lake and Big Brown generation facilities, which the EPA said "superseded" its July 2012 notice. In August 2013, the US Department of Justice, acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant Generation Company LLC and Big Brown Power Company LLC in federal district court in Dallas, alleging violations of the CAA at our Big Brown and Martin Lake generation facilities. In August 2015, the district court issued its ruling on our motion to dismiss and granted the motion as to seven of the nine claims asserted by the EPA in the lawsuit. Two claims remain before the district court, and those are currently scheduled for trial in October 2017. We believe that we have complied with all requirements of the CAA and intend to vigorously defend against the remaining allegations. The lawsuit requests the maximum civil penalties available under the CAA to the government of up to $32,500 to $37,500 per day for each alleged violation, depending on the date of the alleged violation, and injunctive relief, including an order requiring the installation of best available control technology at the affected units. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. We cannot predict the outcome of these proceedings, including the financial effects, if any.
Greenhouse Gas Emissions
In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from new, modified and reconstructed units, and existing electricity generation plants. The rule for existing facilities would establish state-specific emissions rate goals to reduce nationwide carbon dioxide emissions related to affected electricity generation units by over 30% from 2012 emission levels by 2030. A number of parties, including Luminant, filed petitions for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) for the rule for new, modified and reconstructed plants. In addition, a number of petitions for review of the rule for existing plants were filed in the D.C. Circuit Court by various parties and groups, including challenges from twenty-seven different states opposed to the rule as well as those from, among others, certain power generating companies, various business groups and some labor unions. Luminant also filed its own petition for review. In addition, several parties have filed motions to stay the implementation of the rule while the court reviews the legality of the rule for existing units. In January 2016, the D.C. Circuit Court denied the motion to stay and ordered an expedited briefing on the merits. Oral argument is scheduled for June 2016. In January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the US Supreme Court asking that the court stay the rule. In February 2016, the US Supreme Court stayed the rule pending the conclusion of legal challenges on the rule before the D.C. Circuit Court and until the US Supreme Court disposes of any subsequent petition for review. While we cannot predict the outcome of this rulemaking and legal proceedings on our results of operations, liquidity or financial condition, the impacts could be material.
In August 2015, the EPA proposed model rules and federal plan requirements for states to consider as they develop state plans to comply with the rules for GHG emissions. A federal plan would then be finalized for a state if a state fails to submit a state plan by the deadlines established in the CAA for existing plants or if the EPA disapproves a submitted state plan. We filed comments on the federal plan proposal in January 2016. The EPA is expected to finalize the model rule by the summer of 2016. While we cannot predict the outcome of this rulemaking and legal proceedings on our results of operations, liquidity or financial condition, the impacts could be material.
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Cross-State Air Pollution Rule (CSAPR)
In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions from our fossil fueled generation units. In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule. In June 2012, the EPA finalized the proposed rule (Second Revised Rule). As compared to the proposed revisions to the CSAPR issued by the EPA in October 2011, the Final Revisions and the Second Revised Rule finalize emissions budgets for our generation assets that are approximately 6% lower for SO2, 3% higher for annual NOx and 2% higher for seasonal NOx.
The CSAPR became effective January 1, 2015. In July 2015, following a remand of the case from the US Supreme Court to consider further legal challenges, the D.C. Circuit Court unanimously ruled in favor of us and other petitioners, holding that the CSAPR emissions budgets over-controlled Texas and other states. The D.C. Circuit Court remanded those states' budgets to the EPA for prompt reconsideration. While we planned to participate in the EPA's reconsideration process to develop increased budgets that do not over-control Texas, the EPA instead responded to the remand by updating the NOX ozone season budget for the 2008 ozone standard with a new rulemaking without explicitly addressing the issues of over-control of the 1997 standard. Comments on the EPA's proposal were submitted by Luminant in February 2016. While we cannot predict the outcome of future proceedings related to the CSAPR, including the EPA's reconsideration of the CSAPR annual emissions budgets for affected states, based upon our current operating plans we do not believe that the CSAPR will cause any material operational, financial or compliance issues.
Regional Haze
The Regional Haze Program of the CAA establishes "as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I federal areas, like national parks, which impairment results from man-made pollution." There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. Second, electricity generation units built between 1962 and 1977 are subject to best available retrofit technology (BART) standards designed to improve visibility. BART reductions of SO2 and NOX are required either on a unit-by-unit basis or are deemed satisfied by state participation in an EPA-approved regional trading program such as the CSAPR. In February 2009, the TCEQ submitted a State Implementation Plan (SIP) concerning regional haze (Regional Haze SIP) to the EPA. In December 2011, the EPA proposed a limited disapproval of the Regional Haze SIP due to its reliance on the Clean Air Interstate Rule (CAIR) instead of the EPA's replacement CSAPR program. In August 2012, we filed a petition for review in the Fifth Circuit Court challenging the EPA's limited disapproval of the Regional Haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court's decision in the CSAPR litigation. In September 2012, we filed a petition to intervene in a case filed by industry groups and other states and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance of a Federal Implementation Plan (FIP) regarding the regional haze BART program. The Fifth Circuit Court case has since been transferred to the D.C. Circuit Court and consolidated with other pending BART program regional haze appeals. No schedule has been set in the consolidated cases now in the D.C. Circuit Court.
In response to a lawsuit by environmental groups, the D.C. Circuit Court issued a consent decree in March 2012 that required the EPA to propose a decision on the Regional Haze SIP by May 2012 and finalize that decision by November 2012. The consent decree requires a FIP for any provisions that the EPA disapproves. The D.C. Circuit Court has amended the consent decree several times to extend the dates for the EPA to propose and finalize a decision on the Regional Haze SIP. The consent decree was modified in December 2015 to extend the deadline for the EPA to finalize action on the determination and adoption of requirements for BART for electricity generation. Under the amended consent decree the EPA has until December 2016 to finalize a FIP for BART for Texas electricity generation sources, if the EPA determines that BART requirements have not been met.
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In June 2014, the EPA issued requests for information under Section 114 of the CAA to Luminant and other generators in Texas. After releasing a proposed rule in November 2014 and receiving comments from a number of parties, including Luminant and the State of Texas in April 2015, the EPA released a final rule in January 2016 approving in part and disapproving in part Texas' SIP for Regional Haze and issuing a FIP for Regional Haze. In the rule, the EPA asserts that the Texas SIP does not show reasonable progress in improving visibility for two areas in Texas and that its long-term strategy fails to make emission reductions needed to achieve reasonable progress in improving visibility in the Wichita Mountains of Oklahoma. Unlike the proposed rule and inconsistent with how the EPA has applied Regional Haze rules to other states, the EPA's final rule does not treat Texas's compliance with the CSAPR as satisfying its obligations under the BART portion of the Regional Haze Program. The EPA concluded that it would not be appropriate to finalize that determination at this time given the remand of the CSAPR budgets. In our view, the EPA's proposed FIP for Texas goes beyond the requirements of the CSAPR and sets emission limits on a unit-by-unit basis for 15 electricity generation units in Texas. The EPA's proposed emission limits assume additional control equipment for specific coal fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven generation units and upgrades to existing scrubbers at seven generation units. Specifically for Luminant, the EPA's emission limitations are based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4. Luminant is continuing to evaluate the requirements and potential financial and operational impacts of the rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the FIP (if those limits are possible to attain), along with the existence of low wholesale power prices in ERCOT, would likely challenge the long-term economic viability of those units. The scrubber upgrades will be required by February 2019, and the new scrubbers will be required by February 2021. In March 2016, Luminant and a number of other parties, including the State of Texas, filed petitions for review in the US Fifth Circuit Court challenging the FIP on Texas. Luminant and other parties also filed motions to stay the FIP while the court reviews the legality of the EPA's action. While we cannot predict the outcome of the rulemaking and legal proceedings, the result may have a material impact on our results of operations, liquidity or financial condition.
State Implementation Plan (SIP)
In February 2013, in response to a petition for rulemaking filed by the Sierra Club, the EPA proposed a rule requiring certain states to replace SIP exemptions for excess emissions during malfunctions with an affirmative defense. Texas was not included in that original proposal since it already had an EPA-approved affirmative defense provision in its SIP. In 2014, as a result of a D.C. Circuit Court decision striking down an affirmative defense in another EPA rule, the EPA revised its 2013 proposal to extend the EPA's proposed findings of inadequacy to states that have affirmative defense provisions, including Texas. The EPA's revised proposal would require Texas to remove or replace its EPA-approved affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. In May 2015, the EPA finalized the proposal. In June 2015, we filed a petition for review in the Fifth Circuit Court challenging certain aspects of the EPA's final rule as they apply to the Texas SIP. The State of Texas and other parties have also filed similar petitions in the Fifth Circuit Court. In August 2015, the Fifth Circuit Court transferred the petitions that Luminant and other parties filed to the D.C. Circuit Court, and in October 2015 the petitions were consolidated with the pending petitions challenging the EPA's action in the D.C. Circuit Court. Briefing in the D.C. Circuit Court on the challenges is scheduled to be completed by October 2016. We cannot predict the timing or outcome of this proceeding.
In June 2014, the Sierra Club filed a petition in the D.C. Circuit Court seeking review of several EPA regulations containing affirmative defenses for malfunctions, including the Mercury and Air Toxics Standard (MATS) rule for power plants. In the petition, the Sierra Club contends this affirmative defense is no longer permissible in light of a D.C. Circuit Court decision regarding similar defenses applicable to the cement industry. Luminant filed a motion to intervene in this case. In July 2014, the D.C. Circuit Court ordered the case stayed pending the EPA's consideration of a petition for administrative reconsideration of the regulations at issue. In December 2014, the EPA signed a proposal to make technical corrections to the MATS rule. We filed comments on this proposal in April 2015. In March 2016, the EPA finalized the MATS technical corrections, including the removal of affirmative defense for malfunctions. Except as set forth above, we cannot predict the timing or outcome of future proceedings related to this petition, the petition for administrative reconsideration that is pending before the EPA or the financial effects of these proceedings, if any.
Other Matters
We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.
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13. | EQUITY |
EFH Corp. has not declared or paid any dividends since the Merger. The agreement governing the TCEH DIP Facility generally restricts TCEH's ability to make distributions or loans to any of its parent companies or their subsidiaries unless such distributions or loans are expressly permitted under the agreement governing such facility. The agreement governing the EFIH DIP Facility generally restricts EFIH's ability to make distributions or loans to any of its parent companies or their subsidiaries unless such distributions or loans are expressly permitted under the agreement governing such facility.
Under applicable law, we are prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent. In addition, due to the Chapter 11 Cases, no dividends are eligible to be paid without the approval of the Bankruptcy Court.
Equity
The following table presents the changes to equity for the three months ended March 31, 2016:
EFH Corp. Shareholders’ Equity | |||||||||||||||||||
Common Stock (a) | Additional Paid-in Capital | Retained Earnings (Deficit) | Accumulated Other Comprehensive Loss | Total Equity | |||||||||||||||
Balance at December 31, 2015 | $ | 2 | $ | 7,968 | $ | (32,905 | ) | $ | (126 | ) | $ | (25,061 | ) | ||||||
Net loss | — | — | (248 | ) | — | (248 | ) | ||||||||||||
Change in unrecognized losses related to pension and OPEB plans | — | — | — | (1 | ) | (1 | ) | ||||||||||||
Balance at March 31, 2016 | $ | 2 | $ | 7,968 | $ | (33,153 | ) | $ | (127 | ) | $ | (25,310 | ) | ||||||
________________
(a) | Authorized shares totaled 2,000,000,000 at March 31, 2016. Outstanding shares totaled 1,669,861,379 at both March 31, 2016 and December 31, 2015. |
The following table presents the changes to equity for the three months ended March 31, 2015:
EFH Corp. Shareholders’ Equity | |||||||||||||||||||
Common Stock (a) | Additional Paid-in Capital | Retained Earnings (Deficit) | Accumulated Other Comprehensive Loss | Total Equity | |||||||||||||||
Balance at December 31, 2014 | $ | 2 | $ | 7,968 | $ | (27,563 | ) | $ | (130 | ) | $ | (19,723 | ) | ||||||
Net loss | — | — | (1,527 | ) | — | (1,527 | ) | ||||||||||||
Change in unrecognized losses related to pension and OPEB plans | — | — | — | (2 | ) | (2 | ) | ||||||||||||
Net effects of cash flow hedges | — | — | — | 1 | 1 | ||||||||||||||
Net effects related to Oncor | — | — | — | 1 | 1 | ||||||||||||||
Balance at March 31, 2015 | $ | 2 | $ | 7,968 | $ | (29,090 | ) | $ | (130 | ) | $ | (21,250 | ) | ||||||
________________
(a) | Authorized shares totaled 2,000,000,000 at March 31, 2015. Outstanding shares totaled 1,669,861,379 at both March 31, 2015 and December 31, 2014. |
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Accumulated Other Comprehensive Loss
The following table presents the changes to accumulated other comprehensive income (loss) for the three months ended March 31, 2016. There was no other comprehensive income (loss) before reclassification for the period.
Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 15) | Pension and Other Postretirement Employee Benefit Liabilities Adjustments | Accumulated Other Comprehensive Income (Loss) | |||||||||
Balance at December 31, 2015 | $ | (50 | ) | $ | (76 | ) | $ | (126 | ) | ||
Amounts reclassified from accumulated other comprehensive loss and reported in: | |||||||||||
Operating costs | — | (1 | ) | (1 | ) | ||||||
Selling, general and administrative expenses | — | (1 | ) | (1 | ) | ||||||
Income tax benefit (expense) | — | 1 | 1 | ||||||||
Total amount reclassified from accumulated other comprehensive loss during the period | — | (1 | ) | (1 | ) | ||||||
Balance at March 31, 2016 | $ | (50 | ) | $ | (77 | ) | $ | (127 | ) | ||
The following table presents the changes to accumulated other comprehensive income (loss) for the three months ended March 31, 2015. There was no other comprehensive income (loss) before reclassification for the period.
Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 15) | Pension and Other Postretirement Employee Benefit Liabilities Adjustments | Accumulated Other Comprehensive Income (Loss) | |||||||||
Balance at December 31, 2014 | $ | (53 | ) | $ | (77 | ) | $ | (130 | ) | ||
Amounts reclassified from accumulated other comprehensive loss and reported in: | |||||||||||
Operating costs | — | (1 | ) | (1 | ) | ||||||
Depreciation and amortization | 1 | — | 1 | ||||||||
Selling, general and administrative expenses | — | (1 | ) | (1 | ) | ||||||
Equity in earnings of unconsolidated subsidiaries (net of tax) | 1 | — | 1 | ||||||||
Total amount reclassified from accumulated other comprehensive loss during the period | 2 | (2 | ) | — | |||||||
Balance at March 31, 2015 | $ | (51 | ) | $ | (79 | ) | $ | (130 | ) | ||
14. | FAIR VALUE MEASUREMENTS |
Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between willing market participants at the measurement date. We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.
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We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
• | Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange-traded commodity contracts. For example, some of our derivatives are NYMEX or ICE futures and swaps transacted through clearing brokers for which prices are actively quoted. |
• | Level 2 valuations use inputs that, in the absence of actively quoted market prices, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other mathematical means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available. |
• | Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives with values derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means. See further discussion below. |
Our valuation policies and procedures are developed, maintained and validated by a centralized risk management group that reports to the Chief Financial Officer, who also functions as the Chief Risk Officer. Risk management functions include commodity price reporting and validation, valuation model validation, risk analytics, risk control, credit risk management and risk reporting.
We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.
In utilizing broker quotes, we attempt to obtain multiple quotes from brokers (generally non-binding) that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other factors.
Probable loss from default by either us or our counterparties is considered in determining the fair value of derivative assets and liabilities. These non-performance risk adjustments take into consideration credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 15 for additional information regarding credit risk associated with our derivatives). We utilize published credit ratings and default rate factors in calculating these fair value measurement adjustments.
Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including, but not limited to, commodity prices, volatility factors, discount rates and other market based factors. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing locations and credit/non-performance risk assumptions. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.
The significant unobservable inputs and valuation models are developed by employees trained and experienced in market operations and fair value measurements and validated by the company's risk management group, which also further analyzes any significant changes in Level 3 measurements. Significant changes in the unobservable inputs could result in significant upward or downward changes in the fair value measurement.
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With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.
Assets and liabilities measured at fair value on a recurring basis consisted of the following:
March 31, 2016 | |||||||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | |||||||||||||||
Assets: | |||||||||||||||||||
Commodity contracts | $ | 407 | $ | 51 | $ | 55 | $ | 4 | $ | 517 | |||||||||
Nuclear decommissioning trust – equity securities (c) | 385 | — | — | — | 385 | ||||||||||||||
Nuclear decommissioning trust – debt securities (c) | — | 332 | — | — | 332 | ||||||||||||||
Sub-total | $ | 792 | $ | 383 | $ | 55 | $ | 4 | 1,234 | ||||||||||
Assets measured at net asset value (d): | |||||||||||||||||||
Nuclear decommissioning trust – equity securities (c) | 223 | ||||||||||||||||||
Total assets | $ | 1,457 | |||||||||||||||||
Liabilities: | |||||||||||||||||||
Commodity contracts | $ | 118 | $ | 121 | $ | 30 | $ | 4 | $ | 273 | |||||||||
Total liabilities | $ | 118 | $ | 121 | $ | 30 | $ | 4 | $ | 273 | |||||||||
December 31, 2015 | |||||||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | |||||||||||||||
Assets: | |||||||||||||||||||
Commodity contracts | $ | 385 | $ | 41 | $ | 49 | $ | — | $ | 475 | |||||||||
Nuclear decommissioning trust – equity securities (c) | 380 | 219 | — | — | 599 | ||||||||||||||
Nuclear decommissioning trust – debt securities (c) | — | 319 | — | — | 319 | ||||||||||||||
Total assets | $ | 765 | $ | 579 | $ | 49 | $ | — | $ | 1,393 | |||||||||
Liabilities: | |||||||||||||||||||
Commodity contracts | $ | 128 | $ | 64 | $ | 12 | $ | — | $ | 204 | |||||||||
Total liabilities | $ | 128 | $ | 64 | $ | 12 | $ | — | $ | 204 | |||||||||
____________
(a) | See table below for description of Level 3 assets and liabilities. |
(b) | Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in the condensed consolidated balance sheets. |
(c) | The nuclear decommissioning trust investment is included in the other investments line in the condensed consolidated balance sheets. See Note 18. |
(d) | Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. This presentation is only allowed for periods beginning after December 15, 2015. The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the condensed consolidated balance sheets. |
Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium and coal agreements and include financial instruments entered into for hedging purposes as well as physical contracts that have not been designated normal purchases or sales. See Note 15 for further discussion regarding derivative instruments.
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Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facility. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.
The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at March 31, 2016 and December 31, 2015:
March 31, 2016 | ||||||||||||||||||
Fair Value | ||||||||||||||||||
Contract Type (a) | Assets | Liabilities | Total | Valuation Technique | Significant Unobservable Input | Range (b) | ||||||||||||
Electricity purchases and sales | $ | 1 | $ | (4 | ) | $ | (3 | ) | Valuation Model | Hourly price curve shape (d) | $0 to $50/ MWh | |||||||
Electricity spread options | 13 | (23 | ) | (10 | ) | Option Pricing Model | Gas to power correlation (e) | 15% to 45% | ||||||||||
Power volatility (f) | 10% to 40% | |||||||||||||||||
Electricity congestion revenue rights | 36 | (3 | ) | 33 | Market Approach (g) | Illiquid price differences between settlement points (h) | $0 to $10/MWh | |||||||||||
Other (i) | 5 | — | 5 | |||||||||||||||
Total | $ | 55 | $ | (30 | ) | $ | 25 | |||||||||||
December 31, 2015 | ||||||||||||||||||
Fair Value | ||||||||||||||||||
Contract Type (a) | Assets | Liabilities | Total | Valuation Technique | Significant Unobservable Input | Range (b) | ||||||||||||
Electricity purchases and sales | $ | 1 | $ | (1 | ) | $ | — | Valuation Model | Illiquid pricing locations (c) | $15 to $35/ MWh | ||||||||
Hourly price curve shape (d) | $15 to $45/ MWh | |||||||||||||||||
Electricity spread options | 2 | (7 | ) | (5 | ) | Option Pricing Model | Gas to power correlation (e) | 35% to 80% | ||||||||||
Power volatility (f) | 10% to 35% | |||||||||||||||||
Electricity congestion revenue rights | 39 | (4 | ) | 35 | Market Approach (g) | Illiquid price differences between settlement points (h) | $0 to $10/MWh | |||||||||||
Other (i) | 7 | — | 7 | |||||||||||||||
Total | $ | 49 | $ | (12 | ) | $ | 37 | |||||||||||
____________
(a) | Electricity purchase and sales contracts include hedging positions in the ERCOT regions, as well as power contracts, the valuations of which include unobservable inputs related to the hourly shaping of the price curve. Electricity spread options contracts consist of physical electricity call options. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. |
(b) | The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. |
(c) | Based on the historical range of forward average monthly ERCOT hub and load zone prices. |
(d) | Based on the historical range of forward average hourly ERCOT North Hub prices. |
(e) | 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 insufficient market data to consider the valuation liquid. |
(h) | Based on the historical price differences between settlement points within the ERCOT hubs and load zones. |
(i) | Other includes contracts for coal purchases, ancillary services, natural gas, power options and coal options. |
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There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the three months ended March 31, 2016 and 2015. See the table of changes in fair values of Level 3 assets and liabilities below for discussion of transfers between Level 2 and Level 3 for the three months ended March 31, 2016 and 2015.
The following table presents the changes in fair value of the Level 3 assets and liabilities for the three months ended March 31, 2016 and 2015.
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Net asset balance at beginning of period | $ | 37 | $ | 35 | |||
Total unrealized valuation gains (losses) | (5 | ) | 16 | ||||
Purchases, issuances and settlements (a): | |||||||
Purchases | 14 | 19 | |||||
Issuances | (12 | ) | (3 | ) | |||
Settlements | (10 | ) | (8 | ) | |||
Transfers into Level 3 (b) | — | — | |||||
Transfers out of Level 3 (b) | 1 | 1 | |||||
Net change (c) | (12 | ) | 25 | ||||
Net asset balance at end of period | $ | 25 | $ | 60 | |||
Unrealized valuation gains (losses) relating to instruments held at end of period | $ | (4 | ) | $ | 15 | ||
____________
(a) | Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received. |
(b) | Includes transfers due to changes in the observability of significant inputs. Transfers in and out occur at the end of each quarter, which is when the assessments are performed. All Level 3 transfers during the periods presented are in and out of Level 2. |
(c) | Substantially all changes in values of commodity contracts are reported in the condensed statements of consolidated loss in net gain from commodity hedging and trading activities. Activity excludes changes in fair value in the month the positions settled as well as amounts related to positions entered into and settled in the same quarter. |
15. | COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES |
Strategic Use of Derivatives
We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price risk. Because certain of these instruments are deemed to be forward contracts under the Bankruptcy Code, they are not subject to the automatic stay, and counterparties may elect to terminate the agreements. Prior to the Petition Date, we had entered into interest rate swaps to manage our interest rate risk exposure. See Note 14 for a discussion of the fair value of derivatives.
Commodity Hedging and Trading Activity — TCEH has natural gas hedging positions designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity has generally moved with the price of natural gas. TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas through 2016 in order to hedge a portion of electricity price exposure related to expected lignite/coal and nuclear fueled generation. TCEH also enters into derivatives, including electricity, natural gas, fuel oil, uranium, emission and coal instruments, generally for short-term hedging purposes. Consistent with existing Bankruptcy Court orders, to a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets. Unrealized gains and losses arising from changes in the fair value of hedging and trading instruments as well as realized gains and losses upon settlement of the instruments are reported in the condensed statements of consolidated loss in net gain from commodity hedging and trading activities.
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Termination of Commodity Hedges and Interest Rate Swaps — Commodity hedges and interest rate swaps entered into prior to the Petition Date are deemed to be forward contracts under the Bankruptcy Code. The Bankruptcy Filing constituted an event of default under these arrangements, and in accordance with the contractual terms, counterparties terminated certain positions shortly after the Bankruptcy Filing. The positions terminated consisted almost entirely of natural gas hedging positions and interest rate swaps that were secured by a first-lien interest in the same assets of TCEH on a pari passu basis with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes.
Entities with a first-lien security interest included counterparties to both our natural gas hedging positions and interest rate swaps, which had entered into master agreements that provided for netting and setoff of amounts related to these positions. Additionally, certain counterparties to only our interest rate swaps hold the same first-lien security interest. The total net liability of $1.243 billion is subject to the terms of settlement of TCEH's first-lien claims ultimately approved by the Bankruptcy Court and is reported in the condensed consolidated balance sheets as a liability subject to compromise. Additionally, counterparties associated with the net liability are allowed, and have been receiving, adequate protection payments related to their claims as permitted by TCEH's cash collateral order approved by the Bankruptcy Court (see Note 8).
Financial Statement Effects of Derivatives
Substantially all derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in the condensed consolidated balance sheets at March 31, 2016 and December 31, 2015 (noncurrent assets and liabilities are reported in other noncurrent assets and other noncurrent liabilities and deferred credits, respectively). Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract. All amounts relate to commodity contracts.
March 31, 2016 | December 31, 2015 | ||||||||||||||||||||||
Derivative Assets | Derivative Liabilities | Total | Derivative Assets | Derivative Liabilities | Total | ||||||||||||||||||
Current assets | $ | 496 | $ | 3 | $ | 499 | $ | 465 | $ | — | $ | 465 | |||||||||||
Noncurrent assets | 18 | — | 18 | 10 | — | 10 | |||||||||||||||||
Current liabilities | — | (261 | ) | (261 | ) | — | (203 | ) | (203 | ) | |||||||||||||
Noncurrent liabilities | (1 | ) | (11 | ) | (12 | ) | — | (1 | ) | (1 | ) | ||||||||||||
Net assets (liabilities) | $ | 513 | $ | (269 | ) | $ | 244 | $ | 475 | $ | (204 | ) | $ | 271 | |||||||||
At March 31, 2016 and December 31, 2015, there were no derivative positions accounted for as cash flow or fair value hedges.
The pretax effect of derivatives on net income (loss), including realized and unrealized effects, totaled $56 million and $125 million in net gains in the three months ended March 31, 2016 and 2015, respectively, all of which related to commodity contracts reported in net gain from commodity and trading activities in the condensed statements of consolidated loss. Amounts represent changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.
The pretax effect (all losses) on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges was immaterial in both the three months ended March 31, 2016 and 2015. There were no amounts recognized in OCI for the three months ended March 31, 2016 and 2015.
Accumulated other comprehensive income related to cash flow hedges (excluding Oncor's interest rate hedges) at March 31, 2016 and December 31, 2015 totaled $34 million and $34 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps previously accounted for as cash flow hedges. We expect that $2 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income at March 31, 2016 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.
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Balance Sheet Presentation of Derivatives
Consistent with elections under US GAAP to present amounts on a gross basis, we report derivative assets and liabilities in the condensed consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. We may enter into offsetting positions with the same counterparty, resulting in both assets and liabilities. Volatility in underlying commodity prices can result in significant changes in assets and liabilities presented from period to period.
Margin deposits that contractually offset these derivative instruments are reported separately in the condensed consolidated balance sheets. Margin deposits received from counterparties are either used for working capital or other general corporate purposes or, if there are restrictions on the use of cash, amounts are deposited in a separate restricted cash account. At March 31, 2016 and December 31, 2015, essentially all margin deposits held were unrestricted.
We maintain standardized master netting agreements with certain counterparties that allow for the netting of positive and negative exposures. Generally, we utilize the International Swaps and Derivatives Association (ISDA) standardized contract for financial transactions, the Edison Electric Institute standardized contract for physical power transactions and the North American Energy Standards Board (NAESB) standardized contract for physical natural gas transactions. These contain credit enhancements that allow for the right to offset assets and liabilities and collateral received in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.
The following tables reconcile our derivative assets and liabilities as presented in the condensed consolidated balance sheets to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
March 31, 2016 | ||||||||||||||||
Amounts Presented in Balance Sheet | Offsetting Instruments (a) | Financial Collateral (Received) Pledged (b) | Net Amounts | |||||||||||||
Derivative assets: | ||||||||||||||||
Commodity contracts | $ | 517 | $ | (160 | ) | $ | (172 | ) | $ | 185 | ||||||
Derivative liabilities: | ||||||||||||||||
Commodity contracts | (273 | ) | 160 | 12 | (101 | ) | ||||||||||
Net amounts | $ | 244 | $ | — | $ | (160 | ) | $ | 84 | |||||||
December 31, 2015 | ||||||||||||||||
Amounts Presented in Balance Sheet | Offsetting Instruments (a) | Financial Collateral (Received) Pledged (b) | Net Amounts | |||||||||||||
Derivative assets: | ||||||||||||||||
Commodity contracts | $ | 475 | $ | (145 | ) | $ | (147 | ) | $ | 183 | ||||||
Derivative liabilities: | ||||||||||||||||
Commodity contracts | (204 | ) | 145 | 6 | (53 | ) | ||||||||||
Net amounts | $ | 271 | $ | — | $ | (141 | ) | $ | 130 | |||||||
____________
(a) | Amounts presented exclude trade accounts receivable and payable related to settled financial instruments. |
(b) | Financial collateral consists entirely of cash margin deposits. |
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Derivative Volumes
The following table presents the gross notional amounts of derivative volumes at March 31, 2016 and December 31, 2015:
March 31, 2016 | December 31, 2015 | |||||||
Derivative type | Notional Volume | Unit of Measure | ||||||
Natural gas (a) | 1,615 | 1,489 | Million MMBtu | |||||
Electricity | 67,261 | 58,022 | GWh | |||||
Congestion Revenue Rights (b) | 115,014 | 106,260 | GWh | |||||
Coal | 8 | 10 | Million US tons | |||||
Fuel oil | 32 | 35 | Million gallons | |||||
Uranium | 455 | 75 | Thousand pounds | |||||
____________
(a) | Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions. |
(b) | Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT. |
Credit Risk-Related Contingent Features of Derivatives
The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies; however, due to the Chapter 11 Cases, substantially all of such collateral posting requirements have already been effective.
At March 31, 2016 and December 31, 2015, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully collateralized totaled $111 million and $58 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with counterparties totaling $66 million and $31 million at March 31, 2016 and December 31, 2015, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross-default provisions, the remaining liquidity requirements would be immaterial at both March 31, 2016 and December 31, 2015.
In addition, certain derivative agreements include cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. At March 31, 2016 and December 31, 2015, the fair value of derivative liabilities subject to such cross-default provisions were immaterial.
As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $113 million and $59 million at March 31, 2016 and December 31, 2015, respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets subject to related liens.
Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.
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Concentrations of Credit Risk Related to Derivatives
We have concentrations of credit risk with the counterparties to our derivative contracts. At March 31, 2016, total credit risk exposure to all counterparties related to derivative contracts totaled $552 million (including associated accounts receivable). The net exposure to those counterparties totaled $187 million at March 31, 2016 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $104 million. At March 31, 2016, the credit risk exposure to the banking and financial sector represented 80% of the total credit risk exposure and 62% of the net exposure.
Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.
We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.
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16. | RELATED PARTY TRANSACTIONS |
The following represent our significant related-party transactions.
• | Previously, we accrued a management fee payable to the Sponsor Group under the terms of a management agreement. Related amounts expensed and reported as SG&A expense totaled $10 million for the three months ended March 31, 2015. No payments were made in the three months ended March 31, 2016 and 2015. We had previously paid these fees on a quarterly basis; however, beginning with the quarterly management fee due December 31, 2013, the Sponsor Group, while reserving the right to receive the fees, directed EFH Corp. to suspend payments of the management fees for an indefinite period. Effective with the Petition Date, EFH Corp. suspended allocations of such fees to TCEH and EFIH. Fees accrued as of the Petition Date were reclassified to LSTC, and fees accrued after the Petition Date were reported in other noncurrent liabilities and deferred credits. Pursuant to the Settlement Agreement approved by the Bankruptcy Court in December 2015, the Sponsor Group has agreed to forego any and all claims under the management agreement in exchange for releases of alleged liabilities against the Debtors. |
• | In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of each member of the Sponsor Group have from time to time engaged in commercial banking transactions with us and/or provided financial advisory services to us, in each case in the normal course of business. |
• | Affiliates of GS Capital Partners were parties to certain commodity and interest rate hedging transactions with us in the normal course of business. |
• | Affiliates of the Sponsor Group have sold or acquired, and in the future may sell or acquire, debt or debt securities issued by us in open market transactions or through loan syndications. |
• | TCEH's retail operations pay Oncor for services it provides, principally the delivery of electricity. Expenses recorded for these services, reported in fuel, purchased power costs and delivery fees, totaled $220 million and $236 million for the three months ended March 31, 2016 and 2015, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The condensed consolidated balance sheets at March 31, 2016 and December 31, 2015 reflect amounts due currently to Oncor totaling $101 million and $118 million, respectively (included in net payables due to unconsolidated subsidiary), largely related to these electricity delivery fees. Also see discussion below regarding receivables from Oncor under a Federal and State Income Tax Allocation Agreement. |
• | A subsidiary of EFH Corp. bills Oncor for financial and other administrative services and shared facilities at cost. Such amounts reduced reported SG&A expense by $1 million and $6 million for the three months ended March 31, 2016 and 2015, respectively. |
• | A subsidiary of EFH Corp. bills TCEH subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges totaled $60 million and $51 million for the three months ended March 31, 2016 and 2015, respectively. |
• | For the three months ended March 31, 2016, TCEH settled a $2 million payable related to information technology assets purchased from a subsidiary of EFH Corp. in December 2015. For the three months ended March 31, 2015, TCEH settled a $15 million payable related to information technology assets purchased from a subsidiary of EFH Corp. in 2014. 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 condensed consolidated balance sheets, will ultimately be sufficient to fund the future decommissioning liability, reported in noncurrent liabilities in our condensed consolidated balance sheets. The delivery fee surcharges remitted to TCEH totaled $4 million for both the three months ended March 31, 2016 and 2015. Income and expenses associated with the trust fund and the decommissioning liability incurred by TCEH are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates. At March 31, 2016 and December 31, 2015, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $424 million and $409 million, respectively, and is reported in noncurrent liabilities. |
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• | We file a consolidated federal income tax return that includes Oncor Holdings' results. Oncor is not a member of our consolidated tax group, but our consolidated federal income tax return includes our portion of Oncor's results due to our equity ownership in Oncor. We also file a consolidated Texas state margin tax return that includes all of Oncor Holdings' and Oncor's results. However, under a Federal and State Income Tax Allocation Agreement, Oncor Holdings' and Oncor's federal income tax and Texas margin tax expense and related balance sheet amounts, including our income taxes receivable from or payable to Oncor Holdings and Oncor, are recorded as if Oncor Holdings and Oncor file their own corporate income tax returns. |
• | At March 31, 2016, our net current amount payable to Oncor Holdings related to federal and state income taxes (reported in net payables due to unconsolidated subsidiary) totaled $78 million, $81 million of which related to Oncor. The $81 million net payable to Oncor included a $105 million federal income tax payable and a $24 million state margin tax receivable. Additionally, at March 31, 2016, we had a noncurrent tax payable to Oncor of $65 million recorded in other noncurrent liabilities and deferred credits and a noncurrent tax receivable from Oncor Holdings of $2 million recorded in other noncurrent assets. At December 31, 2015, our net current amount payable to Oncor Holdings related to federal and state income taxes totaled $87 million, $89 million of which related to Oncor. The $89 million net payable to Oncor included a $109 million federal income tax payable offset by a $20 million state margin tax receivable. Additionally, at December 31, 2015, we had a noncurrent tax payable to Oncor of $65 million recorded in other noncurrent liabilities and deferred credits and a noncurrent tax receivable from Oncor Holdings of $2 million recorded in other noncurrent assets. |
For the three months ended March 31, 2016, EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $5 million and zero, respectively. For the three months ended March 31, 2015, EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $6 million and zero, respectively.
• | Certain transmission and distribution utilities in Texas have requirements in place to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, as a result of TCEH's credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, at both March 31, 2016 and December 31, 2015, TCEH had posted letters of credit and/or cash in the amount of $6 million for the benefit of Oncor. |
• | In December 2012, Oncor became the sponsor of a new pension plan (the Oncor Plan), the participants in which consist of all of Oncor's active employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Oncor had previously contractually agreed to assume responsibility for pension liabilities that are recoverable by Oncor under regulatory rate-setting provisions. As part of the pension plan actions, EFH Corp. fully funded the non-recoverable pension liabilities under the Oncor Plan. After the pension plan actions, participants remaining in the EFH Corp. pension plan consist of active employees under collective bargaining agreements (union employees). Oncor continues to be responsible for the recoverable portion of pension obligations to these union employees. Under ERISA, EFH Corp. and Oncor remain jointly and severally liable for the funding of the EFH Corp. and Oncor pension plans. |
• | 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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17. | SEGMENT INFORMATION |
Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.
The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity operations for residential and business customers, all largely in the ERCOT market. These activities are conducted by TCEH.
The Regulated Delivery segment consists largely of our investment in Oncor. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary. See Note 4 for discussion of the reporting of Oncor Holdings and, accordingly, the Regulated Delivery segment, as an equity method investment. See Note 16 for discussion of material transactions with Oncor, including payment to Oncor of electricity delivery fees, which are based on rates regulated by the PUCT.
Corporate and Other represents the remaining non-segment operations consisting primarily of discontinued businesses, general corporate expenses and interest and other expenses related to EFH Corp., EFIH and EFCH.
The business segment results reflect the application of ASC 852, Reorganizations. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 to the Financial Statements in our 2015 Form 10-K. Our chief operating decision maker uses more than one measure to assess segment performance, including reported segment net income (loss), which is the measure most comparable to consolidated net loss prepared based on GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices or regulated rates. Certain shared services costs are allocated to the segments.
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Operating revenues (all Competitive Electric) | $ | 1,049 | $ | 1,272 | |||
Equity in earnings of unconsolidated subsidiaries (net of tax) — Regulated Delivery (net of noncontrolling interests of $16 and $20) | $ | 62 | $ | 75 | |||
Net income (loss): | |||||||
Competitive Electric | $ | (343 | ) | $ | (1,336 | ) | |
Regulated Delivery | 62 | 75 | |||||
Corporate and Other | 33 | (266 | ) | ||||
Consolidated net loss | $ | (248 | ) | $ | (1,527 | ) | |
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18. | SUPPLEMENTARY FINANCIAL INFORMATION |
Other Income and Deductions
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Other income: | |||||||
Office space rental income (a) | $ | 3 | $ | 3 | |||
Mineral rights royalty income (b) | 1 | 1 | |||||
All other | 1 | 4 | |||||
Total other income | $ | 5 | $ | 8 | |||
Other deductions: | |||||||
Write-off of generation equipment (b) | $ | 20 | $ | — | |||
Impairment of favorable purchase contracts (Note 5) (b) | — | 8 | |||||
Impairment of emission allowances (Note 5) (b) | — | 51 | |||||
All other | 1 | 1 | |||||
Total other deductions | $ | 21 | $ | 60 | |||
____________
(a) | Reported in Corporate and Other. |
(b) | Reported in Competitive Electric segment. |
Restricted Cash
March 31, 2016 | December 31, 2015 | ||||||||||||||
Current Assets | Noncurrent Assets | Current Assets | Noncurrent Assets | ||||||||||||
Amounts related to TCEH's DIP Facility (Note 10) | $ | 661 | $ | — | $ | 519 | $ | — | |||||||
Amounts related to TCEH's pre-petition Letter of Credit Facility (Note 11) | — | 507 | — | 507 | |||||||||||
Other | 5 | — | 5 | — | |||||||||||
Total restricted cash | $ | 666 | $ | 507 | $ | 524 | $ | 507 | |||||||
Trade Accounts Receivable
March 31, 2016 | December 31, 2015 | ||||||
Wholesale and retail trade accounts receivable | $ | 454 | $ | 542 | |||
Allowance for uncollectible accounts | (7 | ) | (9 | ) | |||
Trade accounts receivable — net | $ | 447 | $ | 533 | |||
Gross trade accounts receivable at March 31, 2016 and December 31, 2015 included unbilled revenues of $183 million and $231 million, respectively.
Allowance for Uncollectible Accounts Receivable
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Allowance for uncollectible accounts receivable at beginning of period | $ | 9 | $ | 15 | |||
Increase for bad debt expense | 5 | 9 | |||||
Decrease for account write-offs | (7 | ) | (9 | ) | |||
Allowance for uncollectible accounts receivable at end of period | $ | 7 | $ | 15 | |||
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Inventories by Major Category
March 31, 2016 | December 31, 2015 | ||||||
Materials and supplies | $ | 222 | $ | 226 | |||
Fuel stock | 196 | 170 | |||||
Natural gas in storage | 30 | 32 | |||||
Total inventories | $ | 448 | $ | 428 | |||
Other Investments
March 31, 2016 | December 31, 2015 | ||||||
Nuclear plant decommissioning trust | $ | 940 | $ | 918 | |||
Land | 36 | 36 | |||||
Miscellaneous other | 29 | 30 | |||||
Total other investments | $ | 1,005 | $ | 984 | |||
Nuclear Decommissioning Trust — Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor's customers as a delivery fee surcharge over the life of the plant and deposited by TCEH in the trust fund. Income and expense associated with the trust fund and the decommissioning liability are offset by a corresponding change in a receivable/payable (currently a payable reported in noncurrent liabilities) that will ultimately be settled through changes in Oncor's delivery fees rates (see Note 16). The nuclear decommissioning trust fund is not a debtor under the Chapter 11 Cases. A summary of investments in the fund follows:
March 31, 2016 | |||||||||||||||
Cost (a) | Unrealized gain | Unrealized loss | Fair market value | ||||||||||||
Debt securities (b) | $ | 315 | $ | 17 | $ | — | $ | 332 | |||||||
Equity securities (c) | 296 | 320 | (8 | ) | 608 | ||||||||||
Total | $ | 611 | $ | 337 | $ | (8 | ) | $ | 940 | ||||||
December 31, 2015 | |||||||||||||||
Cost (a) | Unrealized gain | Unrealized loss | Fair market value | ||||||||||||
Debt securities (b) | $ | 310 | $ | 11 | $ | (2 | ) | $ | 319 | ||||||
Equity securities (c) | 291 | 315 | (7 | ) | 599 | ||||||||||
Total | $ | 601 | $ | 326 | $ | (9 | ) | $ | 918 | ||||||
____________
(a) | Includes realized gains and losses on securities sold. |
(b) | The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's Investors Services, Inc. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 3.60% and 3.68% at March 31, 2016 and December 31, 2015, respectively, and an average maturity of 8 years at both March 31, 2016 and December 31, 2015. |
(c) | The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index. |
Debt securities held at March 31, 2016 mature as follows: $109 million in one to five years, $74 million in five to ten years and $149 million after ten years.
41
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Realized gains | $ | 1 | $ | — | |||
Realized losses | $ | (1 | ) | $ | (1 | ) | |
Proceeds from sales of securities | $ | 67 | $ | 23 | |||
Investments in securities | $ | (71 | ) | $ | (27 | ) | |
Property, Plant and Equipment
At March 31, 2016 and December 31, 2015, property, plant and equipment of $9.350 billion and $9.430 billion, respectively, is stated net of accumulated depreciation and amortization of $4.295 billion and $4.151 billion, respectively.
Asset Retirement and Mining Reclamation Obligations
These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of Oncor's delivery fees.
The following table summarizes the changes to these obligations, reported in other current liabilities and other noncurrent liabilities and deferred credits in the condensed consolidated balance sheets, for the three months ended March 31, 2016:
Nuclear Plant Decommissioning | Mining Land Reclamation | Other | Total | ||||||||||||
Liability at December 31, 2015 | $ | 508 | $ | 215 | $ | 107 | $ | 830 | |||||||
Additions: | |||||||||||||||
Accretion | 7 | 5 | 2 | 14 | |||||||||||
Incremental reclamation costs | — | 14 | 3 | 17 | |||||||||||
Reductions: | |||||||||||||||
Payments | — | (15 | ) | — | (15 | ) | |||||||||
Liability at March 31, 2016 | 515 | 219 | 112 | 846 | |||||||||||
Less amounts due currently | — | (60 | ) | — | (60 | ) | |||||||||
Noncurrent liability at March 31, 2016 | $ | 515 | $ | 159 | $ | 112 | $ | 786 | |||||||
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
March 31, 2016 | December 31, 2015 | ||||||
Uncertain tax positions, including accrued interest | $ | 40 | $ | 40 | |||
Retirement plan and other employee benefits | 170 | 169 | |||||
Asset retirement and mining reclamation obligations | 786 | 764 | |||||
Unfavorable purchase and sales contracts | 537 | 543 | |||||
Nuclear decommissioning fund excess over asset retirement obligation (Note 16) | 424 | 409 | |||||
Other | 116 | 108 | |||||
Total other noncurrent liabilities and deferred credits | $ | 2,073 | $ | 2,033 | |||
Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $6 million for both the three months ended March 31, 2016 and 2015. See Note 5 for intangible assets related to favorable purchase and sales contracts.
42
The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:
Year | Amount | |||
2016 | $ | 24 | ||
2017 | $ | 24 | ||
2018 | $ | 24 | ||
2019 | $ | 24 | ||
2020 | $ | 24 | ||
Fair Value of Debt
March 31, 2016 | December 31, 2015 | |||||||||||||||
Debt: | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Borrowings under debtor-in-possession credit facilities (Note 10) | $ | 6,825 | $ | 6,811 | $ | 6,825 | $ | 6,804 | ||||||||
Long-term debt not subject to compromise, excluding capital lease obligations (Note 10) | $ | 84 | $ | 82 | $ | 90 | $ | 89 | ||||||||
We determine fair value in accordance with accounting standards as discussed in Note 14, and at March 31, 2016, our debt fair value represents Level 2 valuations. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg. The fair value estimates of our pre-petition notes, loans and other debt reported as liabilities subject to compromise have been excluded from the table above. As a result of our ongoing Chapter 11 Cases, obtaining the fair value estimates of our pre-petition debt subject to compromise is impractical, and the fair values will ultimately be decided through the Chapter 11 Cases.
Supplemental Cash Flow Information
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Cash payments related to: | |||||||
Interest paid (a) | $ | 394 | $ | 671 | |||
Capitalized interest | (3 | ) | (3 | ) | |||
Interest paid (net of capitalized interest) (a) | $ | 391 | $ | 668 | |||
Reorganization items (b) | $ | 92 | $ | 89 | |||
Noncash investing and financing activities: | |||||||
Construction expenditures (c) | $ | 83 | $ | 65 | |||
____________
(a) | This amount includes amounts paid for adequate protection. |
(b) | Represents cash payments for legal and other consulting services, including amounts paid under the Merger and Purchase Agreement and the Backstop Agreement. |
(c) | Represents end-of-period accruals for ongoing construction projects. |
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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 months ended March 31, 2016 and 2015 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements. Results are impacted by the effects of the Bankruptcy Filing and the application of Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, Reorganizations.
All dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwise indicated.
Business
EFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through its TCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management, and retail electricity operations. TCEH is a wholly owned subsidiary of EFCH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Oncor Holdings, a holding company that holds an approximately 80% equity interest in Oncor, is a wholly owned subsidiary of EFIH, which is a holding company and a wholly owned subsidiary of EFH Corp.
Various ring-fencing measures have been taken to enhance the credit quality of Oncor. See Notes 1 and 4 to the Financial Statements for a discussion of the reporting of our investment in Oncor (and Oncor Holdings) as an equity method investment and a description of the ring-fencing measures implemented with respect to Oncor. These measures were put in place to mitigate Oncor's exposure to the Texas Holdings Group with the intent to minimize the risk that a court would order any of the assets and liabilities of the Oncor Ring-Fenced Entities to be substantively consolidated with those of any member of the Texas Holdings Group in the event any such member were to become a debtor in a bankruptcy case. Consistent with these ring-fencing measures, the assets and liabilities of the Oncor Ring-Fenced Entities have not been, and are not expected to be, substantively consolidated with the assets and liabilities of the Debtors in the Chapter 11 Cases.
Operating Segments
Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The Competitive Electric segment consists largely of TCEH. The Regulated Delivery segment consists largely of our investment in Oncor.
See Note 17 to the Financial Statements for further information regarding reportable business segments.
Significant Activities and Events and Items Influencing Future Performance
Filing under Chapter 11 of the United States Bankruptcy Code — On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, (the Debtors) filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). During the pendency of the Bankruptcy Filing (the Chapter 11 Cases), the Debtors have operated and will continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.
For additional discussion of the Bankruptcy Filing and its effects, see Note 2 to the Financial Statements.
44
La Frontera Combined Cycle Gas Turbines (CCGTs) — In April 2016, Luminant purchased all of the membership interests in La Frontera Holdings, LLC, the indirect owner of two natural gas fueled generation facilities representing nearly 3,000 MW of capacity located in ERCOT, from La Frontera Ventures, LLC, a subsidiary of NextEra Energy, Inc. The facility in Forney, Texas has a capacity of 1,912 MW and the facility in Paris, Texas has a capacity of 1,076 MW. The aggregate purchase price under the agreement was approximately $1.313 billion, which included the repayment of approximately $950 million of existing project financing indebtedness of La Frontera Holdings, LLC and its subsidiaries at the closing of the transaction, plus approximately $240 million for cash and net working capital subject to final settlement. The purchase price was funded by cash-on-hand and additional borrowings under the TCEH DIP Facility totaling $1.1 billion.
Extension of EFIH DIP Facility — In January 2016, the EFIH Debtors paid a $14 million extension fee and extended the maturity date of the EFIH DIP Facility to the earlier of (a) December 2016 or (b) the effective date of any reorganization plan of EFIH. The terms of the facility were otherwise unchanged by the extension. See Note 10 to the Financial Statements for discussion of the DIP Facilities.
Overall Hedged Generation Position — Taking together forward wholesale and retail electricity sales with all hedging positions, at March 31, 2016 we had effectively hedged an estimated 96% and 16%, respectively, of the price exposure, on a natural gas equivalent basis, related to our expected generation output for the remainder of 2016 and 2017 (assuming an 8.5 market heat rate), as compared to 94% and 18%, respectively, at December 31, 2015. The majority of our third-party hedges are financial natural gas instruments.
Commodity Price Sensitivities — The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas prices and market heat rates on realized pretax earnings for the periods presented. The estimates related to price sensitivity are based on our unhedged position and forward prices at March 31, 2016, which for natural gas reflects estimates of electricity generation less amounts under existing wholesale and retail sales contracts and amounts related to hedging positions. On a rolling basis, generally twelve-months, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.
Balance 2016 | 2017 | ||
$1.00/MMBtu change in natural gas price (a)(b) | $ ~13 | $ ~350 | |
0.1/MMBtu/MWh change in market heat rate (c) | $ — | $ ~10 | |
___________
(a) | Balance of 2016 is from May 1, 2016 through December 31, 2016. |
(b) | Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally being on the margin 70% to 90% of the time in the ERCOT market (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated). Excludes the impact of economic backdown. |
(c) | Based on Houston Ship Channel natural gas prices at March 31, 2016. |
Environmental Matters — See Note 12 to Financial Statements for a discussion of greenhouse gas emissions, the CSAPR, regional haze, state-implementation plan and other recent EPA actions as well as related litigation.
45
Oncor Matters with the PUCT — Change in Control Review (PUCT Docket No. 45188) — In March 2016, the PUCT approved the acquisition of Reorganized EFH contemplated by the Merger and Purchase Agreement. The order approving the acquisition is subject to a number of material conditions and commitments. In April 2016, prior to the termination of the Merger and Purchase Agreement, the Investor Group requested a rehearing by the PUCT with respect to certain conditions and commitments set forth in the PUCT's final order. The PUCT will consider the Investor Group’s request for a rehearing later in May 2016. We cannot predict the outcome of this request.
2008 Rate Review Filing (PUCT Docket No. 35717) — In August 2009, the PUCT issued a final order with respect to Oncor's June 2008 rate review filing with the PUCT and 204 cities based on a test year ended December 31, 2007, and new rates were implemented in September 2009. Oncor and four other parties appealed various portions of the rate review final order to a state district court. In January 2011, the district court signed its judgment reversing the PUCT with respect to two issues: the PUCT's disallowance of certain franchise fees and the PUCT's decision that the Texas Public Utility Regulatory Act (PURA) no longer requires imposition of a rate discount for state colleges and universities. Oncor filed an appeal with the Texas Third Court of Appeals (Austin Court of Appeals) in February 2011 with respect to the issues it appealed to the district court and did not prevail upon, as well as the district court's decision to reverse the PUCT with respect to discounts for state colleges and universities. In August 2014, the Austin Court of Appeals reversed the district court and affirmed the PUCT with respect to the PUCT's disallowance of certain franchise fees and the PUCT's decision that PURA no longer requires imposition of a rate discount for state colleges and universities. The Austin Court of Appeals also reversed the PUCT and district court's rejection of a proposed consolidated tax savings adjustment arising out of EFH Corp.'s ability to offset Oncor's taxable income against losses from other investments and remanded the issue to the PUCT to determine the amount of the consolidated tax savings adjustment. Oncor filed a motion on rehearing with the Austin Court of Appeals with respect to certain appeal issues on which Oncor was not successful, including the consolidated tax savings adjustment. In December 2014, the Austin Court of Appeals issued its opinion, clarifying that it was rendering judgment on the rate discount for state colleges and universities issue (affirming that PURA no longer requires imposition of the rate discount) rather than remanding it to the PUCT, and dismissing the motions for rehearing regarding the franchise fee issue and the consolidated tax savings adjustment. Oncor filed a petition for review with the Texas Supreme Court in February 2015. In February 2016, the Texas Supreme Court granted the petition for review, with the date and time of oral arguments to be set at a later date. There is no deadline for the court to act. If Oncor's appeals efforts are unsuccessful and the proposed consolidated tax savings adjustment is implemented, Oncor estimates that on remand the impact on earnings of the consolidated tax savings adjustment's value could range from zero, as originally determined by the PUCT in Docket No. 35717, to a $135 million loss (after-tax) including interest. Interest accrues at the PUCT approved rate for over-collections, which is 0.18% for 2016. Oncor does not believe that any of the other issues ruled upon by the Austin Court of Appeals would result in a material impact to its results of operations or financial condition.
Transmission Cost Recovery and Rates — In order to reflect increases or decreases in its wholesale transmission costs, including fees it pays to other transmission service providers, PUCT rules allow Oncor to update the transmission cost recovery factor (TCRF) component of its retail delivery rates charged to REPs on March 1 and September 1 each year. The table below lists TCRF filings impacting Oncor's cash flows for the three months ended March 31, 2016 and 2015, as well as filings that will impact Oncor's cash flows for the year ended December 31, 2016.
Docket No. | Filed | Effective | Semi-Annual Billing Impact Increase (Decrease) | |||||
45406 | December 2015 | March 2016 – August 2016 | $ | (64 | ) | |||
44771 | May 2015 | September 2015 – February 2016 | $ | 47 | ||||
43858 | December 2014 | March 2015 – August 2015 | $ | (27 | ) | |||
42558 | May 2014 | September 2014 – February 2015 | $ | 71 | ||||
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RESULTS OF OPERATIONS
Consolidated Financial Results — Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015
Net income (loss) by segment for the three months ended March 31, 2016 and 2015 is presented below:
Three Months Ended March 31, | |||||||||||
2016 | 2015 | $ Change | |||||||||
Competitive Electric segment | $ | (343 | ) | $ | (1,336 | ) | $ | 993 | |||
Regulated Delivery segment | 62 | 75 | (13 | ) | |||||||
Corporate and Other | 33 | (266 | ) | 299 | |||||||
EFH Corp. consolidated | $ | (248 | ) | $ | (1,527 | ) | $ | 1,279 | |||
Consolidated net loss for EFH Corp. decreased by $1.279 billion to $248 million in 2016. The decrease primarily reflected the noncash impairments of goodwill in 2015 and the noncash impairments of certain long-lived assets in 2015. In 2015, a noncash impairment of goodwill totaling $700 million and noncash impairments of certain long-lived assets totaling $676 million were recorded.
See Competitive Electric Segment – Financial Results below for a discussion of significant variances in financial results for the three months ended March 31, 2016 when compared to the three months ended March 31, 2015. See Note 18 to the Financial Statements for details of other income and deductions. See Note 8 to the Financial Statements for details of interest expense and related charges. See Note 9 to the Financial Statements for details of reorganization items. See Note 6 to the Financial Statements for reconciliation of comparable effective tax rates to the US federal statutory rate.
47
Competitive Electric Segment
Revenue, Sales Volume and Customer Count Data
Three Months Ended March 31, | % Change | |||||||||
2016 | 2015 | |||||||||
Operating revenues: | ||||||||||
Retail electricity revenues: | ||||||||||
Residential | $ | 553 | $ | 691 | (20.0 | )% | ||||
Business markets | 324 | 362 | (10.5 | )% | ||||||
Total retail electricity revenues | 877 | 1,053 | (16.7 | )% | ||||||
Wholesale electricity revenues (a)(b) | 118 | 148 | (20.3 | )% | ||||||
Other operating revenues | 54 | 71 | (23.9 | )% | ||||||
Total operating revenues | $ | 1,049 | $ | 1,272 | (17.5 | )% | ||||
Sales volumes: | ||||||||||
Retail electricity sales volumes – (GWh): | ||||||||||
Residential | 4,228 | 5,107 | (17.2 | )% | ||||||
Business markets | 4,220 | 4,364 | (3.3 | )% | ||||||
Total retail electricity | 8,448 | 9,471 | (10.8 | )% | ||||||
Wholesale electricity sales volumes (b) | 5,455 | 5,370 | 1.6 | % | ||||||
Total sales volumes | 13,903 | 14,841 | (6.3 | )% | ||||||
Weather (North Texas average) – percent of normal (c): | ||||||||||
Heating degree days | 81.6 | % | 120.0 | % | (32.0 | )% | ||||
Retail customer counts: | ||||||||||
Retail electricity customers (end of period, in thousands) (d): | ||||||||||
Residential | 1,486 | 1,503 | (1.1 | )% | ||||||
Business markets | 197 | 202 | (2.5 | )% | ||||||
Total retail electricity customers | 1,683 | 1,705 | (1.3 | )% | ||||||
____________
(a) | Upon settlement of physical derivative commodity contracts that we mark-to-market in net income, such as certain electricity sales and purchase agreements and coal purchase contracts, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, rather than contract price. The offsetting differences between contract and market prices are reported in net gain from commodity hedging and trading activities. |
(b) | Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market. |
(c) | Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over the 10-year period from 2000 to 2010. |
(d) | Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers. |
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Competitive Electric Segment
Production, Purchased Power and Delivery Cost Data
Three Months Ended March 31, | % Change | |||||||||
2016 | 2015 | |||||||||
Fuel, purchased power costs and delivery fees ($ millions): | ||||||||||
Fuel for nuclear facilities | $ | 35 | $ | 38 | (7.9 | )% | ||||
Fuel for lignite/coal facilities | 141 | 141 | — | % | ||||||
Total nuclear and lignite/coal facilities (a) | 176 | 179 | (1.7 | )% | ||||||
Fuel for natural gas facilities and purchased power costs (a) | 48 | 62 | (22.6 | )% | ||||||
Other costs | 35 | 42 | (16.7 | )% | ||||||
Fuel and purchased power costs | 259 | 283 | (8.5 | )% | ||||||
Delivery fees | 295 | 330 | (10.6 | )% | ||||||
Total | $ | 554 | $ | 613 | (9.6 | )% | ||||
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh: | ||||||||||
Nuclear facilities | $ | 6.48 | $ | 7.25 | (10.6 | )% | ||||
Lignite/coal facilities (b) | $ | 20.46 | $ | 20.49 | (0.1 | )% | ||||
Natural gas facilities and purchased power (c) | $ | 42.07 | $ | 45.85 | (8.2 | )% | ||||
Delivery fees per MWh | $ | 34.71 | $ | 34.71 | — | % | ||||
Production and purchased power volumes (GWh): | ||||||||||
Nuclear facilities | 5,322 | 5,283 | 0.7 | % | ||||||
Lignite/coal facilities (d) | 7,982 | 8,797 | (9.3 | )% | ||||||
Total nuclear and lignite/coal facilities | 13,304 | 14,080 | (5.5 | )% | ||||||
Natural gas facilities | 26 | 60 | (56.7 | )% | ||||||
Purchased power (e) | 573 | 701 | (18.3 | )% | ||||||
Total energy supply volumes | 13,903 | 14,841 | (6.3 | )% | ||||||
Capacity factors: | ||||||||||
Nuclear facilities | 106.0 | % | 106.4 | % | (0.4 | )% | ||||
Lignite/coal facilities (d) | 45.6 | % | 50.8 | % | (10.2 | )% | ||||
Total | 59.1 | % | 63.2 | % | (6.5 | )% | ||||
____________
(a) | See note (a) to the Revenue, Sales Volume and Customer Count Data table on previous page. |
(b) | Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs and excludes unrealized amounts as discussed in footnote (a) to the Revenue, Sales Volume and Customer Count Data table on the previous page. |
(c) | Excludes volumes related to line loss and power imbalances and unrealized amounts referenced in footnote (a) to the Revenue, Sales Volume and Customer Count Data table on previous page. |
(d) | Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal fueled units totaling 6,720 GWh and 7,150 GWh for the three months ended March 31, 2016 and 2015, respectively. |
(e) | Includes amounts related to line loss and power imbalances. |
49
Competitive Electric Segment — Financial Results — Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015
The overall $1.291 billion decrease in loss before income taxes primarily reflected the noncash impairment of goodwill in 2015 and the noncash impairments of certain long-lived assets in 2015, partially offset by lower operating revenues. In 2015, a noncash impairment of goodwill totaling $700 million and noncash impairments of certain long-lived assets totaling $676 million were recorded as discussed in Notes 5 and 7 to the Financial Statements.
Operating revenues decreased $223 million predominantly due to decreases in retail electricity revenues. Retail electricity revenues decreased $176 million in 2016. $114 million of the decrease was primarily due to an 11% reduction in retail electricity volumes reflecting the effect of milder weather on the residential market. As noted above in Revenue, Sales Volume and Customer Count Data heating degree days were down 32% from 2015 to 2016. $62 million of the decrease was due to a 7% overall average pricing decline in residential and business markets.
Following is an analysis of amounts reported as net gain from commodity hedging and trading activities. Results are primarily related to natural gas and power hedging activity.
Three Months Ended March 31, | |||||||||||
Net gain from commodity hedging and trading activities | 2016 | 2015 | Change | ||||||||
Realized net gains (losses) | $ | 104 | $ | (1 | ) | $ | 105 | ||||
Unrealized net gains (losses) | (40 | ) | 104 | (144 | ) | ||||||
Total | $ | 64 | $ | 103 | $ | (39 | ) | ||||
Decreases in revenues were partially offset by a $105 million increase in realized gains during 2016 which reflected settled gains due to declining market prices. These gains were primarily related to natural gas positions.
The $144 million decrease in net unrealized gains (losses) reflected a larger reversal of previously recorded net unrealized gains on settled positions in 2016 and higher net unrealized gains recorded in 2015 due to the decline in forward power prices.
The $59 million decrease in fuel, purchased power costs and delivery fees in 2016 was driven by a $35 million decrease in delivery fees and a $14 million decrease in fuel for natural gas facilities and purchased power costs.
The $26 million increase in operating costs was driven by timing and scope of maintenance costs at lignite/coal fueled generation facilities. Depreciation and amortization expenses decreased $76 million, driven by the effect of noncash impairments of certain long-lived assets recorded in 2015.
50
Competitive Electric Segment — Energy-Related Commodity Contracts and Mark-to-Market Activities
The table below summarizes the changes in commodity contract assets and liabilities for the three months ended March 31, 2016 and 2015. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $40 million in unrealized net losses in 2016 and $101 million in unrealized net gains in 2015 arising from mark-to-market accounting for positions in the commodity contract portfolio.
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Commodity contract net asset at beginning of period | $ | 271 | $ | 180 | |||
Settlements/termination of positions (a) | (96 | ) | (24 | ) | |||
Changes in fair value of positions in the portfolio (b) | 56 | 125 | |||||
Other activity (c) | 13 | (1 | ) | ||||
Commodity contract net asset at end of period | $ | 244 | $ | 280 | |||
____________
(a) | Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month. |
(b) | Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month. |
(c) | These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold. |
Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values at March 31, 2016, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
Maturity dates of unrealized commodity contract net asset at March 31, 2016 | ||||||||||||||||
Source of fair value | Less than 1 year | 1-3 years | 4-5 years | Total | ||||||||||||
Prices actively quoted | $ | 287 | $ | 2 | $ | — | $ | 289 | ||||||||
Prices provided by other external sources | (66 | ) | (4 | ) | — | (70 | ) | |||||||||
Prices based on models | 14 | 10 | 1 | 25 | ||||||||||||
Total | $ | 235 | $ | 8 | $ | 1 | $ | 244 | ||||||||
Regulated Delivery Segment — Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015
Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) decreased $13 million to $62 million in 2016. The decrease in equity earnings of Oncor primarily reflected lower distribution base revenues driven by milder weather conditions, partially offset by lower operations and maintenance expenses and lower income taxes. See Note 4 to the Financial Statements.
Corporate and Other Activity — Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015
After-tax net income from Corporate and Other activities totaled $33 million in 2016 compared to a net loss of $266 million in 2015. The change primarily reflects:
• | a $235 million decrease in interest expense reflecting the payment of post-petition interest related to the EFIH Second Lien Notes in 2015 (see Note 11 to the Financial Statements); |
• | a $24 million decrease in SG&A expenses primarily due to lower service costs and technology costs, and |
• | a $17 million decrease in Corporate and Other portion of reorganization items in 2016. |
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FINANCIAL CONDITION
Cash Flows — Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015 — Cash used in operating activities totaled $270 million and $407 million in 2016 and 2015, respectively. The decrease in cash used of $137 million was primarily driven by $277 million in lower cash interest payments as a result of the repayment on the EFIH Second Lien Notes in 2015 (see Note 11 to the Financial Statements), partially offset by a $62 million decrease in cash provided for margin deposits and $34 million in lower distributions from Oncor Holdings.
Depreciation and amortization expense reported in the condensed statements of consolidated cash flows exceeded the amount reported in the condensed statements of consolidated loss by $29 million and $36 million for the three months ended March 31, 2016 and 2015, respectively. The difference primarily represents amortization of nuclear fuel, which is reported as fuel costs in the condensed statements of consolidated loss consistent with industry practice.
Cash used in financing activities totaled $26 million and $483 million in 2016 and 2015, respectively. Activity in 2016 reflected $14 million in fees related to the extension of the EFIH DIP Facility and $12 million in debt repayments. Activity in 2015 reflected the repayment of $445 million principal amount of EFIH Second Lien Notes and $28 million in fees related to the repayment (see Note 11 to the Financial Statements).
Cash used in investing activities totaled $237 million and $101 million in 2016 and 2015, respectively. Cash used in 2016 reflected capital expenditures (including nuclear fuel purchases) totaling $93 million and a net use of restricted cash totaling $142 million. Cash used in 2015 reflected capital expenditures (including nuclear fuel purchases) totaling $126 million, partially offset by $25 million in restricted cash released from an escrow account when certain letters of credit were drawn.
Debt Activity — See Notes 10 and 11 to the Financial Statements for details of debtor-in-possession borrowing facilities and pre-petition debt.
Available Liquidity — The following table summarizes changes in available liquidity for the three months ended March 31, 2016:
Available Liquidity | |||||||||||
March 31, 2016 | December 31, 2015 | Change | |||||||||
Cash and cash equivalents – EFH Corp. and other | $ | 485 | $ | 532 | $ | (47 | ) | ||||
Cash and cash equivalents – EFIH | 300 | 354 | (54 | ) | |||||||
Cash and cash equivalents – TCEH (a) | 968 | 1,400 | (432 | ) | |||||||
Total cash and cash equivalents | 1,753 | 2,286 | (533 | ) | |||||||
TCEH DIP Revolving Credit Facility (b) | 1,950 | 1,950 | — | ||||||||
Total liquidity (b) | $ | 3,703 | $ | 4,236 | $ | (533 | ) | ||||
___________
(a) | Cash and cash equivalents at March 31, 2016 and December 31, 2015 exclude $1.168 billion and $1.026 billion, respectively, of restricted cash held for letter of credit support. The March 31, 2016 restricted cash balance includes $507 million under the TCEH pre-petition Letter of Credit Facility and $661 million under the TCEH DIP Facility. |
(b) | Pursuant to an order of the Bankruptcy Court, the TCEH Debtors may not have more than $1.650 billion of cash borrowings outstanding under the TCEH DIP Revolving Credit Facility without written consent of the TCEH committee of unsecured creditors and the ad hoc group of TCEH unsecured noteholders or further order of the Bankruptcy Court. |
The decrease in available liquidity of $533 million in the three months ended March 31, 2016 compared to December 31, 2015 was primarily driven by $394 million in cash interest payments (including adequate protection payments), $92 million of cash used to pay for reorganization expenses and $93 million in capital expenditures (including nuclear fuel purchases), partially offset by $40 million of cash received from the distribution by Oncor Holdings.
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In April 2016, Luminant purchased all of the membership interests in La Frontera Holdings, LLC, the indirect owner of two natural gas fueled generation facilities representing nearly 3,000 MW of capacity located in ERCOT, from La Frontera Ventures, LLC, a subsidiary of NextEra Energy, Inc. The aggregate purchase price under the agreement was approximately $1.313 billion, which included the repayment of approximately $950 million of existing project financing indebtedness of La Frontera Holdings, LLC and its subsidiaries at the closing of the transaction, plus approximately $240 million for cash and net working capital subject to final settlement. The purchase price was funded by cash-on-hand and additional borrowings under the TCEH DIP Facility totaling $1.1 billion. After completing the acquisition, we repaid approximately $230 million of borrowings under the TCEH DIP Facility utilizing cash acquired in the transaction.
We have incurred and expect to continue to incur significant costs associated with the Chapter 11 Cases and our reorganization, but we cannot accurately predict the effect the Chapter 11 Cases will have on our operations, liquidity, financial position and results of operations. Based upon our current internal financial forecasts, we believe that we will have sufficient amounts available under the DIP Facilities, plus cash generated from operations, to fund our anticipated cash requirements through at least the maturity dates of the DIP Facilities.
Debt Capacity — The TCEH DIP Facility permits, subject to certain terms, conditions and limitations, TCEH to request additional term loans or increases in the amount of the revolving credit commitment, not to exceed $750 million. The EFIH DIP Facility permits, subject to certain terms, conditions and limitations, EFIH to incur incremental junior lien subordinated debt in an aggregate amount not to exceed $3 billion.
Distributions of Earnings from Oncor Holdings and Related Considerations — Oncor Holdings' distributions of earnings to us totaled $40 million and $74 million for the three months ended March 31, 2016 and 2015, respectively. In April 2016, Oncor Holdings' board of directors declared a cash distribution expected to be up to approximately $46 million with the exact amount to be determined by Oncor's management. See Note 4 to the Financial Statements for discussion of limitations on amounts Oncor can distribute to its members.
EFH Corp., Oncor Holdings, Oncor and Oncor's minority investor are parties to a Federal and State Income Tax Allocation Agreement. Additional income tax amounts receivable or payable may arise in the normal course under that agreement.
Liquidity Effects of Commodity Hedging and Trading Activities — We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. TCEH uses cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 10 to the Financial Statements for discussion of the TCEH DIP Facility.
Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variation margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other corporate purposes, including reducing borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. At March 31, 2016, essentially all cash collateral held was unrestricted. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted.
At March 31, 2016, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:
• | $13 million in cash has been posted with counterparties as compared to $6 million posted at December 31, 2015; |
• | $176 million in cash has been received from counterparties as compared to $152 million received at December 31, 2015; |
• | $377 million in letters of credit have been posted with counterparties (including certain credit posted related to the anticipated closing of the La Frontera acquisition) as compared to $230 million posted at December 31, 2015, and |
• | $5 million in letters of credit have been received from counterparties as compared to $3 million received at December 31, 2015. |
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Income Tax Matters — EFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. EFH Corp. (parent entity) is a corporate member of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH is classified as a disregarded entity for US federal income tax purposes. Oncor is a partnership for US federal income tax purposes and is not a corporate member of the EFH Corp. consolidated group. Pursuant to applicable US Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.
EFH Corp. and certain of its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) are parties to a Federal and State Income Tax Allocation Agreement, which provides, among other things, that any corporate member or disregarded entity in the EFH Corp. group is required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. The Plan of Reorganization provides that the Debtors will reject this agreement at the effective time of the Plan of Reorganization. Under the terms of the Settlement Agreement, no further cash payments among the Debtors will be made in respect of federal income taxes. However, the EFH Corp. group continues to allocate federal income taxes among the entities that are parties to the Federal and State Income Tax Allocation Agreement. The Settlement Agreement did not alter the allocation and payment for state income taxes, which will continue to be settled.
EFH Corp., Oncor Holdings, Oncor and Oncor's third-party minority investors are parties to a separate Federal and State Income Tax Allocation Agreement, which governs the computation of federal income tax liability among such parties, and similarly provides, among other things, that each of Oncor Holdings and Oncor will pay EFH Corp. its share of an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. The Settlement Agreement had no impact on the tax sharing agreement among EFH Corp., Oncor Holdings and Oncor.
Income Tax Payments — In the next twelve months, income tax payments related to Texas margin tax are expected to total approximately $20 million, and no payments or refunds of federal income taxes are expected. There were no material income tax payments for the three months ended March 31, 2016 and 2015.
Financial Covenants — The Bankruptcy Filing constituted an event of default and automatic acceleration under the agreements governing the pre-petition debt of EFH Corp. and its subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities. The creditors are, however, stayed from taking any action against the Debtors as a result of such defaults and accelerations under the Bankruptcy Code.
The agreement governing the TCEH DIP Facility includes a covenant that requires the Consolidated Superpriority Secured Net Debt to Consolidated EBITDA ratio not exceed 3.50 to 1.00. The ratio was 1.64 to 1.00 at March 31, 2016, and TCEH is in compliance with this covenant. Consolidated Superpriority Secured Net Debt consists of outstanding term loans and revolving credit exposure under the TCEH DIP Facility less unrestricted cash. TCEH's Consolidated EBITDA (as used in the covenant contained in the agreement governing the TCEH DIP Facility) for the three and twelve months ended March 31, 2016 totaled $298 million and $1.546 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. In the event that EFIH is unable to refinance or extend the EFIH DIP Facility prior to its maturity in December 2016, based on the current and projected liquidity requirements of EFIH, EFIH's liquidity may fall beneath the amount required by the minimum liquidity covenant in the EFIH DIP Facility, and if this were to occur, it would be in default of the EFIH DIP Facility unless it obtains a waiver from the required lenders under such facility. However, such a default would not constitute a cross default under the TCEH DIP Facility.
See Note 10 to the Financial Statements for discussion of other covenants related to the DIP Facilities.
Collateral Support Obligations — The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In June 2014, the RCT agreed to accept a collateral bond from TCEH of up to $1.1 billion as a substitute for its self-bond. The collateral bond is a $1.1 billion carve out from the super-priority liens under the TCEH DIP Facility that will enable the RCT to be paid before the TCEH DIP Facility lenders in the event of a liquidation of TCEH's assets. Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts.
The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at March 31, 2016, TCEH posted letters of credit in the amount of $55 million, which are subject to adjustments.
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ERCOT has rules in place to assure adequate creditworthiness of parties that participate in the day-ahead, real-time and congestion revenue rights markets operated by ERCOT. Under these rules, TCEH has posted collateral support, in the form of letters of credit, totaling $60 million at March 31, 2016 (which is subject to daily adjustments based on settlement activity with ERCOT).
Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred, two or more rating agencies downgrade Oncor's credit ratings below investment grade.
Material Cross Default/Acceleration Provisions — Certain of our financing arrangements contain provisions that result in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenants that could or does result in an acceleration of payments due. Such provisions are referred to as "cross default" or "cross acceleration" provisions. The Bankruptcy Filing triggered defaults on our pre-petition debt obligations, but pursuant to the Bankruptcy Code, the creditors are stayed from taking any actions against the Debtors as a result of such defaults.
Guarantees — See Note 12 to the Financial Statements for discussion of guarantees.
OFF–BALANCE SHEET ARRANGEMENTS
See Notes 4 and 12 to the Financial Statements regarding VIEs and guarantees, respectively.
COMMITMENTS AND CONTINGENCIES
See Note 12 to the Financial Statements for discussion of commitments and contingencies.
CHANGES IN ACCOUNTING STANDARDS
See Note 1 to the Financial Statements for discussion of changes in accounting standards.
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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 generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices.
In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. We continuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.
VaR Methodology — A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidence level and considers, among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.
A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlation data. The tables below detail certain VaR measures related to various portfolios of contracts; however, we have excluded a table for proprietary trading activity due to the de minimis size of that activity.
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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), based on a 95% confidence level and an assumed holding period of five to 60 days.
March 31, 2016 | December 31, 2015 | ||||||
Month-end average MtM VaR: | $ | 47 | $ | 68 | |||
Month-end high MtM VaR: | $ | 62 | $ | 97 | |||
Month-end low MtM VaR: | $ | 30 | $ | 49 | |||
Earnings at Risk (EaR) — This measurement estimates the potential reduction of pretax earnings for the periods presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities), based on a 95% confidence level and an assumed holding period of five to 60 days.
March 31, 2016 | December 31, 2015 | ||||||
Month-end average EaR: | $ | 14 | $ | 45 | |||
Month-end high EaR: | $ | 23 | $ | 92 | |||
Month-end low EaR: | $ | 7 | $ | 26 | |||
The decrease in the month end average MtM VaR and EaR risk measures during 2016 reflected decreased net commodity positions, lower electricity and natural gas prices and decreased price volatility.
Credit Risk
Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty's financial condition, credit rating and other quantitative and qualitative credit criteria and authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties' financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and setoff. Credit enhancements such as parental guarantees, letters of credit, surety bonds, margin deposits and customer deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure.
Credit Exposure — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $706 million at March 31, 2016. The components of this exposure are discussed in more detail below.
Assets subject to credit risk at March 31, 2016 include $344 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $52 million. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.
The remaining credit exposure arises from wholesale trade receivables and amounts associated with derivative instruments related to hedging and trading activities. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. At March 31, 2016, the exposure to credit risk from these counterparties totaled $362 million consisting of accounts receivable of $6 million and net asset positions related to commodity contracts of $356 million, after taking into account the netting provisions of the master agreements described above but before taking into account $174 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $188 million decreased $26 million in the three months ended March 31, 2016.
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Of this $188 million net exposure, 89% is with investment grade customers and counterparties, as determined by our internal credit evaluation process which includes publicly available information including major rating agencies' published ratings as well as internal credit methodologies and credit scoring models. Those customers and counterparties without an S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate an S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties based on, but not limited to, the assigned credit rating, margining and collateral management.
The following table presents the distribution of credit exposure at March 31, 2016. 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 2016) recognized as derivative assets in the condensed consolidated balance sheets, after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. Credit collateral includes cash and letters of credit, but excludes other credit enhancements such as liens on assets. See Note 15 to the Financial Statements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.
Exposure Before Credit Collateral | Credit Collateral | Net Exposure | |||||||||
Investment grade | $ | 341 | $ | 173 | $ | 168 | |||||
Below investment grade or no rating | 21 | 1 | 20 | ||||||||
Totals | $ | 362 | $ | 174 | $ | 188 | |||||
Investment grade | 94.2 | % | 89.4 | % | |||||||
Below investment grade or no rating | 5.8 | % | 10.6 | % | |||||||
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 55% and 24% of the $188 million net exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, each of which is rated as investment grade, the counterparties' market role and deemed creditworthiness and the importance of our business relationship with the counterparties. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through the various ongoing risk management measures described above.
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FORWARD-LOOKING STATEMENTS
This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including such matters as activities related to our bankruptcy, financial or operational projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated," "should," "projection," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under Item 1A, Risk Factors in our 2015 Form 10-K and the discussion under Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations in this report and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:
• | our ability to obtain the necessary votes from the required creditors and stakeholders and the approval from the Bankruptcy Court for the Plan of Reorganization; |
• | our ability to obtain Bankruptcy Court approval with respect to our motions in the Chapter 11 Cases, including such approvals not being overturned on appeal or being stayed for any extended period of time; |
• | the filing of an alternative plan of reorganization by one or more creditors of the Debtors; |
• | the breach by one or more of our counterparties under the Plan Support Agreement; |
• | the effectiveness of the overall restructuring activities pursuant to the Chapter 11 Cases, including the Plan of Reorganization, and any additional strategies we employ to address our liquidity and capital resources; |
• | the extent to which the Chapter 11 Cases cause customers, suppliers and others with whom we have commercial relationships to lose confidence in us, which may make it more difficult for us to obtain and maintain such commercial relationships on competitive terms; |
• | difficulties we may face in retaining and motivating our key employees through the bankruptcy process, and difficulties we may face in attracting new employees; |
• | the significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations; |
• | our ability to remain in compliance with the requirements of the DIP Facilities; |
• | our ability to maintain or obtain sufficient financing sources for our operations during the pendency of the Chapter 11 Cases and our ability to obtain sufficient exit financing to fund any Chapter 11 plan of reorganization; |
• | limitations on our ability to utilize previously incurred federal net operating losses or alternative minimum tax credits; |
• | the actions and decisions of creditors, regulators and other third parties that have an interest in the Chapter 11 Cases or reorganization that may be inconsistent with, or interfere with, our business and/or plans; |
• | the duration and related costs of the Chapter 11 Cases; |
• | the actions and decisions of regulatory authorities relative to any plan of reorganization; |
• | restrictions on our operations due to the terms of our debt agreements, including the DIP Facilities, and restrictions imposed by the Bankruptcy Court; |
• | our ability to obtain any required regulatory consent necessary to implement any Chapter 11 plan of reorganization; |
• | the outcome of current or potential litigation regarding whether holders are entitled to make-whole or redemption premiums and/or post-petition interest in connection with the treatment of their claims in bankruptcy; |
• | prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the FERC, the North American Electric Reliability Corporation, the Texas Reliability Entity, Inc., the PUCT, the RCT, the NRC, the EPA, the TCEQ, the US Mine Safety and Health Administration and the US Commodity Futures Trading Commission, with respect to, among other things: |
◦ | allowed prices; |
◦ | allowed rates of return; |
◦ | permitted capital structure; |
◦ | industry, market and rate structure; |
◦ | purchased power and recovery of investments; |
◦ | operations of nuclear generation facilities; |
◦ | operations of fossil fueled generation facilities; |
◦ | operations of mines; |
◦ | self-bonding requirements; |
◦ | acquisition and disposal of assets and facilities; |
◦ | development, construction and operation of facilities; |
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◦ | decommissioning costs; |
◦ | present or prospective wholesale and retail competition; |
◦ | changes in tax laws and policies; |
◦ | changes in and compliance with environmental and safety laws and policies, including the CSAPR, the MATS, regional haze program implementation and greenhouse gas and other climate change initiatives, and |
◦ | clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith; |
• | legal and administrative proceedings and settlements, including the legal proceedings arising out of the Chapter 11 Cases; |
• | general industry trends; |
• | economic conditions, including the impact of an economic downturn; |
• | our ability to collect trade receivables from counterparties; |
• | our ability to attract and retain profitable customers; |
• | our ability to profitably serve our customers; |
• | restrictions on competitive retail pricing; |
• | changes in wholesale electricity prices or energy commodity prices, including the price of natural gas; |
• | changes in prices of transportation of natural gas, coal, fuel oil and other refined products; |
• | changes in the ability of vendors to provide or deliver commodities as needed; |
• | changes in market heat rates in the ERCOT electricity market; |
• | our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates; |
• | weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, wars or terrorist or cyber security threats or activities; |
• | population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT; |
• | access to adequate transmission facilities to meet changing demands; |
• | changes in interest rates, commodity prices, rates of inflation or foreign exchange rates; |
• | changes in operating expenses, liquidity needs and capital expenditures; |
• | commercial bank market and capital market conditions and the potential impact of disruptions in US and international credit markets; |
• | access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets; |
• | our ability to generate sufficient cash flow to make interest or adequate protection payments, or refinance, our debt instruments, including the DIP Facilities; |
• | competition for new energy development and other business opportunities; |
• | inability of various counterparties to meet their obligations with respect to our financial instruments; |
• | changes in technology (including large scale electricity storage) used by and services offered by us; |
• | changes in electricity transmission that allow additional electricity generation to compete with our generation assets; |
• | significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur; |
• | changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure under ERISA; |
• | hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards, and |
• | actions by credit rating agencies. |
Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events or circumstances. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. As such, you should not unduly rely on such forward-looking statements.
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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 on Form 10-Q. Based on the evaluation performed, our principal executive officer and principal financial officer concluded that the disclosure controls and procedures were effective. During the most recent fiscal quarter covered by this quarterly report, there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
Item 1. | LEGAL PROCEEDINGS |
Reference is made to the discussion in Note 12 to the Financial Statements regarding legal proceedings.
Item 1A. | RISK FACTORS |
There have been no material changes from the risk factors discussed in Part I, Item 1A. Risk Factors in our 2015 Form 10-K, except for the risk factors described below and the information disclosed elsewhere in this quarterly report on Form 10-Q that provides factual updates to risk factors contained in our 2015 Form 10-K. The risks described in such reports are not the only risks facing our company.
We may not be able to obtain the requisite acceptances of constituencies in the Chapter 11 Cases for, or confirmation by the Bankruptcy Court of, the Plan of Reorganization, and we may not be able to consummate the Plan of Reorganization.
We filed the Plan of Reorganization in May 2016. We may not receive the requisite acceptances of constituencies in the Chapter 11 Cases for the Plan of Reorganization. Even if the requisite acceptances of the Plan of Reorganization are received, the Bankruptcy Court may not confirm the Plan of Reorganization. In addition, completion of the Plan of Reorganization is subject to the satisfaction of certain conditions precedent. There can be no assurance that such acceptance and confirmation will be obtained, or that such conditions will be satisfied, and therefore, that the Plan of Reorganization will be completed.
Furthermore, even if the requisite acceptances of constituencies in the Chapter 11 Cases for the Plan of Reorganization are received and the Plan of Reorganization is confirmed by the Bankruptcy Court, there can be no assurance as to the timing or as to whether the effective date of the reorganization contemplated therein will occur. If the Plan of Reorganization does not receive the requisite acceptances, or is not confirmed, or if it does receive the requisite acceptances and is confirmed but the effective date of the reorganization contemplated therein does not occur, it may become necessary to amend the Plan of Reorganization to provide for alternative treatment of claims and interests which may result in holders of claims and interests receiving significantly less, or no value, for their claims and interests in the Chapter 11 Cases. If any modifications to the Plan of Reorganization are material, it may be necessary to re-solicit votes from holders of claims and interests adversely affected by the modifications with respect to such Plan of Reorganization.
We no longer have the exclusive right to propose a plan of reorganization in the Chapter 11 Cases.
We no longer have the exclusive right to propose a plan of reorganization in the Chapter 11 Cases. Accordingly, any creditor of the Debtors can propose a plan of reorganization with respect to any one or more of the Debtors. Any new plan of reorganization would require the approval of the Bankruptcy Court and the acceptance of the required creditors, which could subject us to more lengthy Chapter 11 Cases. Any resulting delay could require us to extend or refinance our DIP Facilities and could adversely impact our liquidity and results of operations. In addition, we may not believe that an alternative plan of reorganization proposed by a creditor is in our stakeholders' best interests or fully values the benefits that can be achieved by the Plan of Reorganization. However, we would have limited ability to prevent an alternative plan of reorganization from being approved by the Bankruptcy Court. There can be no assurance that recoveries under any such alternative plan of reorganization would be as favorable to creditors as the Plan of Reorganization. In addition, the proposal of competing plans of reorganization may entail significant litigation and significantly increase the expenses of administration of the Chapter 11 Cases, which could deplete creditor recoveries under any plan of reorganization and adversely impact our liquidity and results of operations.
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It is possible that the TCEH Debtors and the EFH Debtors may emerge from the Chapter 11 Cases at different times.
The Plan of Reorganization provides that the confirmation and effective date of the Plan of Reorganization with respect to the TCEH Debtors may occur separate from, and independent of, the confirmation and effective date of the Plan of Reorganization with respect to the EFH Debtors. As a result, it is possible that the TCEH Debtors and the EFH Debtors may emerge from the Chapter 11 Cases at different times, and the difference in the timing of emergence between the two groups of Debtors may be significant. In such case, any Debtors that remain in bankruptcy may incur increased expenses associated with the Chapter 11 Cases as a result of the loss of synergies from services currently provided to the TCEH Debtors and EFH Debtors, and such expenses may be material. For example, the Debtors that remain in bankruptcy will continue to incur fees and expenses for legal representation, financial advisory and other professional services, which would no longer be shared among all the Debtors. Additionally, if the TCEH Debtors emerge from the Chapter 11 Cases prior to the EFH Debtors, the EFH Debtors will need to replace certain administrative and other services that are currently provided by employees and assets that would remain with the TCEH Debtors, whether through a services agreement with the TCEH Debtors or a third party. Further, a Private Letter Ruling from the IRS with respect to an earlier emergence of the TCEH Debtors may be based upon certain assumptions with respect to the structure of the emergence of the EFH Debtors. Additional submissions to the IRS and/or a supplemental Private Letter Ruling from the IRS may be required once the structure of the emergence of the EFH Debtors is determined.
If the effective date of the Plan of Reorganization with respect to the TCEH Debtors occurs prior to the effective date of the Plan of Reorganization with respect to the EFH Debtors pursuant to the Reorganized TCEH Spin-Off, the Reorganized TCEH Spin-Off may not be “grandfathered” under the PATH Act.
Because the Private Letter Ruling was filed with the IRS prior to December 7, 2015 and has not been subsequently withdrawn (and because no ruling had been issued or denied in its entirety prior to such date), the Reorganized TCEH Spin-Off is grandfathered from a provision in the Protecting Americans from Tax Hikes Act of 2015 (the PATH Act) that prevents companies, such as EFH Corp., involved in tax-free spin-offs from electing REIT status.
The Plan of Reorganization contemplates that the effective date of the Plan of Reorganization with respect to the TCEH Debtors may occur prior to the effective date of the Plan of Reorganization with respect to the EFH Debtors, and has no closing conditions relating to the conversion of Reorganized EFH or one of its subsidiaries into a real estate investment trust (REIT) under the Internal Revenue Code (a REIT Reorganization) with respect to the EFH Debtors. It may be possible that, by consummating the Plan of Reorganization with respect to the TCEH Debtors prior to the Plan of Reorganization with respect to the EFH Debtors, and by getting a Private Letter Ruling that does not contain REIT rulings (though it will continue to contemplate that a REIT Reorganization may occur in the future), there may be a risk that the grandfathering provision of the PATH Act will no longer apply to EFH Corp. We believe the stronger view is that EFH Corp. would continue to be grandfathered, but no guarantees can be made in this regard.
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.
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Item 6. | EXHIBITS |
(a) | Exhibits filed or furnished as part of Part II are: |
Exhibits | Previously Filed With File Number* | As Exhibit | ||||||
(2) | ||||||||
2(a) | 1-12833 Form 8-K/A (filed May 3, 2016) | 99.1 | — | The Debtors' Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code filed with the Bankruptcy Court on May 1, 2016 | ||||
(3(i)) | Articles of Incorporation | |||||||
3(a) | 1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013) | 3(a) | — | Restated Certificate of Formation of Energy Future Holdings Corp. | ||||
(3(ii)) | By-laws | |||||||
3(b) | 1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013) | 3(b) | — | Amended and Restated Bylaws of Energy Future Holdings Corp. | ||||
(31) | Rule 13a - 14(a)/15d-14(a) Certifications | |||||||
31(a) | — | Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||||
31(b) | — | Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||||
(32) | Section 1350 Certifications | |||||||
32(a) | — | Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||||||
32(b) | — | Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||||||
(95) | Mine Safety Disclosures | |||||||
95(a) | — | Mine Safety Disclosures | ||||||
(99) | Additional Exhibits | |||||||
99(a) | — | Condensed Statement of Consolidated Loss – Twelve Months Ended March 31, 2016. | ||||||
99(b) | — | Texas Competitive Electric Holdings Company LLC Consolidated EBITDA reconciliation for the three and twelve months ended March 31, 2016 and 2015 | ||||||
XBRL Data Files | ||||||||
101.INS | — | XBRL Instance Document | ||||||
101.SCH | — | XBRL Taxonomy Extension Schema Document | ||||||
101.CAL | — | XBRL Taxonomy Extension Calculation Document | ||||||
101.DEF | — | XBRL Taxonomy Extension Definition Document | ||||||
101.LAB | — | XBRL Taxonomy Extension Labels Document | ||||||
101.PRE | — | XBRL Taxonomy Extension Presentation Document | ||||||
____________________
* | Incorporated herein by reference |
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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/ TERRY L. NUTT | |||
Name: | Terry L. Nutt | |||
Title: | Senior Vice President and Controller | |||
(Principal Accounting Officer) | ||||
Date: May 9, 2016
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