Vistra Corp. - Quarter Report: 2017 September (Form 10-Q)
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 SEPTEMBER 30, 2017
— OR —
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-38086
Vistra Energy Corp.
(Exact name of registrant as specified in its charter)
Delaware | 36-4833255 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
6555 Sierra Drive, Irving, Texas 75039 | (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, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth 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 Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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
As of October 31, 2017, there were 428,210,147 shares of common stock, par value $0.01, outstanding of Vistra Energy Corp.
TABLE OF CONTENTS
PAGE | ||
PART I. | ||
Item 1. | ||
Item 2. | ||
Item 3. | ||
Item 4. | ||
PART II. | ||
Item 1. | ||
Item 1A. | ||
Item 2. | ||
Item 3. | ||
Item 4. | ||
Item 5. | ||
Item 6. | ||
Vistra Energy Corp.'s (Vistra Energy) annual reports, quarterly reports, current reports and any amendments to those reports are made available to the public, free of charge, on the Vistra Energy website at http://www.vistraenergy.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. The information on Vistra Energy'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 that may (i) be made by and to the parties thereto at specific dates, (ii) be subject to exceptions and qualifications contained in separate disclosure schedules, (iii) represent the parties' risk allocation in the particular transaction, or (iv) 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 Vistra Energy and its subsidiaries occasionally make references to Vistra Energy (or "we," "our," "us" or "the Company"), TXU Energy or Luminant 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.
CCGT | combined cycle gas turbine | |
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. On the Effective Date, the TCEH Debtors (together with the Contributed EFH Debtors) emerged from the Chapter 11 Cases. | |
CME | Chicago Mercantile Exchange | |
Contributed EFH Debtors | certain EFH Debtors that became subsidiaries of Vistra Energy on the Effective Date | |
DIP Facility | TCEH's $3.375 billion debtor-in-possession financing facility, which was repaid in August 2016. See Note 9 to the Financial Statements. | |
DIP Roll Facilities | TCEH's $4.250 billion debtor-in-possession and exit financing facilities, which was converted to the Vistra Operations Credit Facilities on the Effective Date. See Note 9 to the Financial Statements. | |
Debtors | EFH Corp. and the majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities. Prior to the Effective Date, also included the TCEH Debtors and the Contributed EFH Debtors. | |
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, prior to the Effective Date, the indirect parent of the TCEH Debtors, depending on context | |
Effective Date | October 3, 2016, the date the TCEH Debtors and the Contributed EFH Debtors completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases | |
EFH Corp. | Energy Future Holdings Corp. and/or its subsidiaries, depending on context, whose major subsidiaries include Oncor and, prior to the Effective Date, included the TCEH Debtors and the Contributed EFH Debtors | |
EFH Debtors | EFH Corp. and its subsidiaries that are Debtors in the Chapter 11 Cases, including EFIH and EFIH Finance Inc., but excluding the TCEH Debtors and the Contributed EFH Debtors | |
EFIH | Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings | |
Emergence | emergence of the TCEH Debtors and the Contributed EFH Debtors from the Chapter 11 Cases as subsidiaries of a newly-formed company, Vistra Energy, on the Effective Date | |
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 | |
Federal and State Income Tax Allocation Agreements | Prior to the Effective Date, EFH Corp. and certain of its subsidiaries (including EFCH, EFIH and TCEH, but not including Oncor Holdings and Oncor) were parties to a Federal and State Income Tax Allocation Agreement, executed in May 2012 but effective as of January 2010. The Agreement was rejected by the TCEH Debtors and the Contributed EFH Debtors on the Effective Date. See Note 5 to the Financial Statements. | |
GAAP | generally accepted accounting principles | |
GHG | greenhouse gas | |
GWh | gigawatt-hours | |
ICE | IntercontinentalExchange | |
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 | |
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LSTC | liabilities subject to compromise | |
Luminant | subsidiaries of Vistra Energy 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. | |
MMBtu | million British thermal units | |
MW | megawatts | |
MWh | megawatt-hours | |
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., that is engaged in regulated electricity transmission and distribution activities | |
Oncor Holdings | Oncor Electric Delivery Holdings Company LLC, a direct, wholly owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context | |
Oncor Ring-Fenced Entities | Oncor Holdings and its direct and indirect subsidiaries, including Oncor | |
OPEB | postretirement employee benefits other than pensions | |
Petition Date | April 29, 2014, the date the Debtors filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code | |
Plan of Reorganization | Third Amended Joint Plan of Reorganization filed by the Debtors in August 2016 and confirmed by the Bankruptcy Court in August 2016 solely with respect to the TCEH Debtors and the Contributed EFH Debtors | |
PrefCo | Vistra Preferred Inc. | |
PUCT | Public Utility Commission of Texas | |
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. | |
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 Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group, that owns substantially all of the common stock of EFH Corp. | |
TRA | Tax Receivables Agreement, containing certain rights (TRA Rights) to receive payments from Vistra Energy related to certain tax benefits, including those it realized as a result of certain transactions entered into at Emergence (see Note 6) | |
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TCEH or Predecessor | Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of Energy Future Competitive Holdings Company LLC, and, prior to the Effective Date, the parent company of the TCEH Debtors, depending on context, that were engaged in electricity generation and wholesale and retail energy market activities, and whose major subsidiaries included Luminant and TXU Energy. | |
TCEH Debtors | the subsidiaries of TCEH that were Debtors in the Chapter 11 Cases | |
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. The claims arising under these facilities were discharged in the Chapter 11 Cases on the Effective Date pursuant to the Plan of Reorganization. | |
TCEQ | Texas Commission on Environmental Quality | |
TXU Energy | TXU Energy Retail Company LLC, a direct, wholly owned subsidiary of Vistra Energy 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 | |
Vistra Energy or Successor | Vistra Energy Corp., formerly known as TCEH Corp., and/or its subsidiaries, depending on context. On the Effective Date, the TCEH Debtors and the Contributed EFH Debtors emerged from Chapter 11 and became subsidiaries of Vistra Energy Corp. | |
Vistra Operations Credit Facilities | Vistra Operations Company LLC's $5.360 billion senior secured financing facilities. See Note 9 to the Financial Statements. | |
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PART I. FINANCIAL INFORMATION
Item 1. | FINANCIAL STATEMENTS |
VISTRA ENERGY CORP.
CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)
(Unaudited) (Millions of Dollars, Except Per Share Amounts)
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | ||||||||||||||
Operating revenues | $ | 1,833 | $ | 1,690 | $ | 4,487 | $ | 3,973 | |||||||||
Fuel, purchased power costs and delivery fees | (838 | ) | (874 | ) | (2,250 | ) | (2,082 | ) | |||||||||
Net gain from commodity hedging and trading activities | — | 336 | — | 282 | |||||||||||||
Operating costs | (218 | ) | (190 | ) | (626 | ) | (664 | ) | |||||||||
Depreciation and amortization | (178 | ) | (157 | ) | (519 | ) | (459 | ) | |||||||||
Selling, general and administrative expenses | (147 | ) | (165 | ) | (434 | ) | (482 | ) | |||||||||
Operating income | 452 | 640 | 658 | 568 | |||||||||||||
Other income (Note 16) | 10 | 7 | 29 | 19 | |||||||||||||
Other deductions (Note 16) | — | (28 | ) | (5 | ) | (75 | ) | ||||||||||
Interest expense and related charges (Note 7) | (76 | ) | (371 | ) | (169 | ) | (1,049 | ) | |||||||||
Impacts of Tax Receivable Agreement (Note 6) | 138 | — | 96 | — | |||||||||||||
Reorganization items (Note 2) | — | (64 | ) | — | (116 | ) | |||||||||||
Income (loss) before income taxes | 524 | 184 | 609 | (653 | ) | ||||||||||||
Income tax (expense) benefit (Note 5) | (251 | ) | 3 | (284 | ) | (3 | ) | ||||||||||
Net income (loss) | $ | 273 | $ | 187 | $ | 325 | $ | (656 | ) | ||||||||
Weighted average shares of common stock outstanding: | |||||||||||||||||
Basic | 427,591,426 | 427,587,404 | |||||||||||||||
Diluted | 428,312,438 | 428,001,869 | |||||||||||||||
Net income per weighted average share of common stock outstanding: | |||||||||||||||||
Basic | $ | 0.64 | $ | 0.76 | |||||||||||||
Diluted | $ | 0.64 | $ | 0.76 | |||||||||||||
See Notes to the Condensed Consolidated Financial Statements.
CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Unaudited) (Millions of Dollars)
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | ||||||||||||||
Net income (loss) | $ | 273 | $ | 187 | $ | 325 | $ | (656 | ) | ||||||||
Other comprehensive income (loss), net of tax effects: | |||||||||||||||||
Effects related to pension and other retirement benefit obligations (net of tax benefit of $— in all periods) | — | — | — | 1 | |||||||||||||
Total other comprehensive income | — | — | — | 1 | |||||||||||||
Comprehensive income (loss) | $ | 273 | $ | 187 | $ | 325 | $ | (655 | ) | ||||||||
See Notes to the Condensed Consolidated Financial Statements.
1
VISTRA ENERGY CORP. CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) (Millions of Dollars) | ||||||||
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | |||||||
Cash flows — operating activities: | ||||||||
Net income (loss) | $ | 325 | $ | (656 | ) | |||
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities: | ||||||||
Depreciation and amortization | 621 | 532 | ||||||
Deferred income tax expense, net | 209 | 2 | ||||||
Unrealized net (gain) loss from mark-to-market valuations of derivatives | (199 | ) | 36 | |||||
Write-off of intangible and other assets (Note 16) | — | 45 | ||||||
Impacts of Tax Receivable Agreement (Note 6) | (96 | ) | — | |||||
Stock-based compensation | 13 | — | ||||||
Other, net | 84 | 86 | ||||||
Changes in operating assets and liabilities: | ||||||||
Margin deposits, net | 183 | (124 | ) | |||||
Accrued interest | (26 | ) | (10 | ) | ||||
Accrued taxes | 4 | (13 | ) | |||||
Accrued incentive plan | (46 | ) | (30 | ) | ||||
Other operating assets and liabilities, including liabilities subject to compromise | (227 | ) | (64 | ) | ||||
Cash provided by (used in) operating activities | 845 | (196 | ) | |||||
Cash flows — financing activities: | ||||||||
Borrowings under TCEH DIP Roll Facilities and DIP Facility (Note 9) | — | 4,680 | ||||||
TCEH DIP Roll Facilities financing fees | — | (112 | ) | |||||
Repayments/repurchases of debt (Note 9) | (32 | ) | (2,655 | ) | ||||
Other, net | (5 | ) | — | |||||
Cash (used in) provided by financing activities | (37 | ) | 1,913 | |||||
Cash flows — investing activities: | ||||||||
Capital expenditures | (86 | ) | (230 | ) | ||||
Nuclear fuel purchases | (56 | ) | (33 | ) | ||||
Solar development expenditures | (129 | ) | — | |||||
Odessa acquisition (Note 3) | (355 | ) | — | |||||
Lamar and Forney acquisition — net of cash acquired (Note 3) | — | (1,343 | ) | |||||
Changes in restricted cash | 34 | 365 | ||||||
Proceeds from sales of nuclear decommissioning trust fund securities (Note 16) | 154 | 201 | ||||||
Investments in nuclear decommissioning trust fund securities (Note 16) | (169 | ) | (215 | ) | ||||
Other, net | 10 | (33 | ) | |||||
Cash used in investing activities | (597 | ) | (1,288 | ) | ||||
Net change in cash and cash equivalents | 211 | 429 | ||||||
Cash and cash equivalents — beginning balance | 843 | 1,400 | ||||||
Cash and cash equivalents — ending balance | $ | 1,054 | $ | 1,829 | ||||
See Notes to the Condensed Consolidated Financial Statements.
2
VISTRA ENERGY CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars) | |||||||
September 30, 2017 | December 31, 2016 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 1,054 | $ | 843 | |||
Restricted cash (Note 16) | 61 | 95 | |||||
Trade accounts receivable — net (Note 16) | 717 | 612 | |||||
Inventories (Note 16) | 295 | 285 | |||||
Commodity and other derivative contractual assets (Note 13) | 182 | 350 | |||||
Margin deposits related to commodity contracts | 3 | 213 | |||||
Prepaid expense and other current assets | 128 | 75 | |||||
Total current assets | 2,440 | 2,473 | |||||
Restricted cash (Note 16) | 650 | 650 | |||||
Investments (Note 16) | 1,183 | 1,064 | |||||
Property, plant and equipment — net (Note 16) | 4,746 | 4,443 | |||||
Goodwill (Note 4) | 1,907 | 1,907 | |||||
Identifiable intangible assets — net (Note 4) | 2,849 | 3,205 | |||||
Commodity and other derivative contractual assets (Note 13) | 129 | 64 | |||||
Accumulated deferred income taxes | 913 | 1,122 | |||||
Other noncurrent assets | 183 | 239 | |||||
Total assets | $ | 15,000 | $ | 15,167 | |||
LIABILITIES AND EQUITY | |||||||
Current liabilities: | |||||||
Long-term debt due currently (Note 9) | $ | 44 | $ | 46 | |||
Trade accounts payable | 487 | 479 | |||||
Commodity and other derivative contractual liabilities (Note 13) | 72 | 359 | |||||
Margin deposits related to commodity contracts | 14 | 41 | |||||
Accrued taxes | 55 | 31 | |||||
Accrued taxes other than income | 105 | 128 | |||||
Accrued interest | 6 | 33 | |||||
Other current liabilities | 336 | 387 | |||||
Total current liabilities | 1,119 | 1,504 | |||||
Long-term debt, less amounts due currently (Note 9) | 4,540 | 4,577 | |||||
Commodity and other derivative contractual liabilities (Note 13) | 32 | 2 | |||||
Tax Receivable Agreement obligation (Note 6) | 476 | 596 | |||||
Asset retirement obligations (Note 16) | 1,666 | 1,671 | |||||
Other noncurrent liabilities and deferred credits (Note 16) | 232 | 220 | |||||
Total liabilities | 8,065 | 8,570 | |||||
3
VISTRA ENERGY CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars) | |||||||
September 30, 2017 | December 31, 2016 | ||||||
Commitments and Contingencies (Note 10) | |||||||
Total equity (Note 11): | |||||||
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: September 30, 2017 — 427,597,368; December 31, 2016 — 427,580,232) | 4 | 4 | |||||
Additional paid-in-capital | 7,755 | 7,742 | |||||
Retained deficit | (830 | ) | (1,155 | ) | |||
Accumulated other comprehensive income | 6 | 6 | |||||
Total equity | 6,935 | 6,597 | |||||
Total liabilities and equity | $ | 15,000 | $ | 15,167 | |||
See Notes to the Condensed Consolidated Financial Statements.
4
VISTRA ENERGY CORP.
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 Vistra Energy and/or its subsidiaries in the Successor period, and to TCEH and/or its subsidiaries in the Predecessor periods, as apparent in the context. See Glossary for defined terms.
On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities (collectively, the Debtors), filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court).
On October 3, 2016 (the Effective Date), subsidiaries of TCEH that were Debtors in the Chapter 11 Cases (the TCEH Debtors) and certain EFH Corp. subsidiaries (the Contributed EFH Debtors) completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases (Emergence) as subsidiaries of a newly-formed company, Vistra Energy (our Successor). On the Effective Date, Vistra Energy was spun-off from EFH Corp. in a tax-free transaction to the former first lien creditors of TCEH (Spin-Off). As a result, as of the Effective Date, Vistra Energy is a holding company for subsidiaries principally engaged in competitive electricity market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity to end users. TCEH is the Predecessor to Vistra Energy. See Note 2 for further discussion regarding the Chapter 11 Cases.
Vistra Energy is a holding company operating an integrated power business in Texas. Through our Luminant and TXU Energy subsidiaries, we are engaged in competitive electricity market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity to end users. Prior to the Effective Date, TCEH was a holding company for subsidiaries principally engaged in the same activities as Vistra Energy.
Subsequent to the Effective Date, Vistra Energy has two reportable segments: our Wholesale Generation segment, consisting largely of Luminant, and our Retail Electricity segment, consisting largely of TXU Energy. Prior to the Effective Date, there were no reportable business segments for our Predecessor. See Note 15 for further information concerning reportable business segments.
Basis of Presentation
As of the Effective Date, Vistra Energy applied fresh start reporting under the applicable provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852). Fresh start reporting included (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring (TCEH, or the Predecessor) from the financial statements of the entity that emerges from restructuring (Vistra Energy, or the Successor), (2) accounting for the effects of the Plan of Reorganization, (3) assigning the reorganization value of the Successor entity by measuring all assets and liabilities of the Successor entity at fair value, and (4) selecting accounting policies for the Successor entity. The financial statements of Vistra Energy for periods subsequent to the Effective Date are not comparable to the financial statements of TCEH for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that resulted from the Plan of Reorganization and the related application of fresh start reporting. The reorganization value of Vistra Energy was assigned to its assets and liabilities in conformity with the procedures specified by FASB ASC 805, Business Combinations, and the portion of the reorganization value that was not attributable to identifiable tangible or intangible assets was recognized as goodwill.
The condensed consolidated financial statements of the Predecessor reflect the application of ASC 852 as it applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. As a result, the condensed consolidated financial statements of the Predecessor have been prepared as if TCEH was a going concern and contemplated the realization of assets and liabilities in the normal course of business. During the Chapter 11 Cases, the Debtors operated their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The 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. Prior to the Effective Date, the Predecessor recorded the effects of the Plan of Reorganization in accordance with ASC 852. See Reorganization Items in Note 2 for further discussion of these accounting and reporting changes.
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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 contained in our prospectus filed with the SEC pursuant to Rule 424(b) of the Securities Act in May 2017. 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, estimates of expected obligations, judgment related to the potential timing of events and other estimates. 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 May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606), which was further amended through several updates issued by the FASB in 2016 and 2017. The guidance under Topic 606 provides the core principle and key steps in determining the recognition of revenue and expands disclosure requirements related to revenue recognition. We intend to adopt the new standard on January 1, 2018 using the modified retrospective method and expect to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance completed to date. In recent periods, we completed an assessment of substantially all of our performance obligations in our contractual relationships and continued to assess the expanded disclosure requirements. We do not anticipate that the adoption of the standard will have a material effect on our results of operations, cash flows or financial condition.
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2016-02 (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 November 2016, the FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash. The ASU requires restricted cash to be included in the cash and cash equivalents and a reconciliation between the change in cash and cash equivalents and the amounts presented on the balance sheet. This ASU will be effective for fiscal years beginning after December 15, 2017, and we will adopt the new standard on January 1, 2018. The ASU will modify the presentation of our statement of consolidated cash flows, but will not have a material impact on our statement of consolidated net income and consolidated balance sheet.
In January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business. The ASU provides an updated model for determining if acquired assets and liabilities constitute a business. In a business combination, the acquired assets and liabilities are recognized at fair value and goodwill could be recognized. In an asset acquisition, the assets are allocated value based on relative fair value and no goodwill is recognized. The ASU narrows the definition of a business. We adopted this standard in the first quarter of 2017. ASU 2017-01 did not have a material impact on our financial statements.
In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). The ASU provides for the elimination of Step 2 from the goodwill impairment test. If impairment charges are recognized, the amount recorded will be the amount by which the carrying amount exceeds the reporting unit's fair value with certain limitations. We adopted this standard in the first quarter of 2017. ASU 2017-04 did not have a material impact on our financial statements.
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2. EMERGENCE FROM 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. On the Effective Date, the TCEH Debtors and the Contributed EFH Debtors completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases as subsidiaries of Vistra Energy.
Separation of Vistra Energy from EFH Corp. and its Subsidiaries
Upon the Effective Date, Vistra Energy separated from EFH Corp. pursuant to a tax-free spin-off transaction that was part of a series of transactions that included a taxable component. The taxable portion of the transaction generated a taxable gain that resulted in no regular tax liability due to available net operating loss carryforwards of EFH Corp. The transaction did result in an alternative minimum tax liability of approximately $14 million payable by EFH Corp. to the IRS. Pursuant to the Tax Matters Agreement (defined below), Vistra Energy had an obligation to reimburse EFH Corp. 50% of the estimated alternative minimum tax, and approximately $7 million was reimbursed during the three months ended June 30, 2017. In October 2017, the 2016 federal tax return that included the results of EFCH, EFIH, Oncor Holdings and TCEH was filed with the IRS and resulted in a $3 million payable from EFH Corp. to Vistra Energy. The spin-off transaction resulted in Vistra Energy, including the TCEH Debtors and the Contributed EFH Debtors, no longer being an affiliate of EFH Corp. and its subsidiaries.
Separation Agreement
On the Effective Date, EFH Corp., Vistra Energy and a subsidiary of Vistra Energy entered into a separation agreement that provided for, among other things, the transfer of certain assets and liabilities by EFH Corp., EFCH and TCEH to Vistra Energy. Among other things, EFH Corp., EFCH and/or TCEH, as applicable, (a) transferred the TCEH Debtors and certain contracts and assets (and related liabilities) primarily related to the business of the TCEH Debtors to Vistra Energy, (b) transferred sponsorship of certain employee benefit plans (including related assets), programs and policies to a subsidiary of Vistra Energy and (c) assigned certain employment agreements from EFH Corp. and certain of the Contributed EFH Debtors to a subsidiary of Vistra Energy.
Tax Matters Agreement
On the Effective Date, Vistra Energy and EFH Corp. entered into a tax matters agreement (the Tax Matters Agreement), which provides for the allocation of certain taxes among the parties and for certain rights and obligations related to, among other things, the filing of tax returns, resolutions of tax audits and preserving the tax-free nature of the spin-off.
Pre-Petition Claims
On the Effective Date, the TCEH Debtors (together with the Contributed EFH Debtors) emerged from the Chapter 11 Cases and discharged approximately $33.8 billion in LSTC. Initial distributions related to the allowed claims asserted against the TCEH Debtors and the Contributed EFH Debtors commenced subsequent to the Effective Date. As of September 30, 2017, the TCEH Debtors have approximately $54 million in escrow to (1) distribute to holders of currently contingent and/or disputed unsecured claims that become allowed and/or (2) make further distributions to holders of previously allowed unsecured claims, if applicable. Additionally, the TCEH Debtors have approximately $7 million in escrow to pay remaining professional fees incurred in the Chapter 11 Cases. The remaining contingent and/or disputed claims against the TCEH Debtors consist primarily of unsecured legal claims, including asbestos claims. These remaining claims and the related escrow balance for the claims are recorded in Vistra Energy's condensed consolidated balance sheet as other current liabilities and current restricted cash, respectively. A small number of other disputed, de minimis claims that are asserted as being entitled to priority and/or against the Contributed EFH Debtors, if allowed, will be paid by Vistra Energy, but all non-priority unsecured claims, including asbestos claims arising before the Petition Date, will be satisfied from the approximately $54 million in escrow.
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Predecessor Reorganization Items
Expenses and income directly associated with the Chapter 11 Cases are reported separately in the condensed statements of consolidated income (loss) as reorganization items as required by ASC 852, Reorganizations. Reorganization items also included adjustments to reflect the carrying value of LSTC at their estimated allowed claim amounts, as such adjustments were determined. The following table presents reorganization items incurred in the three and nine months ended September 30, 2016 as reported in the condensed statements of consolidated income (loss):
Predecessor | |||||||
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | ||||||
Expenses related to legal advisory and representation services | $ | 28 | $ | 55 | |||
Expenses related to other professional consulting and advisory services | 19 | 39 | |||||
Contract claims adjustments | 10 | 13 | |||||
Other | 7 | 9 | |||||
Total reorganization items | $ | 64 | $ | 116 | |||
3. | ACQUISITION AND DEVELOPMENT OF GENERATION FACILITIES |
Odessa Acquisition (Successor)
In August 2017, La Frontera Holdings, LLC (La Frontera), an indirect wholly owned subsidiary of Vistra Energy, purchased a 1,054 MW CCGT natural gas fueled generation plant (and other related assets and liabilities) located in Odessa, Texas (Odessa Facility) from Odessa-Ector Power Partners, L.P., an indirect wholly owned subsidiary of Koch Ag & Energy Solutions, LLC (Koch) (altogether, the Odessa Acquisition). La Frontera paid an aggregate purchase price of approximately $355 million, plus a five-year earn-out provision, to acquire the Odessa Facility. The purchase price was funded by cash on hand.
The Odessa Acquisition was accounted for as an asset acquisition. Substantially all of the cash paid of approximately $355 million was assigned to property, plant and equipment in our consolidated balance sheet. Additionally, the initial fair value associated with an earn-out provision of approximately $16 million was included as consideration in the overall purchase price. The earn-out provision requires cash payments to be made to Koch if spark-spreads related to the pricing point of the Odessa Facility exceed certain thresholds. Subsequent to the acquisition, the earn-out provision has been accounted for as a derivative in our consolidated financial statements.
Upton Solar Development (Successor)
In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power generation facility in Upton County, Texas (Upton). As part of this project, we entered a turnkey engineering, procurement and construction agreement to construct the approximately 180 MW facility. For the nine months ended September 30, 2017, we have spent approximately $129 million related to this project primarily for progress payments under the engineering, procurement and construction agreement and the acquisition of the development rights. We currently estimate that the facility will begin operations in the summer of 2018.
Lamar and Forney Acquisition (Predecessor)
In April 2016, Luminant purchased all of the membership interests in La Frontera Holdings, LLC (La Frontera), the indirect owner of two combined-cycle gas turbine (CCGT) natural gas fueled generation facilities representing nearly 3,000 MW of capacity located in ERCOT, from a subsidiary of NextEra Energy, Inc. (the Lamar and Forney Acquisition). The aggregate purchase price was approximately $1.313 billion, which included the repayment of approximately $950 million of existing project financing indebtedness of La Frontera at closing, plus approximately $236 million for cash and net working capital.
The Lamar and Forney Acquisition was accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date.
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See Note 6 to the audited financial statements contained in our prospectus filed with the SEC pursuant to Rule 424(b) of the Securities Act in May 2017 for a summary of the consideration paid and the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Lamar and Forney Acquisition as of the acquisition date. During the three months ended September 30, 2016, the working capital adjustment included in the purchase price was finalized between the parties, and the purchase price allocation was completed. The Lamar and Forney Acquisition did not result in the recording of goodwill since the purchase price did not exceed the fair value of the net assets acquired.
Unaudited Pro Forma Financial Information — The following unaudited pro forma financial information for the nine months ended September 30, 2016 assumes that the Lamar and Forney Acquisition occurred on January 1, 2016. The unaudited pro forma financial information is provided for information purposes only and is not necessarily indicative of the results of operations that would have occurred had the Lamar and Forney Acquisition been completed on January 1, 2016, nor is the unaudited pro forma financial information indicative of future results of operations.
Predecessor | |||
Nine Months Ended September 30, 2016 | |||
Revenues | $ | 4,116 | |
Net loss | $ | (672 | ) |
The unaudited pro forma financial information includes adjustments for incremental depreciation as a result of the fair value determination of the net assets acquired and interest expense on borrowings under our Predecessor's DIP Roll Facilities in lieu of interest expense incurred prior to the acquisition.
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4. | GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS |
Goodwill
The carrying value of goodwill totaled $1.907 billion at both September 30, 2017 and December 31, 2016. The goodwill arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to the Retail Electricity segment (see Note 1). Of the goodwill recorded at Emergence, $1.686 billion is deductible for tax purposes over 15 years on a straight-line basis.
Identifiable Intangible Assets
Identifiable intangible assets, including the impact of fresh start reporting (see Note 1), are comprised of the following:
September 30, 2017 | December 31, 2016 | |||||||||||||||||||||||
Identifiable Intangible Asset | Gross Carrying Amount | Accumulated Amortization | Net | Gross Carrying Amount | Accumulated Amortization | Net | ||||||||||||||||||
Retail customer relationship | $ | 1,648 | $ | 467 | $ | 1,181 | $ | 1,648 | $ | 152 | $ | 1,496 | ||||||||||||
Software and other technology-related assets | 178 | 36 | 142 | 147 | 9 | 138 | ||||||||||||||||||
Electricity supply contract (a) | 190 | 9 | 181 | 190 | 2 | 188 | ||||||||||||||||||
Retail and wholesale contracts | 164 | 72 | 92 | 164 | 38 | 126 | ||||||||||||||||||
Other identifiable intangible assets (b) | 33 | 9 | 24 | 30 | 2 | 28 | ||||||||||||||||||
Total identifiable intangible assets subject to amortization | $ | 2,213 | $ | 593 | 1,620 | $ | 2,179 | $ | 203 | 1,976 | ||||||||||||||
Retail trade names (not subject to amortization) | 1,225 | 1,225 | ||||||||||||||||||||||
Mineral interests (not currently subject to amortization) | 4 | 4 | ||||||||||||||||||||||
Total identifiable intangible assets | $ | 2,849 | $ | 3,205 | ||||||||||||||||||||
____________
(a) | Contract terminated in October 2017. See Note 17. |
(b) | Includes mining development costs and environmental allowances and credits. |
Amortization expense related to finite-lived identifiable intangible assets (including the classification in the condensed statements of consolidated income (loss)) consisted of:
Successor | Predecessor | Successor | Predecessor | |||||||||||||||||
Identifiable Intangible Asset | Condensed Statements of Consolidated Income (Loss) Line | Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | |||||||||||||||
Retail customer relationship | Depreciation and amortization | $ | 105 | $ | 3 | $ | 315 | $ | 9 | |||||||||||
Software and other technology-related assets | Depreciation and amortization | 10 | 15 | 27 | 44 | |||||||||||||||
Electricity supply contract | Operating revenues | 2 | — | 7 | — | |||||||||||||||
Retail and wholesale contracts | Operating revenues/fuel, purchased power costs and delivery fees | (17 | ) | — | 34 | — | ||||||||||||||
Other identifiable intangible assets | Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization | 3 | 3 | 7 | 6 | |||||||||||||||
Total amortization expense (a) | $ | 103 | $ | 21 | $ | 390 | $ | 59 | ||||||||||||
____________
(a) | Amounts recorded in depreciation and amortization totaled $116 million and $20 million for the three months ended September 30, 2017 and 2016, respectively, and $347 million and $58 million for the nine months ended September 30, 2017 and 2016, respectively. |
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Estimated Amortization of Identifiable Intangible Assets
As of September 30, 2017, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.
Year | Estimated Amortization Expense | |||
2017 | $ | 560 | ||
2018 | $ | 374 | ||
2019 | $ | 266 | ||
2020 | $ | 198 | ||
2021 | $ | 130 | ||
5. | INCOME TAXES |
Subsequent to the Effective Date, the TCEH Debtors and the Contributed EFH Debtors are no longer included in the consolidated federal income tax return of EFH Corp. and will be included in Vistra Energy's consolidated federal income tax return.
Prior to the Effective Date, EFH Corp. was the corporate parent of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH was classified as a disregarded entity for US federal income tax purposes. For the 2016 tax year (through the period until the Effective Date) EFH Corp. filed a US federal income tax return in October 2017 that included the results of EFCH, EFIH, Oncor Holdings and TCEH. 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.
Prior to the Effective Date, EFH Corp. and certain of its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) were parties to a Federal and State Income Tax Allocation Agreement, which provided, 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. Pursuant to the Plan of Reorganization, the TCEH Debtors and the Contributed EFH Debtors rejected this agreement on the Effective Date. See Note 2 for a discussion of the Tax Matters Agreement that was entered into on the Effective Date between EFH Corp. and Vistra Energy. Additionally, since the date of the Settlement Agreement, no further cash payments among the Debtors were made in respect of federal income taxes. The Settlement Agreement did not alter the allocation and payment for state income taxes, which continued to be settled prior to the Effective Date.
The calculation of our effective tax rate is as follows:
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | ||||||||||||||
Income (loss) before income taxes | $ | 524 | $ | 184 | $ | 609 | $ | (653 | ) | ||||||||
Income tax (expense) benefit | $ | (251 | ) | $ | 3 | $ | (284 | ) | $ | (3 | ) | ||||||
Effective tax rate | 47.9 | % | (1.6 | )% | 46.6 | % | (0.5 | )% | |||||||||
Successor — For the three months ended September 30, 2017, the effective tax rate of 47.9% related to our income tax expense was higher than the US Federal statutory rate of 35% due primarily to nondeductible impacts of the TRA and Texas margin tax and a reduction in the tax basis of certain of our assets based on the finalization of tax returns related to the pre-Emergence period. For the nine months ended September 30, 2017, the effective tax rate of 46.6% related to our income tax expense was higher than the US Federal statutory rate of 35% due primarily to nondeductible impacts of the TRA and Texas margin tax and a reduction in the tax basis of certain of our assets based on the finalization of tax returns related to the pre-Emergence period.
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Predecessor — For the three months ended September 30, 2016, the effective tax rate of (1.6)% related to our income tax benefit was lower than the US Federal statutory rate of 35% due primarily to a valuation allowance recorded against deferred tax assets in 2016, offset by the tax benefit recognized from the settlement agreement reached with the Texas Comptroller of Public Accounts. For the nine months ended September 30, 2016, the effective tax rate of (0.5)% related to our income tax expense was lower than the US Federal statutory rate of 35% due primarily to a valuation allowance recorded against deferred tax assets and Texas margin tax expense on pretax losses in 2016.
Liability for Uncertain Tax Positions
Successor — Vistra Energy has limited operational history and filed its first federal tax return in October 2017. We currently have no liabilities for uncertain tax positions.
Predecessor — In September 2016, EFH Corp. entered into a settlement agreement with the Texas Comptroller of Public Accounts (Comptroller) whereby the Comptroller agreed to release all claims and liabilities related to the EFH Corp. consolidated group's state taxes, including sales tax, gross receipts utility tax, franchise tax and direct pay tax, through the agreement date, in exchange for a release of all refund claims and a one-time payment of $12 million. This settlement was entered and approved by the Bankruptcy Court in September 2016. As a result of the settlement, our Predecessor reduced the liability for uncertain tax positions by $27 million.
6. | TAX RECEIVABLE AGREEMENT OBLIGATION |
On the Effective Date, Vistra Energy entered into a tax receivable agreement (the TRA) with a transfer agent on behalf of certain former first lien creditors of TCEH. The TRA generally provides for the payment by us to holders of TRA Rights of 85% of the amount of cash savings, if any, in US federal and state income tax that we realize in periods after Emergence as a result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the Lamar and Forney Acquisition in April 2016 (see Note 3) and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.
Pursuant to the TRA, we issued the TRA Rights for the benefit of the first lien secured creditors of our Predecessor entitled to receive such TRA Rights under the Plan. Such TRA Rights are subject to various transfer restrictions described in the TRA and are entitled to certain registration rights more fully described in the Registration Rights Agreement (see Note 14).
During the three months ended September 30, 2017, we recorded a reduction to the carrying value of the TRA obligation of approximately $160 million. The reduction to the TRA obligation resulted from changes in the estimated timing of TRA payments resulting from changes in certain tax assumptions including (a) the impacts of Luminant's plan to retire its Monticello generation plant (see Note 17), (b) investment tax credits we expect to receive related to the Upton solar development project, (c) assets acquired in the Odessa Acquisition (see Note 3) and (d) the impacts of other forecasted tax amounts.
As of September 30, 2017, the estimated carrying value of the TRA obligation totaled $500 million, which represents the discounted amount of projected payments under the TRA. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate of 35% and (b) estimates of our taxable income in the current and future years. Our taxable income takes into consideration the current federal tax code and reflects our current estimates of future results of the business. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. The aggregate amount of undiscounted payments under the TRA is estimated to be approximately $2.2 billion, with approximately half of such amount expected to be attributable to the first 15 tax years following Emergence, and the final payment expected to be made approximately 40 years following Emergence (assuming that the TRA is not terminated earlier pursuant to its terms).
The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation. During the three and nine months ended September 30, 2017, the Impacts of Tax Receivable Agreement on the condensed statement of consolidated income (loss) totaled $138 million and $96 million, respectively, which represents the reduction to the carrying value of the TRA obligation discussed above net of accretion expense totaling $22 million and $64 million, respectively. The balance at September 30, 2017 and December 31, 2016 totaled $500 million and $596 million, respectively. The balance at September 30, 2017 included $24 million recorded to other current liabilities in the condensed consolidated balance sheet.
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Additionally, we expect to record an adjustment to the carrying value of the TRA obligation during the fourth quarter of 2017 as a result of the retirement announcements related to the Sandow 4, Sandow 5 and Big Brown generation units and the impacts of the Alcoa settlement (see Note 17).
7. | INTEREST EXPENSE AND RELATED CHARGES |
Successor | Predecessor | Successor | Predecessor | |||||||||||||||
Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | |||||||||||||||
Interest paid/accrued post-Emergence | $ | 52 | $ | — | $ | 157 | — | $ | — | |||||||||
Interest paid/accrued on debtor-in-possession financing | — | 38 | — | 76 | ||||||||||||||
Adequate protection amounts paid/accrued | — | 331 | — | 977 | ||||||||||||||
Unrealized mark-to-market net (gains) losses on interest rate swaps | (3 | ) | — | 3 | — | |||||||||||||
Reversal of debt extinguishment gain | 21 | — | — | — | ||||||||||||||
Capitalized interest | (1 | ) | (2 | ) | (5 | ) | (9 | ) | ||||||||||
Other | 7 | 4 | 14 | 5 | ||||||||||||||
Total interest expense and related charges | $ | 76 | $ | 371 | $ | 169 | $ | 1,049 | ||||||||||
Successor
During the three and nine months ended September 30, 2017, interest expense and related charges totaled $76 million and $169 million, respectively. The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 9, was 4.57% and 4.61% for the three and nine months ended September 30, 2017, respectively.
During the three months ended September 30, 2017, we identified and corrected an error that understated interest expense and related charges by $22 million for both the three months ended March 31, 2017 and the six months ended June 30, 2017. In February 2017, certain pricing terms for the Vistra Operations Credit facility were amended. This amendment was accounted for as an extinguishment of debt in the three months ended March 31, 2017. In the current period, we determined that the amendment should have been accounted for as a modification of debt. During the three months ended March 31, 2017, we recognized a noncash debt extinguishment gain totaling $21 million. The amendment should have been recorded as a net charge to interest expense totaling $1 million. Because the error and the correction of the error were not material to the previously issued condensed consolidated financial statements for the three months ended March 31, 2017 and the six months ended June 30, 2017, or to the condensed consolidated financial statements for the three months ended September 30, 2017, we have corrected the error in our condensed consolidated financial statements for the current period.
Predecessor
Interest expense for the three and nine months ended September 30, 2016 reflects interest paid and accrued on debtor-in-possession financing (see Note 9) and adequate protection amounts paid and accrued, as approved by the Bankruptcy Court in June 2014 for the benefit of secured creditors in exchange for their consent to the senior secured, super-priority liens contained in the DIP Facility. The interest rate applicable to the adequate protection amounts paid/accrued for the nine months ended September 30, 2016 was 4.95%.
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The Bankruptcy Code generally restricts payment of interest on pre-petition debt, subject to certain exceptions. Other than amounts ordered or approved by the Bankruptcy Court, effective on the Petition Date, our Predecessor 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 our condensed statements of consolidated income (loss) does not include contractual interest on pre-petition debt classified as LSTC totaling $213 million and $640 million for the three and nine months ended September 30, 2016, respectively, which had been stayed by the Bankruptcy Court effective on the Petition Date. Adequate protection amounts paid/accrued presented below excludes interest paid/accrued on TCEH first-lien interest rate and commodity hedge claims totaling $16 million and $47 million for the three and nine months ended September 30, 2016, respectively, as such amounts are not included in contractual interest amounts below.
Predecessor | |||||||
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | ||||||
Contractual interest on debt classified as LSTC | $ | 528 | $ | 1,570 | |||
Adequate protection amounts paid/accrued | 315 | 930 | |||||
Contractual interest on debt classified as LSTC not paid/accrued | $ | 213 | $ | 640 | |||
8. | EARNINGS PER SHARE |
Basic earnings per share available to common shareholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements.
Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | ||||||||||||||||||||
Net Income | Shares | Per Share Amount | Net Income | Shares | Per Share Amount | ||||||||||||||||
Net income available for common stock — basic | $ | 273 | 427,591,426 | $ | 0.64 | $ | 325 | 427,587,404 | $ | 0.76 | |||||||||||
Dilutive securities: | |||||||||||||||||||||
Stock-based incentive compensation plan | — | 721,012 | — | — | 414,465 | — | |||||||||||||||
Net income available for common stock — diluted | $ | 273 | 428,312,438 | $ | 0.64 | $ | 325 | 428,001,869 | $ | 0.76 | |||||||||||
For the three and nine months ended September 30, 2017, stock-based incentive compensation plan awards totaling 85,393 and 490,345 shares, respectively, were excluded from the calculation of diluted earnings per share because the effect would have been antidilutive.
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9. | LONG-TERM DEBT |
Successor
Amounts in the table below represent the categories of long-term debt obligations incurred by the Successor.
September 30, 2017 | December 31, 2016 | ||||||
Vistra Operations Credit Facilities (a) | $ | 4,484 | $ | 4,515 | |||
Mandatorily redeemable subsidiary preferred stock (b) | 70 | 70 | |||||
8.82% Building Financing due semiannually through February 11, 2022 (c) | 30 | 36 | |||||
Capital lease obligations | — | 2 | |||||
Total long-term debt including amounts due currently | 4,584 | 4,623 | |||||
Less amounts due currently | (44 | ) | (46 | ) | |||
Total long-term debt less amounts due currently | $ | 4,540 | $ | 4,577 | |||
____________
(a) | At September 30, 2017, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of $22 million, debt discounts of $2 million and debt issuance costs of $7 million. At December 31, 2016, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of $25 million, debt discounts of $2 million and debt issuance costs of $8 million. |
(b) | Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the spin-off of Vistra Energy from EFH Corp. (see Note 2). This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance. |
(c) | Obligation related to a corporate office space capital lease contributed to Vistra Energy pursuant to the Plan of Reorganization. This obligation will be funded by amounts held in an escrow account and reflected in other noncurrent assets in our condensed consolidated balance sheets. |
Vistra Operations Credit Facilities — The Vistra Operations Credit Facilities consist of up to $5.360 billion in senior secured, first lien financing consisting of a revolving credit facility of up to $860 million, including a $600 million letter of credit sub-facility (Revolving Credit Facility), an initial term loan facility of up to $2.850 billion (Initial Term Loan B Facility), an incremental term loan facility of up to $1.0 billion (Incremental Term Loan B Facility, and together with the Initial Term Loan B Facility, the Term Loan B Facility) and a term loan letter of credit facility of up to $650 million (Term Loan C Facility).
The Vistra Operations Credit Facilities and related available capacity at September 30, 2017 are presented below.
September 30, 2017 | ||||||||||||||
Vistra Operations Credit Facilities | Maturity Date | Facility Limit | Cash Borrowings | Available Capacity | ||||||||||
Revolving Credit Facility (a) | August 4, 2021 | $ | 860 | $ | — | $ | 860 | |||||||
Initial Term Loan B Facility (b)(c) | August 4, 2023 | 2,850 | 2,829 | — | ||||||||||
Incremental Term Loan B Facility (c) | December 14, 2023 | 1,000 | 992 | — | ||||||||||
Term Loan C Facility (d) | August 4, 2023 | 650 | 650 | 170 | ||||||||||
Total Vistra Operations Credit Facilities | $ | 5,360 | $ | 4,471 | $ | 1,030 | ||||||||
___________
(a) | Facility to be used for general corporate purposes. |
(b) | Facility used to repay all amounts outstanding under our Predecessor's DIP Facility and issuance costs for the DIP Roll Facilities, with the remaining balance used for general corporate purposes. |
(c) | Cash borrowings under the Term Loan B Facility reflect required scheduled quarterly payment in annual amount equal to 1% of the original principal amount with the balance paid at maturity. Amounts paid cannot be reborrowed. |
(d) | Facility used for issuing letters of credit for general corporate purposes. Borrowings under this facility were funded to collateral accounts that are reported as restricted cash in our condensed consolidated balance sheets. At September 30, 2017, the restricted cash supported $480 million in letters of credit outstanding (see Note 16), leaving $170 million in available letter of credit capacity. |
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In February and August 2017, certain pricing terms for the Vistra Operations Credit Facility were amended. We accounted for both of these transactions as modifications of debt. Amounts borrowed under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus 2.75%, and there were no outstanding borrowings at September 30, 2017. Amounts borrowed under the Initial Term Loan B Facility, the Incremental Term Loan B Facility and the Term Loan C Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 2.75%. At September 30, 2017, the weighted average interest rate before taking into consideration interest rate swaps on outstanding borrowings under the Initial Term Loan B Facility, the Incremental Term Loan B Facility and the Term Loan C Facility was 3.98%. The Vistra Operations Credit Facilities also provide 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 Vistra Operations Credit Facilities.
Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities.
The Vistra Operations Credit Facilities also permit certain hedging agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements met certain criteria set forth in the Vistra Operations Credit Facilities.
The Vistra Operations Credit Facilities provide for affirmative and negative covenants applicable to Vistra Operations (and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the agents under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case except as permitted in the Vistra Operations Credit Facilities. Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein.
The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $100 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the facilities, not to exceed 4.25 to 1.00. Although we had no borrowings under the Revolving Credit Facility as of September 30, 2017, we would have been in compliance with this financial covenant if it was required to be tested at such date. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.
Interest Rate Swaps — In the Successor period from October 3, 2016 through December 31, 2016, we entered into $3.0 billion notional amount of interest rate swaps to hedge a portion of our exposure to our variable rate debt. The interest rate swaps, which became effective in January 2017, expire in July 2023 and effectively fix the interest rates between 4.75% and 4.88% on $3.0 billion of our variable rate debt. The interest rate swaps are secured by a first lien secured interest on a pari-passu basis with the Vistra Operations Credit Facilities.
Predecessor
DIP Roll Facilities — In August 2016, the Predecessor entered into the DIP Roll Facilities. The facilities provided for up to $4.250 billion in senior secured, super-priority financing. The DIP Roll Facilities were senior, secured, super-priority debtor-in-possession credit agreements by and among the TCEH Debtors, the lenders that were party thereto from time to time and an administrative and collateral agent. On the Effective Date, the DIP Roll Facilities converted to the Vistra Operations Credit Facilities discussed above. Net proceeds from the DIP Roll Facilities were used to repay outstanding borrowings under the former DIP Facility, fund a collateral account used to backstop issuances of letters of credit and pay issuance costs. The remaining balance was used for general corporate purposes.
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DIP Facility — The DIP Facility provided for up to $3.375 billion in senior secured, super-priority financing. The DIP Facility was a senior, secured, super-priority credit agreement by and among the TCEH Debtors, the lenders that were party thereto from time to time and an administrative and collateral agent. As discussed above, in August 2016, all outstanding amounts under the DIP Facility were repaid using proceeds from the DIP Roll Facilities.
10. | COMMITMENTS AND CONTINGENCIES |
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of September 30, 2017, there are no material outstanding claims related to our guarantee obligations, and we do not anticipate we will be required to make any material payments under these guarantees.
Letters of Credit
At September 30, 2017, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling $480 million as follows:
• | $350 million to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ERCOT; |
• | $46 million to support executory contracts and insurance agreements; |
• | $55 million to support our REP financial requirements with the PUCT, and |
• | $29 million for other credit support requirements. |
Litigation
Litigation Related to EPA Reviews — In June 2008, the EPA issued an initial request for information to Luminant 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, Luminant received an additional information request from the EPA under Section 114 related to our Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to our Sandow 4 generation facility.
In July 2012, the EPA sent Luminant 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 August 2013, the US Department of Justice, acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant in federal district court in Dallas, alleging violations of the CAA, including its New Source Review standards, at our Big Brown and Martin Lake generation facilities. In August 2015, the district court granted Luminant's motion to dismiss seven of the nine claims asserted by the EPA in the lawsuit. In August 2016, the EPA filed an amended complaint, eliminating one of the two remaining claims and withdrawing with prejudice a request for civil penalties in the other remaining claim. The EPA also filed a motion for entry of final judgment so that it could seek to appeal the district court's dismissal decision. In September 2016, Luminant filed a response opposing the EPA's motion for entry of final judgment. In October 2016, the district court denied the EPA's motion for entry of final judgment and agreed that the remaining claim must be fully adjudicated at the district court or withdrawn with prejudice before the EPA may appeal the dismissal decision.
In January 2017, the EPA dismissed its two remaining claims with prejudice and the district court entered final judgment in our favor. In March 2017, the EPA and the Sierra Club appealed the final judgment to the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) and Luminant filed a motion in the district court to recover its attorney fees and costs. In April 2017, the district court stayed its consideration of Luminant's motion for attorney fees. In June 2017, the EPA and the Sierra Club filed their opening briefs in the Fifth Circuit Court. Luminant filed its response brief in August 2017. In September 2017, the EPA and the Sierra Club filed their reply briefs. The case has not yet been set for oral argument. 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 or retirement of the plants at issue and could possibly require the payment of substantial penalties. We cannot predict the outcome of these proceedings, including the financial effects, if any.
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Greenhouse Gas Emissions
In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from new, modified and reconstructed and existing electricity generation units, referred to as the Clean Power Plan. The rule for existing facilities would establish state-specific emissions rate goals to reduce nationwide CO2 emissions related to affected units by over 30% from 2012 emission levels by 2030. A number of parties, including Luminant, filed petitions for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) for the rule for new, modified and reconstructed plants. In addition, a number of petitions for review of the rule for existing plants were filed in the D.C. Circuit Court by various parties and groups, including challenges from twenty-seven different states opposed to the rule as well as those from, among others, certain power generating companies, various business groups and some labor unions. Luminant also filed its own petition for review. In January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the US Supreme Court (Supreme Court) asking that the Supreme Court stay the rule while the D.C. Circuit Court reviews the legality of the rule for existing plants. In February 2016, the Supreme Court stayed the rule pending the conclusion of legal challenges on the rule before the D.C. Circuit Court and until the Supreme Court disposes of any subsequent petition for review. Oral argument on the merits of the legal challenges to the rule were heard in September 2016 before the entire D.C. Circuit Court.
In March 2017, President Trump issued an Executive Order entitled Promoting Energy Independence and Economic Growth (Order). The Order covers a number of matters, including the Clean Power Plan. Among other provisions, the Order directs the EPA to review the Clean Power Plan and, if appropriate, suspend, revise or rescind the rules on existing and new, modified and reconstructed generating units. In April 2017, in accordance with the Order, the EPA published its intent to review the Clean Power Plan. In addition, the Department of Justice has filed motions seeking to abate those cases until the EPA concludes its review of the rules, including any new rulemaking that results from that review. In April 2017, the D.C. Circuit Court issued orders holding the cases in abeyance for 60 days and directing the EPA to provide status reports at 30 day intervals. The D.C. Circuit Court further ordered that all parties file supplemental briefs in May 2017 on whether the cases should be remanded to the EPA rather than held in abeyance. The 60-day abeyance expired in June 2017, and the D.C. Circuit Court has yet to take further action. In October 2017, the EPA issued a proposed rule that would rescind the Clean Power Plan. The proposed repeal focuses on what the EPA believes to be the unlawful nature of the Clean Power Plan and asks for public comment on the EPA's interpretations of its authority under the Clean Air Act. We currently plan to submit comments in response to the proposed repeal. While we cannot predict the outcome of these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, if the rules are ultimately implemented or upheld as they were issued, they could have a material impact on our results of operations, liquidity or financial condition.
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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).
The CSAPR became effective January 1, 2015. In July 2015, following a remand of the case from the Supreme Court to consider further legal challenges, the D.C. Circuit Court unanimously ruled in favor of Luminant 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 Luminant planned to participate in the EPA's reconsideration process to develop increased budgets for the 1997 ozone standard that do not over-control Texas, the EPA instead responded to the remand by proposing a new rulemaking that created new NOX ozone season budgets for the 2008 ozone standard without addressing the over-controlling budgets for the 1997 standard. Comments on the EPA's proposal were submitted by Luminant in February 2016. In August 2016, the EPA disapproved Texas's 2008 ozone State Implementation Plan (SIP) submittal and imposed a Federal Implementation Plan (FIP) in its place in October 2016. Texas filed a petition in the Fifth Circuit Court challenging the SIP disapproval and Luminant has intervened in support of Texas's challenge. The State of Texas and Luminant have also both filed challenges in the D.C. Circuit Court challenging the EPA's FIP and those cases are currently pending before that court. With respect to Texas's SO2 emission budgets, in June 2016, the EPA issued a memorandum describing the EPA's proposed approach for responding to the D.C. Circuit Court's remand for reconsideration of the CSAPR SO2 emission budgets for Texas and three other states that had been remanded to the EPA by the D.C. Circuit Court. In the memorandum, the EPA stated that those four states could either voluntarily participate in the CSAPR by submitting a SIP revision adopting the SO2 budgets that had been previously held invalid by the D.C. Circuit Court and the current annual NOX budgets or, if the state chooses not to participate in the CSAPR, the EPA could withdraw the CSAPR FIP by the fall of 2016 for those states and address any interstate transport and regional haze obligations on a state-by-state basis. Texas has not indicated that it intends to adopt the over-controlling budgets and, in November 2016, the EPA proposed to withdraw the CSAPR FIP for Texas. In September 2017, the EPA finalized its proposal to remove Texas from the annual CSAPR programs. As a result, Texas electric generating units are no longer subject to the CSAPR annual SO2 and NOX limits, but remain subject to the CSAPR's ozone season NOX requirements. While we cannot predict the outcome of future proceedings related to the CSAPR, including the EPA's recent actions concerning the CSAPR annual emissions budgets for affected states and participating in the CSAPR program, based upon our current operating plans we do not believe that the CSAPR itself will cause any material operational, financial or compliance issues to our business or require us to incur any material compliance costs.
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Regional Haze — Reasonable Progress and Long-Term Strategies
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. In February 2009, the TCEQ submitted a 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 that the EPA proposed in July 2011. The EPA finalized the limited disapproval in June 2012. In August 2012, Luminant 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, Luminant 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 FIP regarding the regional haze best available retrofit technology (BART) program. The Fifth Circuit Court case has since been transferred to the D.C. Circuit Court and consolidated with other pending BART program regional haze appeals. Briefing in the D.C. Circuit Court was completed in March 2017.
In June 2014, the EPA issued requests for information under Section 114 of the CAA to Luminant and other generators in Texas related to the reasonable progress program. 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 issued 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. The EPA's emission limits in the FIP assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven electricity generating units and upgrades to existing scrubbers at seven generation units. Specifically, for Luminant, the EPA's FIP is 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. Under the terms of the rule, subject to the legal proceedings described in the following paragraph, the scrubber upgrades would be required by February 2019, and the new scrubbers would 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 Fifth Circuit Court challenging the FIP's Texas requirements. Luminant and other parties also filed motions to stay the FIP while the court reviews the legality of the EPA's action. In July 2016, the Fifth Circuit Court denied the EPA's motion to dismiss Luminant's challenge to the FIP and denied the EPA's motion to transfer the challenges Luminant, the other industry petitioners and the State of Texas filed to the D.C. Circuit Court. In addition, the Fifth Circuit Court granted the motions to stay filed by Luminant, the other industry petitioners and the State of Texas pending final review of the petitions for review. The case was abated until the end of November 2016 in order to allow the parties to pursue settlement discussions. Settlement discussions were unsuccessful, and in December 2016 the EPA filed a motion seeking a voluntary remand of the rule back to the EPA for further consideration of Luminant's pending request for administrative reconsideration. Luminant and some of the other petitioners filed a response opposing the EPA's motion to remand and filed a cross motion for vacatur of the rule in December 2016. In March 2017, the Fifth Circuit Court remanded the rule back to the EPA for reconsideration in light of the Court's prior determination that we and the other petitioners demonstrated a substantial likelihood that the EPA exceeded its statutory authority and acted arbitrarily and capriciously, but the Court denied all of the other pending motions. The stay of the rule (and the emission control requirements) remains in effect. In addition, the Fifth Circuit Court denied the EPA's motion to lift the stay as to parts of the rule implicated in the EPA's subsequent BART proposal and the Court is retaining jurisdiction of the case and requiring the EPA to file status reports on its reconsideration every 60 days. While we cannot predict the outcome of the rulemaking and legal proceedings, or estimate a range of reasonably possible costs, the result may have a material impact on our results of operations, liquidity or financial condition.
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Regional Haze — Best Available Retrofit Technology
The second part of the Regional Haze Program subjects certain electricity generation units built between 1962 and 1977, to BART standards designed to improve visibility if such units cause or contribute to impairment of visibility in a federal class I area. 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 or other approved alternative program. 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 had until December 2016 to propose, and had until September 2017 to finalize, either approval of the state plan or a FIP for BART for Texas electricity generation sources if the EPA determines that BART requirements have not been met. The EPA issued a proposed BART FIP for Texas in January 2017. The EPA's proposed emission limits assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at 12 electric generation units and upgrades to existing scrubbers at four electric generation units. Specifically, for Luminant, the EPA's proposed emission limitations were 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 and Monticello Unit 3. Luminant evaluated the requirements and potential financial and operational impacts of the proposed rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the FIP (if those limits are possible to attain), along with the existence of low wholesale power prices in ERCOT, would challenge the long-term economic viability of those units. Under the terms of the proposed rule, the scrubber upgrades would have been required within three years of the effective date of the final rule and the new scrubbers will be required within five years of the effective date of the final rule. We submitted comments on the proposed FIP in May 2017.
The EPA signed the final BART FIP for Texas in September 2017. The rule is a partial approval of Texas's 2009 SIP and a partial FIP. In response to comments on the proposed rule submitted to the EPA, for SO2, the rule creates an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The program includes 39 generating units, including our Martin Lake, Big Brown, Monticello, Sandow 4, Stryker 2 and Graham 2 plants. Of the 39 units, 30 are BART-eligible, three are co-located with a BART-eligible unit and six units are included in the program based on a visibility impacts analysis by the EPA. The 39 units represent 89% of SO2 emissions from Texas electric generating units in 2016 and 85% of all CSAPR SO2 allowance allocations for Texas existing electric generating units. The compliance obligations in the program will start on January 1, 2019. The identified units will receive an annual allowance allocation that is equal to their current annual CSAPR SO2 allocation. Luminant's units covered by the program are allocated 91,222 allowances annually. Under the rule, a unit that is listed that does not operate for two consecutive years starting after 2018 would no longer receive allowances after the fifth year of non-operation. While we are still analyzing the rule, we believe the recent retirement announcement for our Monticello, Big Brown (if not sold) and Sandow 4 plants (see Note 17) will enhance our ability to comply with this BART rule for SO2. For NOX, the rule adopts the CSAPR's ozone program as BART and for particulate matter, the rule approves Texas's SIP that determines that no electric generating units are subject to particulate matter BART. While we cannot predict the outcome of the rulemaking and potential legal proceedings, we believe the rule, if ultimately implemented or upheld as issued, will not have a material impact on our results of operation, liquidity or financial condition.
Intersection of the CSAPR and Regional Haze Programs
Historically the EPA has considered compliance with a regional trading program, such as the CSAPR, as satisfying a state's obligations under the BART portion of the Regional Haze Program. However, in the reasonable progress FIP, the EPA diverged from this approach and did not treat Texas' 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 given the remand of the CSAPR budgets. As described above, the EPA has now removed Texas from the annual CSAPR trading programs and has issued a final BART FIP for Texas.
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Affirmative Defenses During Malfunctions
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 that was found to be lawful by the Fifth Circuit Court in 2013. 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, Luminant 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 was completed in October 2016 and oral argument was originally set for May 2017. However, in April 2017, the court granted the EPA's motion to continue oral argument and ordered that the case be held in abeyance with the EPA to provide status reports to the court on the EPA's review of the action at 90-day intervals. We cannot predict the timing or outcome of this proceeding, or estimate a range of reasonably possible costs, but implementation of the rule as finalized may have a material impact on our results of operations, liquidity or financial condition.
SO2 Designations for Texas
In February 2016, the EPA notified Texas of the EPA's preliminary intention to designate nonattainment areas for counties surrounding our Big Brown, Monticello and Martin Lake generation plants based on modeling data submitted to the EPA by the Sierra Club. Such designation would potentially require the implementation of various controls or other requirements to demonstrate attainment. Luminant submitted comments challenging the use of modeling data rather than data from actual air quality monitoring equipment. In November 2016, the EPA finalized its proposed designations for Texas including finalizing the nonattainment designations for the areas referenced above. In doing so, the EPA ignored contradictory modeling that we submitted with our comments. The final designation mandates would be for Texas to begin the multi-year process to evaluate what potential emission controls or operational changes, if any, may be necessary to demonstrate attainment. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court and protective petitions in the D.C. Circuit Court. In March 2017, the EPA filed a motion to transfer or dismiss our Fifth Circuit Court petition, and the State of Texas and Luminant filed an opposition to that motion. Briefing on that motion in the Fifth Circuit Court was completed in May 2017, and the Fifth Circuit Court held oral argument on that motion in July 2017. In August 2017, the Fifth Circuit Court denied the EPA's motion to transfer our challenge to the D.C. Circuit Court. In October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance in light of the EPA's representation that it was considering granting Luminant's request that the EPA reconsider the rule. In addition, with respect to Monticello and Big Brown (if that plant is retired and not sold), the retirement of those plants should favorably impact our legal challenge to the nonattainment designations in that the nonattainment designation for Freestone County and Titus County are based solely on the Sierra Club modeling of alleged SO2 emissions from Big Brown and Monticello. We dispute the Sierra Club's modeling. Regardless, considering these retirement announcements, the nonattainment designation for those counties are no longer supported. While we cannot predict the outcome of this matter, or estimate a range of reasonably possible costs, the result may have a material impact on our results of operations, liquidity or financial condition.
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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11. | EQUITY |
Successor Shareholders' Equity
Vistra Energy did not declare or pay any dividends during the nine months ended September 30, 2017. The agreement governing the Vistra Operations Credit Facilities (the Credit Facilities Agreement) generally restricts the ability of Vistra Operations Company LLC (Vistra Operations) to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of September 30, 2017, Vistra Operations can distribute approximately $980 million to Vistra Energy Corp. (Parent) under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was reduced by approximately $67 million and $537 million due to net distributions made by Vistra Operations to Parent during the three and nine months ended September 30, 2017, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses.
Under applicable Delaware General Corporate Law, we are prohibited from paying any distribution to the extent that such distribution exceeds the value of our "surplus," which is defined as the excess of our net assets above our capital (the aggregate par value of all outstanding shares of our stock).
The following table presents the changes to shareholder's equity for the nine months ended September 30, 2017:
Vistra Energy Shareholders' Equity | |||||||||||||||||||
Common Stock (a) | Additional Paid-in Capital | Retained Earnings (Deficit) | Accumulated Other Comprehensive Income | Total Shareholders' Equity | |||||||||||||||
Balance at December 31, 2016 | $ | 4 | $ | 7,742 | $ | (1,155 | ) | $ | 6 | $ | 6,597 | ||||||||
Net income | — | — | 325 | — | 325 | ||||||||||||||
Effects of stock-based incentive compensation plans | — | 13 | — | — | 13 | ||||||||||||||
Balance at September 30, 2017 | $ | 4 | $ | 7,755 | $ | (830 | ) | $ | 6 | $ | 6,935 | ||||||||
________________
(a) | Authorized shares totaled 1,800,000,000 at September 30, 2017. Outstanding shares totaled 427,597,368 and 427,580,232 at September 30, 2017 and December 31, 2016, respectively. |
Predecessor Membership Interests
The following table presents the changes to membership interests for the nine months ended September 30, 2016:
TCEH Membership Interests | |||||||||||
Capital Account | Accumulated Other Comprehensive Loss | Total Membership Interests | |||||||||
Balance at December 31, 2015 | $ | (22,851 | ) | $ | (33 | ) | $ | (22,884 | ) | ||
Net loss | (656 | ) | — | (656 | ) | ||||||
Net effects of cash flow hedges | — | 1 | 1 | ||||||||
Balance at September 30, 2016 | $ | (23,507 | ) | $ | (32 | ) | $ | (23,539 | ) | ||
12. | FAIR VALUE MEASUREMENTS |
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. 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 and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group.
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Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance risk. These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 13 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.
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. Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative exchanges) futures and options transacted through clearing brokers for which prices are actively quoted. We report the fair value of CME and ICE transactions without taking into consideration margin deposits, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that, beginning in January 2017, are legally characterized as settlement of derivative contracts rather than collateral. |
• | 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 such as interest rates and yield curves observable at commonly quoted intervals. We attempt to obtain multiple quotes from brokers that are active in the markets in which we participate and require at least one quote from two brokers to determine a pricing input as observable. 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. |
• | 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. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing delivery periods and locations and credit-related nonperformance risk assumptions. These inputs and valuation models are developed and maintained by employees trained and experienced in market operations and fair value measurements and validated by the Company's risk management group. |
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.
Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below:
September 30, 2017 | |||||||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | |||||||||||||||
Assets: | |||||||||||||||||||
Commodity contracts | $ | 27 | $ | 90 | $ | 182 | $ | 3 | $ | 302 | |||||||||
Interest rate swaps | — | 2 | — | 7 | 9 | ||||||||||||||
Nuclear decommissioning trust – equity securities (c) | 486 | — | — | — | 486 | ||||||||||||||
Nuclear decommissioning trust – debt securities (c) | — | 365 | — | — | 365 | ||||||||||||||
Sub-total | $ | 513 | $ | 457 | $ | 182 | $ | 10 | 1,162 | ||||||||||
Assets measured at net asset value (d): | |||||||||||||||||||
Nuclear decommissioning trust – equity securities (c) | 281 | ||||||||||||||||||
Total assets | $ | 1,443 | |||||||||||||||||
Liabilities: | |||||||||||||||||||
Commodity contracts | $ | 28 | $ | 25 | $ | 25 | $ | 3 | $ | 81 | |||||||||
Interest rate swaps | — | 16 | — | 7 | 23 | ||||||||||||||
Total liabilities | $ | 28 | $ | 41 | $ | 25 | $ | 10 | $ | 104 | |||||||||
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December 31, 2016 | |||||||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | |||||||||||||||
Assets: | |||||||||||||||||||
Commodity contracts | $ | 167 | $ | 131 | $ | 98 | $ | — | $ | 396 | |||||||||
Interest rate swaps | — | 5 | — | 13 | 18 | ||||||||||||||
Nuclear decommissioning trust – equity securities (c) | 425 | — | — | — | 425 | ||||||||||||||
Nuclear decommissioning trust – debt securities (c) | — | 340 | — | — | 340 | ||||||||||||||
Sub-total | $ | 592 | $ | 476 | $ | 98 | $ | 13 | 1,179 | ||||||||||
Assets measured at net asset value (d): | |||||||||||||||||||
Nuclear decommissioning trust – equity securities (c) | 247 | ||||||||||||||||||
Total assets | $ | 1,426 | |||||||||||||||||
Liabilities: | |||||||||||||||||||
Commodity contracts | $ | 302 | $ | 15 | $ | 15 | $ | — | $ | 332 | |||||||||
Interest rate swaps | — | 16 | — | 13 | 29 | ||||||||||||||
Total liabilities | $ | 302 | $ | 31 | $ | 15 | $ | 13 | $ | 361 | |||||||||
____________
(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 our condensed consolidated balance sheets. |
(c) | The nuclear decommissioning trust investment is included in the other investments line in our condensed consolidated balance sheets. See Note 16. |
(d) | The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our condensed consolidated balance sheets. 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. |
Commodity contracts consist primarily of natural gas, electricity, coal, fuel oil and uranium agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as normal purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 13 for further discussion regarding derivative instruments.
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.
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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 September 30, 2017 and December 31, 2016:
September 30, 2017 | ||||||||||||||||||
Fair Value | ||||||||||||||||||
Contract Type (a) | Assets | Liabilities | Total | Valuation Technique | Significant Unobservable Input | Range (b) | ||||||||||||
Electricity purchases and sales | $ | 101 | $ | (8 | ) | $ | 93 | Valuation Model | Hourly price curve shape (c) | $0 to $35/ MWh | ||||||||
Illiquid delivery periods for ERCOT hub power prices and heat rates (d) | $20 to $60/ MWh | |||||||||||||||||
Electricity options | 33 | (13 | ) | 20 | Option Pricing Model | Gas to power correlation (e) | 30% to 95% | |||||||||||
Power volatility (e) | 5% to 180% | |||||||||||||||||
Electricity congestion revenue rights | 35 | (4 | ) | 31 | Market Approach (f) | Illiquid price differences between settlement points (g) | $0 to $15/ MWh | |||||||||||
Other (h) | 13 | — | 13 | |||||||||||||||
Total | $ | 182 | $ | (25 | ) | $ | 157 | |||||||||||
December 31, 2016 | ||||||||||||||||||
Fair Value | ||||||||||||||||||
Contract Type (a) | Assets | Liabilities | Total | Valuation Technique | Significant Unobservable Input | Range (b) | ||||||||||||
Electricity purchases and sales | $ | 32 | $ | — | $ | 32 | Valuation Model | Hourly price curve shape (c) | $0 to $35/ MWh | |||||||||
Illiquid delivery periods for ERCOT hub power prices and heat rates (d) | $30 to $70/ MWh | |||||||||||||||||
Electricity congestion revenue rights | 42 | (6 | ) | 36 | Market Approach (f) | Illiquid price differences between settlement points (g) | $0 to $10/ MWh | |||||||||||
Other (h) | 24 | (9 | ) | 15 | ||||||||||||||
Total | $ | 98 | $ | (15 | ) | $ | 83 | |||||||||||
____________
(a) | Electricity purchase and sales contracts include power and heat rate positions in ERCOT regions. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. Electricity options consist of physical electricity options and spread options. |
(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 hourly ERCOT North Hub prices. |
(d) | Based on historical forward ERCOT power price and heat rate variability. |
(e) | Based on historical forward correlation and volatility within ERCOT. |
(f) | While we use the market approach, there is insufficient market data to consider the valuation liquid. |
(g) | Based on the historical price differences between settlement points within ERCOT hubs and load zones. |
(h) | Other includes contracts for natural gas, coal and coal options. December 31, 2016 also includes an immaterial amount of electricity options. |
There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the three and nine months ended September 30, 2017 and 2016. See the table below for discussion of transfers between Level 2 and Level 3 for the three and nine months ended September 30, 2017 and 2016.
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The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and nine months ended September 30, 2017 and 2016.
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | ||||||||||||||
Net asset (liability) balance at beginning of period | $ | 75 | $ | (9 | ) | $ | 83 | $ | 37 | ||||||||
Total unrealized valuation gains (losses) | 132 | 126 | 139 | 122 | |||||||||||||
Purchases, issuances and settlements (a): | |||||||||||||||||
Purchases | 16 | 11 | 51 | 37 | |||||||||||||
Issuances | (5 | ) | (4 | ) | (19 | ) | (20 | ) | |||||||||
Settlements | (45 | ) | (24 | ) | (87 | ) | (51 | ) | |||||||||
Transfers into Level 3 (b) | — | — | 4 | 1 | |||||||||||||
Transfers out of Level 3 (b) | — | — | 2 | 1 | |||||||||||||
Earn-out provision (c) | (16 | ) | — | (16 | ) | — | |||||||||||
Net liabilities assumed in the Lamar and Forney Acquisition (Note 3) | — | (3 | ) | — | (30 | ) | |||||||||||
Net change (d) | 82 | 106 | 74 | 60 | |||||||||||||
Net asset balance at end of period | $ | 157 | $ | 97 | $ | 157 | $ | 97 | |||||||||
Unrealized valuation gains relating to instruments held at end of period | $ | 106 | $ | 92 | $ | 110 | $ | 98 | |||||||||
____________
(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. All Level 3 transfers during the periods presented are in and out of Level 2. |
(c) | Represents initial fair value of the earn-out provision incurred as part of the Odessa Acquisition. See Note 3. |
(d) | Substantially all changes in value of commodity contracts (excluding the initial fair value of the earn-out provision related to the Odessa Acquisition in 2017 and the net liability assumed in the Lamar and Forney Acquisition in 2016) are reported as operating revenues in our condensed statements of consolidated income (loss). Activity excludes change in fair value in the month positions settle. |
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13. | COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES |
Strategic Use of Derivatives
We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price and interest rate risk. See Note 12 for a discussion of the fair value of derivatives.
Commodity Hedging and Trading Activity — We utilize natural gas and electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets. We also utilize short-term electricity, natural gas, coal, fuel oil and uranium derivative instruments for fuel hedging and other purposes. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy marketing companies. Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in our condensed statements of consolidated income (loss) in operating revenues and fuel, purchased power costs and delivery fees in the Successor period and net gain from commodity hedging and trading activities in the Predecessor period.
Interest Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in our condensed statements of consolidated income (loss) in interest expense and related charges.
Financial Statement Effects of Derivatives
Substantially all derivative contractual assets and liabilities are accounted for under 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 our condensed consolidated balance sheets at September 30, 2017 and December 31, 2016. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.
September 30, 2017 | |||||||||||||||||||
Derivative Assets | Derivative Liabilities | ||||||||||||||||||
Commodity Contracts | Interest Rate Swaps | Commodity Contracts | Interest Rate Swaps | Total | |||||||||||||||
Current assets | $ | 181 | $ | — | $ | 1 | $ | — | $ | 182 | |||||||||
Noncurrent assets | 120 | 9 | — | — | 129 | ||||||||||||||
Current liabilities | (2 | ) | (7 | ) | (53 | ) | (10 | ) | (72 | ) | |||||||||
Noncurrent liabilities | — | — | (26 | ) | (6 | ) | (32 | ) | |||||||||||
Net assets (liabilities) | $ | 299 | $ | 2 | $ | (78 | ) | $ | (16 | ) | $ | 207 | |||||||
December 31, 2016 | |||||||||||||||||||
Derivative Assets | Derivative Liabilities | ||||||||||||||||||
Commodity Contracts | Interest Rate Swaps | Commodity Contracts | Interest Rate Swaps | Total | |||||||||||||||
Current assets | $ | 350 | $ | — | $ | — | $ | — | $ | 350 | |||||||||
Noncurrent assets | 46 | 17 | — | 1 | 64 | ||||||||||||||
Current liabilities | — | (12 | ) | (330 | ) | (17 | ) | (359 | ) | ||||||||||
Noncurrent liabilities | — | — | (2 | ) | — | (2 | ) | ||||||||||||
Net assets (liabilities) | $ | 396 | $ | 5 | $ | (332 | ) | $ | (16 | ) | $ | 53 | |||||||
At September 30, 2017 and December 31, 2016, there were no derivative positions accounted for as cash flow or fair value hedges.
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The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized effects:
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Derivative (condensed statements of consolidated income (loss) presentation) | Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | |||||||||||||
Commodity contracts (Operating revenues) (a) | $ | 166 | $ | — | $ | 333 | $ | — | |||||||||
Commodity contracts (Fuel, purchased power costs and delivery fees) (a) | 9 | — | 3 | — | |||||||||||||
Commodity contracts (Net gain from commodity hedging and trading activities) (a) | — | 239 | — | 194 | |||||||||||||
Interest rate swaps (Interest expense and related charges) (b) | (4 | ) | — | (24 | ) | — | |||||||||||
Net gain (loss) | $ | 171 | $ | 239 | $ | 312 | $ | 194 | |||||||||
____________
(a) | Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts. |
(b) | Includes unrealized mark-to-market net gains as well as the net realized effect on interest paid/accrued, both reported in Interest Expense and Related Charges (see Note 7). |
In conjunction with fresh start reporting, the balances in accumulated other comprehensive income were eliminated from our condensed consolidated balance sheet on the Effective Date. The pretax effect (all losses) on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges by the Predecessor was immaterial in the three and nine months ended September 30, 2016. There were no amounts recognized in OCI for the three and nine months ended September 30, 2017.
Balance Sheet Presentation of Derivatives
We elect to report derivative assets and liabilities in our condensed consolidated balance sheets on a gross basis without taking into consideration netting arrangements we have with counterparties to those derivatives. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset assets and liabilities and collateral 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.
Generally, margin deposits that contractually offset these derivative instruments are reported separately in our condensed consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that, beginning in January 2017, are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes.
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The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
September 30, 2017 | December 31, 2016 | |||||||||||||||||||||||||||||||
Derivative Assets and Liabilities | Offsetting Instruments (a) | Cash Collateral (Received) Pledged (b) | Net Amounts | Derivative Assets and Liabilities | Offsetting Instruments (a) | Cash Collateral (Received) Pledged (b) | Net Amounts | |||||||||||||||||||||||||
Derivative assets: | ||||||||||||||||||||||||||||||||
Commodity contracts | $ | 299 | $ | (64 | ) | $ | (9 | ) | $ | 226 | $ | 396 | $ | (193 | ) | $ | (20 | ) | $ | 183 | ||||||||||||
Interest rate swaps | 2 | — | — | 2 | 5 | — | — | 5 | ||||||||||||||||||||||||
Total derivative assets | 301 | (64 | ) | (9 | ) | 228 | 401 | (193 | ) | (20 | ) | 188 | ||||||||||||||||||||
Derivative liabilities: | ||||||||||||||||||||||||||||||||
Commodity contracts | (78 | ) | 64 | 1 | (13 | ) | (332 | ) | 193 | 136 | (3 | ) | ||||||||||||||||||||
Interest rate swaps | (16 | ) | — | — | (16 | ) | (16 | ) | — | — | (16 | ) | ||||||||||||||||||||
Total derivative liabilities | (94 | ) | 64 | 1 | (29 | ) | (348 | ) | 193 | 136 | (19 | ) | ||||||||||||||||||||
Net amounts | $ | 207 | $ | — | $ | (8 | ) | $ | 199 | $ | 53 | $ | — | $ | 116 | $ | 169 | |||||||||||||||
____________
(a) | Amounts presented exclude trade accounts receivable and payable related to settled financial instruments. |
(b) | Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements and, to a lesser extent, initial margin requirements. |
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes at September 30, 2017 and December 31, 2016:
September 30, 2017 | December 31, 2016 | |||||||||
Derivative type | Notional Volume | Unit of Measure | ||||||||
Natural gas (a) | 1,420 | 1,282 | Million MMBtu | |||||||
Electricity | 106,190 | 75,322 | GWh | |||||||
Congestion Revenue Rights (b) | 96,269 | 126,573 | GWh | |||||||
Coal | 4 | 12 | Million US tons | |||||||
Fuel oil | 19 | 34 | Million gallons | |||||||
Uranium | 450 | 25 | Thousand pounds | |||||||
Interest rate swaps – floating/fixed (c) | $ | 3,000 | $ | 3,000 | Million US dollars | |||||
____________
(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. |
(c) | Includes notional amounts of interest rate swaps that became effective in January 2017 and have maturity dates through July 2023. |
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Credit Risk-Related Contingent Features of Derivatives
Our derivative contracts 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 or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:
September 30, 2017 | December 31, 2016 | ||||||
Fair value of derivative contract liabilities (a) | $ | (41 | ) | $ | (31 | ) | |
Offsetting fair value under netting arrangements (b) | 22 | 13 | |||||
Cash collateral and letters of credit | 1 | 1 | |||||
Liquidity exposure | $ | (18 | ) | $ | (17 | ) | |
____________
(a) | Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses). |
(b) | Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements. |
Concentrations of Credit Risk Related to Derivatives
We have concentrations of credit risk with the counterparties to our derivative contracts. At September 30, 2017, total credit risk exposure to all counterparties related to derivative contracts totaled $442 million (including associated accounts receivable). The net exposure to those counterparties totaled $337 million at September 30, 2017 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $68 million. At September 30, 2017, the credit risk exposure to the banking and financial sector represented 41% of the total credit risk exposure and 36% 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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14. | RELATED PARTY TRANSACTIONS |
Successor
In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares of common stock and TRA Rights in exchange for their claims.
Registration Rights Agreement
Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra Energy common stock held by such selling stockholders.
In December 2016, we filed a Form S-1 registration statement with the SEC to register for resale the shares of Vistra Energy common stock held by certain significant stockholders pursuant to the Registration Rights Agreement. The registration statement was amended in February 2017, April 2017 and May 2017. The registration statement was declared effective by the SEC in May 2017. Among other things, under the terms of the Registration Rights Agreement:
• | we will be required to use reasonable best efforts to convert the Form S-1 registration statement into a registration statement on Form S-3 as soon as reasonably practicable after we become eligible to do so and to have such Form S-3 declared effective as promptly as practicable (but in no event more than 30 days after it is filed with the SEC); |
• | if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the Registration Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the Registration Rights Agreement; and |
• | the selling stockholders received the right, subject to certain conditions and exceptions, to request that we file registration statements or amend or supplement registration statements, with the SEC for an underwritten offering of all or part of their respective shares of Vistra Energy common stock (a Demand Registration), and the Company is required to cause any such registration statement or amendment or supplement (a) to be filed with the SEC promptly and, in any event, on or before the date that is 45 days, in the case of a registration statement on Form S-1, or 30 days, in the case of a registration statement on Form S-3, after we receive the written request from the relevant selling stockholders to effectuate the Demand Registration and (b) to become effective as promptly as reasonably practicable and in any event no later than 120 days after it is initially filed. |
All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or on behalf of the selling stockholders, will be paid by us. Legal fee expenses paid or accrued by Vistra Energy on behalf of the selling stockholders totaled less than $1 million during both the three and nine months ended September 30, 2017.
Tax Receivable Agreement
On the Effective Date, Vistra Energy entered into the TRA with a transfer agent on behalf of certain former first lien creditors of TCEH. See Note 6 for discussion of the TRA.
Predecessor
See Note 2 for a discussion of certain agreements entered into on the Effective Date between EFH Corp. and Vistra Energy with respect to the separation of the entities, including a separation agreement, a transition services agreement, a tax matters agreement and a settlement agreement.
The following represent our Predecessor's significant related-party transactions. As of the Effective Date, pursuant to the Plan of Reorganization, the Sponsor Group, EFH Corp., EFIH, Oncor Holdings and Oncor ceased being affiliates of Vistra Energy and its subsidiaries, including the TCEH Debtors and the Contributed EFH Debtors.
• | Our retail operations (and prior to the Effective Date, our Predecessor) 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 $265 million and $700 million for the three and nine months ended September 30, 2016, respectively. |
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• | A former subsidiary of EFH Corp. billed our Predecessor's subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges, which are largely settled in cash and primarily reported in SG&A expenses, totaled $51 million and $157 million for the three and nine months ended September 30, 2016, respectively. |
• | 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 Vistra Energy (and prior to the Effective Date, our Predecessor) 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 asset retirement obligations in our condensed consolidated balance sheets. The delivery fee surcharges remitted to our Predecessor totaled $6 million and $15 million for the three and nine months ended September 30, 2016, respectively. Income and expenses associated with the trust fund and the decommissioning liability incurred by Vistra Energy (and prior to the Effective Date, our Predecessor) are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates. |
• | EFH Corp. files consolidated federal income tax and Texas state margin tax returns that included our results prior to the Effective Date; however, under a Federal and State Income Tax Allocation Agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., were recorded as if our Predecessor filed its own corporate income tax return. For the nine months ended September 30, 2016, our Predecessor made income tax payments totaling $22 million to EFH Corp. |
• | 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 TCEH and/or provided financial advisory services to TCEH, 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 our Predecessor 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 our Predecessor in open market transactions or through loan syndications. |
15. | SEGMENT INFORMATION |
The operations of Vistra Energy are aligned into two reportable business segments: Wholesale Generation and Retail Electricity. Our chief operating decision maker reviews the results of these two segments separately and allocates resources to the respective segments as part of our strategic operations. These two business units offer different products or services and involve different risks.
The Wholesale Generation segment is engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management, all largely in the ERCOT market. These activities are substantially all conducted by Luminant.
The Retail Electricity segment is engaged in retail sales of electricity and related services to residential, commercial and industrial customers, all largely in the ERCOT market. These activities are substantially all conducted by TXU Energy.
Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our Wholesale Generation and Retail Electricity segments.
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 December 31, 2016 audited financial statements. Our chief operating decision maker uses more than one measure to assess segment performance, including reported segment operating income and segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices. Certain shared services costs are allocated to the segments.
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Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | |||||||
Operating revenues (a) | ||||||||
Wholesale Generation | $ | 1,203 | $ | 2,757 | ||||
Retail Electricity | 1,286 | 3,136 | ||||||
Eliminations | (656 | ) | (1,406 | ) | ||||
Consolidated operating revenues | $ | 1,833 | $ | 4,487 | ||||
Depreciation and amortization | ||||||||
Wholesale Generation | $ | 60 | $ | 167 | ||||
Retail Electricity | 108 | 322 | ||||||
Corporate and Other | 10 | 30 | ||||||
Consolidated depreciation and amortization | $ | 178 | $ | 519 | ||||
Operating income (loss) | ||||||||
Wholesale Generation | $ | 469 | $ | 651 | ||||
Retail Electricity | (3 | ) | 54 | |||||
Corporate and Other | (14 | ) | (47 | ) | ||||
Consolidated operating income | $ | 452 | $ | 658 | ||||
Net income (loss) | ||||||||
Wholesale Generation | $ | 469 | $ | 653 | ||||
Retail Electricity | 7 | 77 | ||||||
Corporate and Other | (203 | ) | (405 | ) | ||||
Consolidated net income | $ | 273 | $ | 325 | ||||
____________
(a) | For the three and nine months ended September 30, 2017, includes third-party unrealized net gains from mark-to-market valuations of commodity positions of $137 million and $204 million, respectively, recorded to the Wholesale Generation segment and $2 million and $11 million, respectively, recorded to the Retail Electricity segment. In addition, for the three and nine months ended September 30, 2017, unrealized net gains with affiliate of $89 million and $171 million, respectively, were recorded to operating revenues for the Wholesale Generation segment and corresponding unrealized net losses with affiliate of $(89) million and $(171) million, respectively, were recorded to fuel, purchased power costs and delivery fees for the Retail Electricity segment, with no impact to consolidated results. |
September 30, 2017 | December 31, 2016 | ||||||
Total assets | |||||||
Wholesale Generation | $ | 7,445 | $ | 6,952 | |||
Retail Electricity | 5,926 | 5,753 | |||||
Corporate and Other and Eliminations | 1,629 | 2,462 | |||||
Consolidated total assets | $ | 15,000 | $ | 15,167 | |||
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16. | SUPPLEMENTARY FINANCIAL INFORMATION |
Other Income and Deductions
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | ||||||||||||||
Other income: | |||||||||||||||||
Office space sublease rental income (a) | $ | 3 | $ | — | $ | 9 | $ | — | |||||||||
Insurance settlement | — | — | — | 9 | |||||||||||||
Sale of land (b) | 1 | 2 | 4 | 2 | |||||||||||||
Interest income | 4 | 2 | 10 | 3 | |||||||||||||
All other | 2 | 3 | 6 | 5 | |||||||||||||
Total other income | $ | 10 | $ | 7 | $ | 29 | $ | 19 | |||||||||
Other deductions: | |||||||||||||||||
Write-off of generation equipment (b) | $ | — | $ | 4 | $ | 2 | $ | 45 | |||||||||
Adjustment to asbestos liability | — | 11 | — | 11 | |||||||||||||
Fees associated with TCEH DIP Roll Facilities | — | 5 | — | 5 | |||||||||||||
All other | — | 8 | 3 | 14 | |||||||||||||
Total other deductions | $ | — | $ | 28 | $ | 5 | $ | 75 | |||||||||
____________
(a) | Reported in Corporate and Other non-segment (Successor period only). |
(b) | Reported in Wholesale Generation segment (Successor period only). |
Restricted Cash
September 30, 2017 | December 31, 2016 | ||||||||||||||
Current Assets | Noncurrent Assets | Current Assets | Noncurrent Assets | ||||||||||||
Amounts related to the Vistra Operations Credit Facilities (Note 9) | $ | — | $ | 650 | $ | — | $ | 650 | |||||||
Amounts related to restructuring escrow accounts | 61 | — | 90 | — | |||||||||||
Other | — | — | 5 | — | |||||||||||
Total restricted cash | $ | 61 | $ | 650 | $ | 95 | $ | 650 | |||||||
Trade Accounts Receivable
September 30, 2017 | December 31, 2016 | ||||||
Wholesale and retail trade accounts receivable | $ | 738 | $ | 622 | |||
Allowance for uncollectible accounts | (21 | ) | (10 | ) | |||
Trade accounts receivable — net | $ | 717 | $ | 612 | |||
Gross trade accounts receivable at September 30, 2017 and December 31, 2016 included unbilled retail revenues of $250 million and $225 million, respectively.
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Allowance for Uncollectible Accounts Receivable
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | |||||||
Allowance for uncollectible accounts receivable at beginning of period | $ | 10 | $ | 9 | ||||
Increase for bad debt expense | 35 | 20 | ||||||
Decrease for account write-offs | (24 | ) | (16 | ) | ||||
Allowance for uncollectible accounts receivable at end of period | $ | 21 | $ | 13 | ||||
Inventories by Major Category
September 30, 2017 | December 31, 2016 | ||||||
Materials and supplies | $ | 172 | $ | 173 | |||
Fuel stock | 102 | 88 | |||||
Natural gas in storage | 21 | 24 | |||||
Total inventories | $ | 295 | $ | 285 | |||
Other Investments
September 30, 2017 | December 31, 2016 | ||||||
Nuclear plant decommissioning trust | $ | 1,132 | $ | 1,012 | |||
Land | 49 | 49 | |||||
Miscellaneous other | 2 | 3 | |||||
Total other investments | $ | 1,183 | $ | 1,064 | |||
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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 Vistra Energy (and prior to the Effective Date, a subsidiary of 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 receivable reported in noncurrent assets) that will ultimately be settled through changes in Oncor's delivery fees rates. The nuclear decommissioning trust fund was not a debtor in the Chapter 11 Cases. A summary of investments in the fund follows:
September 30, 2017 | |||||||||||||||
Cost (a) | Unrealized gain | Unrealized loss | Fair market value | ||||||||||||
Debt securities (b) | $ | 352 | $ | 14 | $ | (1 | ) | $ | 365 | ||||||
Equity securities (c) | 321 | 451 | (5 | ) | 767 | ||||||||||
Total | $ | 673 | $ | 465 | $ | (6 | ) | $ | 1,132 | ||||||
December 31, 2016 | |||||||||||||||
Cost (a) | Unrealized gain | Unrealized loss | Fair market value | ||||||||||||
Debt securities (b) | $ | 333 | $ | 10 | $ | (3 | ) | $ | 340 | ||||||
Equity securities (c) | 309 | 368 | (5 | ) | 672 | ||||||||||
Total | $ | 642 | $ | 378 | $ | (8 | ) | $ | 1,012 | ||||||
____________
(a) | Includes realized gains and losses on securities sold. |
(b) | The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's Investors Services, Inc. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 3.57% and 3.56% at September 30, 2017 and December 31, 2016, respectively, and an average maturity of 9 years at both September 30, 2017 and December 31, 2016. |
(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 September 30, 2017 mature as follows: $102 million in one to 5 years, $99 million in five to 10 years and $164 million after 10 years.
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | ||||||||||||||
Realized gains | $ | 1 | $ | 3 | $ | 3 | $ | 3 | |||||||||
Realized losses | $ | (1 | ) | $ | (2 | ) | $ | (3 | ) | $ | (2 | ) | |||||
Proceeds from sales of securities | $ | 56 | $ | 46 | $ | 154 | $ | 201 | |||||||||
Investments in securities | $ | (62 | ) | $ | (52 | ) | $ | (169 | ) | $ | (215 | ) | |||||
Property, Plant and Equipment
At September 30, 2017 and December 31, 2016, property, plant and equipment of $4.746 billion and $4.443 billion, respectively, is stated net of accumulated depreciation and amortization of $318 million and $85 million, respectively.
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Asset Retirement and Mining Reclamation Obligations (ARO)
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 delivery fees charged by Oncor. As part of fresh start reporting, new fair values were established for all AROs for the Successor.
At September 30, 2017, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.223 billion, which exceeds the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory asset has been recorded to our condensed consolidated balance sheet of $91 million in other noncurrent assets.
The following table summarizes the changes to these obligations, reported in other current liabilities and asset retirement obligations in our condensed consolidated balance sheets, for the nine months ended September 30, 2017:
Nuclear Plant Decommissioning | Mining Land Reclamation | Other | Total | ||||||||||||
Liability at December 31, 2016 | $ | 1,200 | $ | 375 | $ | 151 | $ | 1,726 | |||||||
Additions: | |||||||||||||||
Accretion | 23 | 14 | 4 | 41 | |||||||||||
Adjustment for change in estimates (a) | — | 3 | 4 | 7 | |||||||||||
Reductions: | |||||||||||||||
Payments | — | (23 | ) | — | (23 | ) | |||||||||
Liability at September 30, 2017 | 1,223 | 369 | 159 | 1,751 | |||||||||||
Less amounts due currently | — | (83 | ) | (2 | ) | (85 | ) | ||||||||
Noncurrent liability at September 30, 2017 | $ | 1,223 | $ | 286 | $ | 157 | $ | 1,666 | |||||||
____________
(a) | Relates to the impacts of accelerating the ARO associated with the planned retirement of the Monticello plant (see Note 17). |
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
September 30, 2017 | December 31, 2016 | ||||||
Unfavorable purchase and sales contracts | $ | 39 | $ | 46 | |||
Other, including retirement and other employee benefits | 193 | 174 | |||||
Total other noncurrent liabilities and deferred credits | $ | 232 | $ | 220 | |||
Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $2 million and $6 million for the three months ended September 30, 2017 and 2016, respectively, and $7 million and $18 million for the nine months ended September 30, 2017 and 2016, respectively. See Note 4 for intangible assets related to favorable purchase and sales contracts.
The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:
Year | Amount | |||
2017 | $ | 10 | ||
2018 | $ | 11 | ||
2019 | $ | 9 | ||
2020 | $ | 9 | ||
2021 | $ | 1 | ||
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Fair Value of Debt
September 30, 2017 | December 31, 2016 | |||||||||||||||
Debt: | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Long-term debt under the Vistra Operations Credit Facilities (Note 9) | $ | 4,484 | $ | 4,484 | $ | 4,515 | $ | 4,552 | ||||||||
Other long-term debt, excluding capital lease obligations (Note 9) | 30 | 27 | 36 | 32 | ||||||||||||
Mandatorily redeemable subsidiary preferred stock (Note 9) | 70 | 70 | 70 | 70 | ||||||||||||
We determine fair value in accordance with accounting standards as discussed in Note 12, and at September 30, 2017, 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.
Supplemental Cash Flow Information
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | |||||||
Cash payments related to: | ||||||||
Interest paid (a) | $ | 197 | $ | 1,064 | ||||
Capitalized interest | (5 | ) | (9 | ) | ||||
Interest paid (net of capitalized interest) (a) | $ | 192 | $ | 1,055 | ||||
Income taxes | $ | 51 | $ | 22 | ||||
Reorganization items (b) | $ | — | $ | 104 | ||||
Noncash investing and financing activities: | ||||||||
Construction expenditures (c) | $ | 16 | $ | 53 | ||||
____________
(a) | Predecessor period includes amounts paid for adequate protection. |
(b) | Represents cash payments made by our Predecessor for legal and other consulting services, including amounts paid on behalf of third parties pursuant to contractual obligations approved by the Bankruptcy Court. |
(c) | Represents end-of-period accruals for ongoing construction projects. |
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17. | SUBSEQUENT EVENTS |
Merger Agreement
On October 29, 2017, Vistra Energy and Dynegy Inc., a Delaware corporation (Dynegy), entered into an Agreement and Plan of Merger (the Merger Agreement). The following description of the Merger Agreement does not purport to be a complete description and is qualified in its entirety by reference to the full text of the Merger Agreement filed as Exhibit 2.1 to our Current Report on Form 8-K filed on October 31, 2017.
Upon the terms and subject to the conditions set forth in the Merger Agreement, which has been approved by the boards of directors of Vistra Energy and Dynegy, Dynegy will merge with and into Vistra Energy (the Merger), with Vistra Energy continuing as the surviving corporation. The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended (the Code), so that none of Vistra Energy, Dynegy or any of the Dynegy stockholders generally will recognize any gain or loss in the transaction, except that Dynegy stockholders will recognize gain with respect to cash received in lieu of fractional shares of Vistra Energy's common stock. We expect that Vistra Energy will be the acquirer for both federal tax and accounting purposes.
Upon the closing of the Merger, each issued and outstanding share of Dynegy common stock, par value $0.01 per share, other than shares owned by Vistra Energy or its subsidiaries, held in treasury by Dynegy or held by a subsidiary of Dynegy, will automatically be converted into the right to receive 0.652 shares of common stock, par value $0.01 per share, of Vistra Energy (the Exchange Ratio), except that cash will be paid in lieu of fractional shares, which we expect will result in Vistra Energy's stockholders and Dynegy's stockholders owning approximately 79% and 21%, respectively, of the combined company. Dynegy stock options and equity-based awards outstanding immediately prior to the Effective Time will generally automatically convert upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra Energy's common stock, after giving effect to the Exchange Ratio.
The Merger Agreement also provides that, upon the closing of the Merger, the board of directors of the combined company will be comprised of 11 members, consisting of (a) the eight current directors of Vistra Energy and (b) three of Dynegy's current directors, of whom one will be a Class I director, one will be a Class II director and one will be a Class III director, unless the closing of the Merger occurs after the date of Vistra Energy's 2018 Annual General Meeting, in which case one will be a Class I director and two will be Class II directors. Upon completion of the Merger, each of Curtis A. Morgan, currently a director and the President and Chief Executive Officer of Vistra Energy, Jim Burke, currently Chief Operating Officer of Vistra Energy, and J. William Holden, currently Chief Financial Officer of Vistra Energy, will continue in those roles at the combined company.
Completion of the Merger is subject to various customary conditions, including, among others, (a) approval by Vistra Energy's stockholders of the issuance of Vistra Energy's common stock in the Merger, (b) adoption of the Merger Agreement by Vistra Energy's stockholders and Dynegy's stockholders, (c) receipt of all requisite regulatory approvals, which includes approvals of the Federal Energy Regulatory Commission, the PUCT, the Federal Communications Commission and the New York Public Service Commission, and the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and (d) effectiveness of the registration statement for the shares of Vistra Energy's common stock to be issued in the Merger, and the approval of the listing of such shares on the New York Stock Exchange. Each party's obligation to consummate the Merger is also subject to certain additional customary conditions, including (i) subject to certain exceptions, the accuracy of the representations and warranties of the other party, (ii) performance in all material respects by the other party of its obligations under the Merger Agreement and (iii) the receipt by such party of an opinion from its counsel to the effect that the Merger will qualify as a tax-free reorganization within the meaning of the Code.
The Merger Agreement contains customary representations, warranties and covenants of Vistra Energy and Dynegy, including, among others, covenants (a) to conduct their respective businesses in the ordinary course during the interim period between the execution of the Merger Agreement and completion of the Merger, (b) not to take certain actions during the interim period except with the consent of the other party, (c) that Vistra Energy and Dynegy will convene and hold meetings of their respective stockholders to obtain the required stockholder approvals, and (d) that the parties use their respective reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals and consents (except that Vistra Energy shall not be required, and Dynegy shall not be permitted, to take any action that constitutes or would reasonably be expected to have certain specified burdensome effects). Each of Vistra Energy and Dynegy is also subject to restrictions on its ability to solicit alternative acquisition proposals and to provide information to, and engage in discussion with, third parties regarding such proposals, except under limited circumstances to permit Vistra Energy's and Dynegy's boards of directors to comply with their respective fiduciary duties.
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The Merger Agreement contains certain termination rights for both Vistra Energy and Dynegy, including in specified circumstances in connection with an alternative acquisition proposal that has been determined to be a superior offer. Upon termination of the Merger Agreement, under specified circumstances (a) for a failure by Vistra Energy to obtain certain requisite regulatory approvals, Vistra Energy may be required to pay Dynegy a termination fee of $100 million, (b) in connection with a superior offer, acquisition proposal or unforeseeable material intervening event, Vistra Energy may be required to pay a termination fee to Dynegy of $100 million, and (c) in connection with a superior offer, acquisition proposal or an unforeseeable material intervening event, Dynegy may be required to pay to Vistra Energy a termination fee of $87 million. In addition, if the Merger Agreement is terminated (i) because Vistra Energy's stockholders do not approve the issuance of Vistra Energy's common stock in the Merger or do not adopt the Merger Agreement, then Vistra Energy will be obligated to reimburse Dynegy for its reasonable out-of-pocket fees and expenses incurred in connection with the Merger Agreement, or (ii) because Dynegy's stockholders do not adopt the Merger Agreement, then Dynegy will reimburse Vistra Energy for its reasonable out-of-pocket fees and expenses incurred in connection with the Merger Agreement, each of which is subject to a cap of $22 million. Such expense reimbursement may be deducted from the abovementioned termination fees, if ultimately payable.
The Merger is subject to certain risks and uncertainties, and there can be no assurance that we will be able to complete the Merger on the expected timeline or at all.
Merger Support Agreements — Concurrently with the execution of the Merger Agreement, certain stockholders of Vistra Energy, including affiliates of Apollo Management Holdings L.P. (collectively, the Apollo Entities), affiliates of Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P. (collectively, the Brookfield Entities) and certain affiliates of Oaktree Capital Management, L.P. (Oaktree), such agreements representing in the aggregate approximately 34% of the shares of Vistra Energy's common stock that will be entitled to vote on the Merger, and certain stockholders of Dynegy, including Terawatt Holdings, LP, an affiliate of certain affiliated investment funds of Energy Capital Partners III, LLC (Terawatt) and certain affiliates of Oaktree, such agreements representing in the aggregate approximately 21% of the shares of Dynegy's common stock that will be entitled to vote on the Merger, have entered into merger support agreements (the Merger Support Agreements), pursuant to which each such stockholder agreed to vote their shares of common stock of Vistra Energy or Dynegy, as applicable, to adopt the Merger Agreement, and in the case of stockholders of Vistra Energy, approve the stock issuance. The Merger Support Agreements will automatically terminate upon a change of recommendation by the applicable board of directors or the termination of the Merger Agreement in accordance with its terms.
The foregoing description of the Merger Support Agreements does not purport to be complete and is qualified in its entirety by reference to that certain Merger Support Agreement, dated as of October 29, 2017, by and among Dynegy and the Apollo Entities, the Brookfield Entities and certain affiliates of Oaktree (filed as Exhibit 10.1 to Dynegy Inc.'s Current Report on Form 8-K filed on October 30, 2017), the Merger Support Agreement entered into between Vistra Energy and Terawatt (filed as Exhibit 10.1 to our Current Report on Form 8-K filed on October 31, 2017) and the Merger Support Agreement entered into between Vistra Energy and certain affiliates of Oaktree (filed as Exhibit 10.2 to our Current Report on Form 8-K filed on October 31, 2017).
Planned Retirement of Generation Facilities
Monticello Site — In September 2017, we decided to retire our Monticello plant given that it is projected to be uneconomic based on current market conditions and given the significant environmental costs associated with operating the plant. In the three months ended September 30, 2017, we recorded a charge of approximately $24 million related to the retirement, including employee-related severance costs, noncash charges for materials inventory and the acceleration of Luminant's mining reclamation obligations (see Note 16). The charge, all of which related to our Wholesale Generation segment, was recorded to operating costs in our condensed statements of consolidated income (loss). In addition, we will continue the ongoing reclamation work at the plant's mines, which ceased active operations in the spring of 2016.
Sandow and Big Brown Sites — In October 2017, the Company and Alcoa entered into a contract termination agreement pursuant to which the parties agreed to an early settlement of a long-standing power and mining agreement. In consideration for the early termination, Alcoa made a one-time payment to Luminant of $238 million in October 2017. We expect to record the impacts of the Settlement Agreement in our consolidated financial statements for the fourth quarter of 2017, which would include the receipt of the cash payment, the acquisition of real property and the incurrence of certain liabilities and asset retirement obligations, along with the elimination of a related electric supply contract intangible asset on our consolidated balance sheet (see Note 4). The contract was important to the overall economic viability of the Sandow plant.
In October 2017, we decided to retire the Sandow and Big Brown plants and a related mine which supplies the Sandow plants. Management had previously announced its decision to retire a mine which supplies the Big Brown plant.
41
Regulatory Review — As part of the retirement process, Luminant has filed notices with ERCOT, which trigger a reliability review regarding such proposed retirements. If, at the end of the applicable ERCOT reliability review period, ERCOT determines the units are not needed for reliability, Luminant would expect to cease plant operations at Sandow and Monticello in January 2018 and at Big Brown in February 2018, which would result in the plants being taken offline by February 2018. In October 2017, ERCOT determined our Monticello plant would not be needed for system reliability purposes.
The announced retirements total installed nameplate generation capacity of 4,167 MW as detailed below.
Name | Location (all in the state of Texas) | Fuel Type | Installed Nameplate Generation Capacity (MW) | Number of Units | Estimated Date Units Will Be Taken Offline | ||||||
Monticello | Titus County | Lignite/Coal | 1,880 | 3 | January 4, 2018 | ||||||
Sandow | Milam County | Lignite | 1,137 | 2 | January 11, 2018 | ||||||
Big Brown | Freestone County | Lignite/Coal | 1,150 | 2 | February 12, 2018 | ||||||
Total | 4,167 | 7 | |||||||||
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Item 2. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
As described in Note 1 to the Financial Statements, Vistra Energy is considered a new reporting entity for accounting purposes as of the Effective Date, and its financial statements reflect the application of fresh start reporting. The financial statements of Vistra Energy (the Successor) for periods subsequent to the Effective Date are not comparable to the financial statements of TCEH (the Predecessor) for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that resulted from the Plan of Reorganization, and the related application of fresh start reporting, which includes accounting policies implemented by Vistra Energy that may differ from the Predecessor.
The following discussion and analysis of our financial condition and results of operations for the Successor three and nine months ended September 30, 2017 and the Predecessor three and nine months ended September 30, 2016 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements. Results are impacted by the effects of fresh start reporting, 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
Vistra Energy is a holding company operating an integrated power business in Texas. Through our Luminant and TXU Energy subsidiaries, we are principally engaged in competitive electricity market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and related services to end users. Prior to the Effective Date, TCEH was a holding company for our subsidiaries, which were principally engaged in the same activities as they are today.
Operating Segments
Subsequent to the Effective Date, Vistra Energy has two reportable segments: the Wholesale Generation segment, consisting largely of Luminant, and the Retail Electricity segment, consisting largely of TXU Energy. Prior to the Effective Date, there were no reportable business segments for TCEH. See Note 15 to the Financial Statements for further information concerning reportable business segments.
Significant Activities and Events and Items Influencing Future Performance
Planned Retirement of Generation Plants — In October 2017, Luminant announced plans to retire three power plants with a total installed nameplate generation capacity of approximately 4,167 MW and two lignite mines. These power plants include the Monticello, Sandow 4, Sandow 5 and Big Brown generation units. Luminant decided to retire these units given they are projected to be uneconomic based on current market conditions and given the significant environmental costs associated with operating such units. In the case of the Sandow units, the decision also reflected the execution of a Settlement Agreement discussed below.
As part of the retirement process, Luminant has filed notices with ERCOT, which trigger a reliability review regarding such proposed retirements. If, at the end of the applicable ERCOT reliability review period, ERCOT determines the units are not needed for reliability, Luminant would expect to cease plant operations at Sandow and Monticello in January 2018 and at Big Brown in February 2018. In October 2017, ERCOT determined our Monticello plant would not be needed for system reliability purposes.
Monticello Site — In September 2017, we decided to retire our Monticello plant. We recorded a charge of approximately $24 million in the three months ended September 30, 2017 related to the retirement, including employee related severance costs and noncash charges for materials inventory and the acceleration of Luminant's mining reclamation obligations (see Note 16 to the Financial Statements). In addition, we will continue the ongoing reclamation work at the plant's mines, which ceased active operations in the spring of 2016.
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Sandow and Big Brown Sites — With respect to the Sandow and Big Brown plants, we expect to record charges of approximately $70 to $90 million in the fourth quarter of 2017 related to the expected retirements, including employee-related severance costs, non-cash charges for writing off materials inventory and a contract intangible asset associated with the Big Brown plant. We expect to record additional charges in the fourth quarter of 2017 related to changes in the timing and amounts of asset retirement obligations for mining and plant-related reclamation at these facilities.
Termination and Settlement of Alcoa Contract — In October 2017, subsidiaries of Vistra Energy (Vistra Parties) entered into a separation and settlement agreement (Settlement Agreement) with Alcoa Corporation and Alcoa USA Corp. (collectively, the Alcoa Parties). Pursuant to the Settlement Agreement, the Vistra Parties and the Alcoa Parties agreed to early termination of a series of agreements related to industrial operations near Rockdale, Texas, thereby ending their contractual relationship with respect to the power generation unit known as Sandow Unit 4 and the mine known as Three Oaks Mine. The terminated agreements were scheduled to terminate in 2038 absent the Settlement Agreement. Among other things, the Alcoa Parties made a cash payment to the Vistra Parties in the amount of $238 million and transferred certain real property and related assets to the Vistra Parties, the Vistra Parties agreed to assume and be responsible for certain liabilities and asset retirement obligations related to Sandow Unit 4 (including certain related common facilities), the related mine and other property transferred from the Alcoa Parties to the Vistra Parties, and both parties released one another from any obligations and claims under the terminated agreements. The transactions under the Settlement Agreement are effective as of October 1, 2017.
We expect to record the impacts of the Settlement Agreement in our consolidated financial statements for the fourth quarter of 2017, which would include the receipt of the cash payment, the acquisition of real property and the incurrence of certain liabilities and asset retirement obligations, along with the elimination of a related electric supply contract intangible asset on our consolidated balance sheet (see Note 4 to the Financial Statements). We currently estimate that the aggregate impacts related to the Settlement Agreement will result in a gain in the period.
CCGT Plant Acquisition — In July 2017, La Frontera Holdings, LLC (La Frontera), an indirect wholly owned subsidiary of Vistra Energy, entered into an asset purchase agreement with Odessa-Ector Power Partners, L.P., an indirect wholly owned subsidiary of Koch Ag & Energy Solutions, LLC (the Odessa Acquisition), to acquire a 1,054 MW CCGT natural gas fueled generation plant (and other related assets and liabilities) located in Odessa, Texas (the Odessa Facility). On August 1, 2017, the Odessa Acquisition closed and La Frontera acquired the Odessa Facility. La Frontera paid an aggregate purchase price of approximately $355 million, plus a five-year earn-out provision, to acquire the Odessa Facility. The purchase price was funded by cash on hand.
Upton Solar Development — In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power generation facility in Upton County, Texas. As part of this project, we entered a turnkey engineering, procurement and construction agreement to construct the approximately 180 MW facility. For the nine months ended September 30, 2017, we have spent approximately $129 million related to this project primarily for progress payments under the engineering, procurement and construction agreement and the acquisition of the development rights. We currently estimate that the facility will begin operations in the summer of 2018.
Repricing of Vistra Operations Credit Facilities — In February 2017 and August 2017, certain pricing terms for the Vistra Operations Credit Facility were amended. Any amounts borrowed under the Revolving Credit Facility will bear interest based on applicable LIBOR rates plus 2.75%. Amounts borrowed under the Initial Term Loan B Facility, the Incremental Term Loan B Facility and the Term Loan C Facility will bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 2.75%. See Note 9 to the Financial Statements for details of the Vistra Operations Credit Facilities.
Natural Gas Price and Market Heat Rate Exposure — Taking together forward wholesale, retail electricity sales and other retail customer considerations and all other hedging positions, at October 20, 2017, we had effectively hedged an estimated 100% and 82% of the natural gas price exposure related to our overall business for 2017 and 2018, respectively. Additionally, taking into consideration our overall heat rate exposure and related hedging positions at October 20, 2017, we had effectively hedged 87% and 67% of the heat rate exposure to our overall business for 2017 and 2018, respectively.
44
The following sensitivity table provides approximate estimates of the potential impact of movements in natural gas prices and market heat rates on realized pretax earnings (in millions) taking into account the hedge positions noted in the paragraph above for the periods presented. The estimates related to price sensitivity are based on our expected generation and retail positions, related hedges and forward prices as of October 20, 2017. The underlying hedge positions take into account the effects of the proposed retirements of generation facilities discussed in Note 17 to the Financial Statements.
Balance 2017 (a) | 2018 | ||
$0.50/MMBtu increase in natural gas price (b)(c) | $ ~— | $ ~50 | |
$0.50/MMBtu decrease in natural gas price (b)(c) | $ ~— | $ ~(40) | |
1.0/MMBtu/MWh increase in market heat rate (d) | $ ~5 | $ ~85 | |
1.0/MMBtu/MWh decrease in market heat rate (d) | $ ~(5) | $ ~(70) | |
___________
(a) | Balance of 2017 is from November 1, 2017 through December 31, 2017. |
(b) | Assumes conversion of generation positions based on market heat rates and an estimate of natural gas generally being on the margin 70% to 90% of the time in the ERCOT market. |
(c) | Based on Houston Ship Channel natural gas prices at October 20, 2017. |
(d) | Based on ERCOT North Hub around-the-clock heat rates at October 20, 2017. |
Environmental Matters — See Note 10 to Financial Statements for a discussion of greenhouse gas emissions, the Cross-State Air Pollution Rule, regional haze, state implementation plan and other recent EPA actions as well as related litigation.
45
RESULTS OF OPERATIONS
Vistra Energy Consolidated Financial Results — Three Months Ended September 30, 2017
Successor | |||||||||||||||
Three Months Ended September 30, 2017 | |||||||||||||||
Wholesale Generation | Retail Electricity | Eliminations / Corporate and Other | Vistra Energy Consolidated | ||||||||||||
Operating revenues | $ | 1,203 | $ | 1,286 | $ | (656 | ) | $ | 1,833 | ||||||
Fuel, purchased power costs and delivery fees | (430 | ) | (1,064 | ) | 656 | (838 | ) | ||||||||
Operating costs | (213 | ) | (4 | ) | (1 | ) | (218 | ) | |||||||
Depreciation and amortization | (60 | ) | (108 | ) | (10 | ) | (178 | ) | |||||||
Selling, general and administrative expenses | (31 | ) | (113 | ) | (3 | ) | (147 | ) | |||||||
Operating income (loss) | 469 | (3 | ) | (14 | ) | 452 | |||||||||
Other income | 9 | 10 | (9 | ) | 10 | ||||||||||
Interest expense and related charges | (9 | ) | — | (67 | ) | (76 | ) | ||||||||
Impacts of Tax Receivable Agreement | — | — | 138 | 138 | |||||||||||
Income before income taxes | $ | 469 | $ | 7 | 48 | 524 | |||||||||
Income tax expense | (251 | ) | (251 | ) | |||||||||||
Net income (loss) | $ | (203 | ) | $ | 273 | ||||||||||
Consolidated operating income totaled $452 million for the three months ended September 30, 2017. Results were driven by:
• | Our Wholesale Generation segment had operating income of $469 million for the period, which was primarily driven by income from our generation fleet during the peak summer operating months and unrealized mark-to-market gains on commodity risk management activities totaling $235 million for the period (including $89 million of unrealized gains on positions with the Retail Electricity segment and $9 million of unrealized gains on hedging activities for fuel and purchased power costs). The unrealized gains were driven by the impacts of a decrease in forward power prices during the period, partially offset by the reversal of previously recorded unrealized gains on settled positions. Additionally, operating income includes a $47 million unfavorable impact due to an unplanned outage at one of our nuclear generation units that began in June 2017 ($37 million of lower earnings due to lost generation and $10 million of additional operating costs). The outage required repairs to the plant's steam turbine generator, a standard component in all power stations that is completely unrelated to Comanche Peak's nuclear reactor, which was not impacted by the outage. The unit returned to service in August 2017. Please see the discussion of Wholesale Generation below for further details. |
• | Our Retail Electricity segment had an operating loss of $3 million for the period, which was primarily driven by $89 million of unrealized losses in purchased power costs on positions with the Wholesale Generation segment, mostly offset by favorable profit margins. Please see the discussion of Retail Electricity below for further details. |
• | Net operating expense related to Eliminations and Corporate and Other activities totaled $14 million and primarily reflected amortization of software and other technology-related assets (see Note 4 to the Financial Statements). |
Interest expense and related charges totaled $76 million and included $52 million of interest expense incurred and $3 million of unrealized mark-to-market gains on interest rate swaps. See Note 7 to the Financial Statements.
The Impacts of the Tax Receivable Agreement was income of $138 million, which includes a $160 million gain due to changes in the estimated timing of TRA payments. See Note 6 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.
Income tax expense totaled $251 million. The effective tax rate was 47.9%. See Note 5 to the Financial Statements for reconciliation of this effective rate to the US federal statutory rate.
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Vistra Energy Consolidated Financial Results — Nine Months Ended September 30, 2017
Successor | |||||||||||||||
Nine Months Ended September 30, 2017 | |||||||||||||||
Wholesale Generation | Retail Electricity | Eliminations / Corporate and Other | Vistra Energy Consolidated | ||||||||||||
Operating revenues | $ | 2,757 | $ | 3,136 | $ | (1,406 | ) | $ | 4,487 | ||||||
Fuel, purchased power costs and delivery fees | (1,225 | ) | (2,432 | ) | 1,407 | (2,250 | ) | ||||||||
Operating costs | (616 | ) | (11 | ) | 1 | (626 | ) | ||||||||
Depreciation and amortization | (167 | ) | (322 | ) | (30 | ) | (519 | ) | |||||||
Selling, general and administrative expenses | (98 | ) | (317 | ) | (19 | ) | (434 | ) | |||||||
Operating income (loss) | 651 | 54 | (47 | ) | 658 | ||||||||||
Other income | 20 | 23 | (14 | ) | 29 | ||||||||||
Other deductions | (4 | ) | — | (1 | ) | (5 | ) | ||||||||
Interest expense and related charges | (14 | ) | — | (155 | ) | (169 | ) | ||||||||
Impacts of Tax Receivable Agreement | — | — | 96 | 96 | |||||||||||
Income (loss) before income taxes | $ | 653 | $ | 77 | (121 | ) | 609 | ||||||||
Income tax expense | (284 | ) | (284 | ) | |||||||||||
Net income (loss) | $ | (405 | ) | $ | 325 | ||||||||||
Consolidated operating income totaled $658 million for the nine months ended September 30, 2017. Results were driven by:
• | Our Wholesale Generation segment had operating income of $651 million for the period, which was primarily driven by income from our generation fleet during the peak summer operating months and unrealized mark-to-market gains on commodity risk management activities totaling $362 million for the period (including $171 million of unrealized gains on positions with the Retail Electricity segment and $13 million of unrealized losses on hedging activities for fuel and purchased power costs). The unrealized gains were driven by decreases in forward natural gas prices and power prices during the period, partially offset by the reversal of previously recorded unrealized gains on settled positions. Additionally, operating income includes a $74 million unfavorable impact due to an unplanned outage at one of our nuclear generation units that began in June 2017 ($57 million of lower earnings due to lost generation and $17 million of additional operating costs). The outage required repairs to the plant's steam turbine generator, a standard component in all power stations that is completely unrelated to Comanche Peak's nuclear reactor, which was not impacted by the outage. The unit returned to service in August 2017. Please see the discussion of Wholesale Generation below for further details. |
• | Our Retail Electricity segment had an operating income of $54 million for the period, which was primarily driven by favorable profit margins, partially offset by $171 million of unrealized losses in purchased power costs on positions with the Wholesale Generation segment. Please see the discussion of Retail Electricity below for further details. |
• | Net operating expense related to Eliminations and Corporate and Other activities totaled $47 million and primarily reflected amortization of software and other technology-related assets (see Note 4 to the Financial Statements). |
Interest expense and related charges totaled $169 million and included $157 million of interest expense incurred and $3 million of unrealized mark-to-market losses on interest rate swaps. See Note 7 to the Financial Statements.
The Impacts of the Tax Receivable Agreement was income of $96 million, which includes a $160 million gain due to changes in the estimated timing of TRA payments. See Note 6 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.
Income tax expense totaled $284 million. The effective tax rate was 46.6%. See Note 5 to the Financial Statements for reconciliation of this effective rate to the US federal statutory rate.
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Operating Income
We evaluate our segment performance using operating income as an earnings metric. We believe operating income is useful in evaluating our core business activities and is one of the metrics used by our chief operating decision maker and leadership to evaluate segment results. Operating income excludes interest income, interest expense and related charges, impacts of the Tax Receivables Agreement and income tax expense as these activities are managed at the corporate level.
Operating Statistics — Three and Nine Months Ended September 30, 2017
Successor | |||||||
Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | ||||||
Sales volumes (GWh): | |||||||
Retail electricity sales volumes: | |||||||
Residential | 6,948 | 16,060 | |||||
Business markets | 5,257 | 14,006 | |||||
Total retail electricity sales volumes | 12,205 | 30,066 | |||||
Wholesale electricity sales volumes (a) | 12,926 | 35,741 | |||||
Production volumes (GWh): | |||||||
Nuclear facilities | 3,936 | 12,646 | |||||
Lignite and coal facilities | 14,781 | 38,513 | |||||
Natural gas facilities | 6,026 | 13,496 | |||||
Capacity factors: | |||||||
Nuclear facilities | 77.5 | % | 83.9 | % | |||
Lignite and coal facilities | 83.5 | % | 73.3 | % | |||
CCGT facilities | 87.6 | % | 67.2 | % | |||
Market pricing: | |||||||
Average ERCOT North power price ($/MWh) | $ | 26.26 | $ | 23.85 | |||
Weather (North Texas average) - percent of normal (b): | |||||||
Cooling degree days | 93.3 | % | 96.3 | % | |||
Heating degree days | N/A | 60.2 | % | ||||
____________
(a) | Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market. |
(b) | 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 2006 to 2015. |
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Wholesale Generation Segment Financial Results — Three and Nine Months Ended September 30, 2017
For the three months ended September 30, 2017, wholesale electricity revenues totaled $1.203 billion and included:
• | $538 million in third-party wholesale electricity revenue, which included $401 million in electricity sales to third parties, including revenues from the recently acquired Odessa power generation facility (see Note 3 to the Financial Statements), and $137 million in unrealized gains from hedging activities reflecting a decrease in forward power prices, and |
• | $655 million in affiliated revenue with the Retail Electricity segment, which included $566 million in sales for the period and $89 million in unrealized gains on hedging activities with affiliate positions reflecting a decrease in forward power prices, partially offset by the reversal of previously recorded unrealized gains on settled power positions. |
For the nine months ended September 30, 2017, wholesale electricity revenues totaled $2.757 billion and included:
• | $1.328 million in third-party wholesale electricity revenue, which included $1.124 billion in electricity sales to third parties, including revenues from the recently acquired Odessa power generation facility (see Note 3 to the Financial Statements), and $204 million in unrealized gains from hedging activities reflecting a decrease in forward natural gas and power prices, partially offset by the reversal of previously recorded unrealized gains on settled power positions, and |
• | $1.406 billion in affiliated revenue with the Retail Electricity segment, which included $1.235 billion in sales for the period and $171 million in unrealized gains on hedging activities with affiliate positions reflecting a decrease in forward power prices partially offset by the reversal of previously recorded unrealized gains on settled power positions. |
For the three and nine months ended September 30, 2017, wholesale electricity sales and operating costs include unfavorable impacts totaling $47 million and $74 million, respectively, due to an unplanned outage at one of our nuclear generation units that began in June 2017.
Successor | |||||||
Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | ||||||
Wholesale electricity sales | $ | 401 | $ | 1,124 | |||
Unrealized net gains on hedging activities | 137 | 204 | |||||
Sales to affiliates | 566 | 1,235 | |||||
Unrealized net gains on hedging activities with affiliates | 89 | 171 | |||||
Other revenues | 10 | 23 | |||||
Total wholesale electricity revenues | $ | 1,203 | $ | 2,757 | |||
For the three and nine months ended September 30, 2017, fuel, purchased power costs and delivery fees totaled $430 million and $1.225 billion, respectively, and reflected $439 million and $1.212 billion, respectively, in fuel and purchased power costs and ancillary and other costs. For the three and nine months ended September 30, 2017, fuel expense for our nuclear facilities were lower due to an unplanned outage at one of our units. For the three months ended September 30, 2017, fuel and purchased power costs also included $9 million in unrealized gains from hedging activities reflecting reversal of previously recorded unrealized losses on settled natural gas positions. For the nine months ended September 30, 2017, fuel and purchased power costs also included $13 million in unrealized losses from hedging activities also reflecting reversal of previously recorded unrealized gains on settled positions.
Successor | |||||||
Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | ||||||
Fuel for nuclear facilities | $ | 19 | $ | 66 | |||
Fuel for lignite and coal facilities | 215 | 595 | |||||
Fuel for natural gas facilities and purchased power costs | 190 | 489 | |||||
Unrealized (gains) losses from hedging activities | (9 | ) | 13 | ||||
Ancillary and other costs | 15 | 62 | |||||
Total fuel and purchased power costs | $ | 430 | $ | 1,225 | |||
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Operating costs totaled $213 million and $616 million for the three and nine months ended September 30, 2017, respectively, and reflected operations and maintenance expenses for power generation facilities and salaries and benefits for facilities personnel. Total charges of approximately $24 million related to severance accruals, write-off of material and supplies inventory and changes to estimates and timing of asset retirement obligations are presented in operating costs for both periods due to our decision to retire our Monticello generation facility (see Note 17 to the Financial Statements).
For the three and nine months ended September 30, 2017, depreciation and amortization expenses totaled $60 million and $167 million, respectively, and primarily reflected depreciation on power generation and mining property, plant and equipment.
For the three and nine months ended September 30, 2017, SG&A totaled $31 million and $98 million, respectively, and reflected functional group service costs allocated from Corporate and Other activities totaling $26 million and $89 million, respectively.
Retail Electricity Segment Financial Results — Three and Nine Months Ended September 30, 2017
For the three months ended September 30, 2017, retail electricity revenues totaled $1.286 billion and included $1.223 billion related to 12,205 GWh in sales volumes. During the period, revenues were unfavorably impacted by mild weather during the peak summer cooling period as noted in the weather information included above in our Operating Statistics.
For the nine months ended September 30, 2017, retail electricity revenues totaled $3.136 billion and included $3.019 billion related to 30,066 GWh in sales volumes. During the period, revenues were unfavorably impacted by mild weather in both the peak summer cooling period and the winter season at the beginning of the year as noted in the weather information included above in our Operating Statistics.
Successor | |||||||
Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | ||||||
Retail electricity sales | $ | 1,223 | $ | 3,019 | |||
Amortization income (expense) of identifiable intangible assets related to retail contracts (see Note 4 to the Financial Statements) | 20 | (24 | ) | ||||
Other revenues | 43 | 141 | |||||
Total retail electricity revenues | $ | 1,286 | $ | 3,136 | |||
Purchased power costs, delivery fees and other costs totaled $1.064 billion and $2.432 billion for the three and nine months ended September 30, 2017, respectively, and reflected the following:
Successor | |||||||
Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | ||||||
Purchases from affiliates | $ | 566 | $ | 1,235 | |||
Unrealized net losses on hedging activities with affiliates | 89 | 171 | |||||
Delivery fees | 408 | 1,023 | |||||
Other costs | 1 | 3 | |||||
Total purchased power costs and delivery fees | $ | 1,064 | $ | 2,432 | |||
Depreciation and amortization expenses totaled $108 million and $322 million for the three and nine months ended September 30, 2017, respectively, and primarily reflected the impacts of amortization expense related to the retail customer relationship intangible asset established in fresh start reporting (see Note 4 to the Financial Statements).
SG&A totaled $113 million and $317 million for the three and nine months ended September 30, 2017, respectively, and reflected employee compensation and benefit costs (including functional group costs allocated from Corporate and Other), marketing and operation expenses and bad debt expense. For both periods, SG&A reflects an increase in bad debt expense as a result of the estimated impact on collectability from customers affected by Hurricane Harvey.
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Predecessor Consolidated Financial Results — Three and Nine Months Ended September 30, 2016
Predecessor | |||||||
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | ||||||
Operating revenues | $ | 1,690 | $ | 3,973 | |||
Fuel, purchased power costs and delivery fees | (874 | ) | (2,082 | ) | |||
Net gain from commodity hedging and trading activities | 336 | 282 | |||||
Operating costs | (190 | ) | (664 | ) | |||
Depreciation and amortization | (157 | ) | (459 | ) | |||
Selling, general and administrative expenses | (165 | ) | (482 | ) | |||
Operating income | 640 | 568 | |||||
Other income | 7 | 19 | |||||
Other deductions | (28 | ) | (75 | ) | |||
Interest expense and related charges | (371 | ) | (1,049 | ) | |||
Reorganization items | (64 | ) | (116 | ) | |||
Income (loss) before income taxes | 184 | (653 | ) | ||||
Income tax (expense) benefit | 3 | (3 | ) | ||||
Net income (loss) | $ | 187 | $ | (656 | ) | ||
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Predecessor Operating Statistics — Three and Nine Months Ended September 30, 2016
Predecessor | |||||||
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | ||||||
Operating revenues: | |||||||
Retail electricity revenues | $ | 1,299 | $ | 3,154 | |||
Wholesale electricity revenues and other operating revenues (a)(b) | 391 | 819 | |||||
Total operating revenues | $ | 1,690 | $ | 3,973 | |||
Fuel, purchased power costs and delivery fees: | |||||||
Fuel for nuclear facilities | $ | 31 | $ | 92 | |||
Fuel for lignite and coal facilities | 236 | 548 | |||||
Fuel for natural gas facilities and purchased power costs (a) | 150 | 310 | |||||
Other costs | 41 | 108 | |||||
Delivery fees | 416 | 1,024 | |||||
Total | $ | 874 | $ | 2,082 | |||
Sales volumes: | |||||||
Retail electricity sales volumes (GWh): | |||||||
Residential | 7,359 | 16,619 | |||||
Business markets | 5,385 | 14,354 | |||||
Total retail electricity | 12,744 | 30,973 | |||||
Wholesale electricity sales volumes (b) | 12,058 | 25,563 | |||||
Production volumes (GWh): | |||||||
Nuclear facilities | 5,310 | 15,005 | |||||
Lignite and coal facilities (c) | 14,630 | 31,865 | |||||
Natural gas facilities | 4,452 | 8,539 | |||||
Capacity factors: | |||||||
Nuclear facilities | 104.6 | % | 99.2 | % | |||
Lignite and coal facilities (c) | 82.6 | % | 60.5 | % | |||
Market pricing: | |||||||
Average ERCOT North power price ($/MWh) | $ | 26.54 | $ | 20.78 | |||
Weather (North Texas average) - percent of normal (d): | |||||||
Cooling degree days | 106.6 | % | 102.8 | % | |||
Heating degree days | — | % | 81.9 | % | |||
____________
(a) | Upon settlement, physical derivative commodity contracts that we mark-to-market in net income, such as certain electricity sales and purchase agreements and coal purchase contracts, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, rather than contract price. The offsetting differences between contract and market prices are reported in net gain 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) | Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal fueled units totaling 2,390 GWh and 14,420 GWh for the three and nine months ended September 30, 2016, respectively. |
(d) | Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over the 10-year period from 2000 to 2010. |
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Predecessor Financial Results — Three and Nine Months Ended September 30, 2016
For the three months ended September 30, 2016, income before income taxes totaled $184 million and reflected net gains in commodity and hedging activities totaling $336 million, partially offset by interest expense for adequate protection on pre-petition debt totaling $331 million. For the nine months ended September 30, 2016, loss before income taxes totaled $653 million and primarily reflected interest expense for adequate protection on pre-petition debt totaling $977 million and the effects of declining average electricity prices and milder than normal winter weather on operating revenues, partially offset by net gains in commodity and hedging activities.
Operating revenues totaled $1.690 billion and $3.973 billion for the three and nine months ended September 30, 2016, respectively.
• | For the three and nine months ended September 30, 2016, retail electricity revenues totaled $1.299 billion and $3.154 billion, respectively, and were negatively impacted by reduced volumes reflecting milder than normal winter weather in 2016 and declining average prices. |
• | For the three and nine months ended September 30, 2016, wholesale revenues totaled $396 million and $649 million, respectively, and increased due to additional sales from the Lamar and Forney generation assets acquired in April 2016. For the nine months ended September 30, 2016, wholesale volumes were also negatively impacted by lower average wholesale electricity prices. |
Following is an analysis of amounts reported as net losses from commodity hedging and trading activities. Results are primarily related to natural gas and power hedging activity.
Predecessor | |||||||
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | ||||||
Realized net gains | $ | 122 | $ | 320 | |||
Unrealized net gains (losses) | 214 | (38 | ) | ||||
Total | $ | 336 | $ | 282 | |||
For both periods presented, the negative impacts of declining average prices on wholesale operating revenues were partially offset by realized net gains reflecting settled gains on derivatives due to declining market prices. These gains were primarily related to natural gas positions.
For the three months ended September 30, 2016, net unrealized gains were primarily impacted by reversals of previously recorded unrealized net losses on settled positions and unrealized net gains recorded due to unrealized gains on heat rate and power hedges due to decreases in forward prices. For the nine months ended September 30, 2016, net unrealized losses were primarily impacted by reversals of previously recorded unrealized net gains on settled positions.
Fuel, purchased power costs and delivery fees totaled $874 million and $2.082 billion for the three and nine months ended September 30, 2016, respectively, and reflected the impact of declining electricity prices on purchased power costs during 2016, partially offset by incremental natural gas fuel costs associated with the Lamar and Forney Acquisition (see Note 3 to the Financial Statements).
Operating costs totaled $190 million and $664 million for the three and nine months ended September 30, 2016, respectively, and primarily reflect maintenance expense for our generation assets, including the scope and timing of maintenance costs at lignite/coal fueled generation facilities. Operating costs were also impacted by incremental operation and maintenance costs associated with the Lamar and Forney Acquisition.
Depreciation and amortization expenses totaled $157 million and $459 million for the three and nine months ended September 30, 2016, respectively, and reflected incremental depreciation expense associated with the Lamar and Forney Acquisition.
SG&A expenses totaled $165 million and $482 million for the three and nine months ended September 30, 2016, respectively, and reflected administrative and general salaries, employee benefits, marketing costs related to retail electricity activity and other administrative costs.
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For the three and nine months ended September 30, 2016, results for the period also include $7 million and $32 million, respectively, of severance expense, primarily reported in fuel, purchased power costs and delivery fees and operating costs, associated with certain actions taken to reduce costs related to mining and lignite/coal generation operations.
For the three and nine months ended September 30, 2016, interest expense and related charges totaled $371 million and $1.049 billion, respectively, and included adequate protection payments approved by the Bankruptcy Court for the benefit of TCEH secured creditors totaling $331 million and $977 million, respectively, and interest expense on debtor-in-possession financing totaling $38 million and $76 million, respectively.
Energy-Related Commodity Contracts and Mark-to-Market Activities
The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2017 and 2016. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $202 million in unrealized net gains for the nine months ended September 30, 2017 and $38 million in unrealized net losses for the nine months ended September 30, 2016 arising from mark-to-market accounting for positions in the commodity contract portfolio.
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | |||||||
Commodity contract net asset at beginning of period | $ | 64 | $ | 271 | ||||
Settlements/termination of positions (a) | (134 | ) | (232 | ) | ||||
Changes in fair value of positions in the portfolio (b) | 336 | 194 | ||||||
Other activity (c) | (45 | ) | (35 | ) | ||||
Commodity contract net asset at end of period | $ | 221 | $ | 198 | ||||
____________
(a) | Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The Successor period includes reversal of $38 million of previously recorded unrealized gains related to Vistra Energy beginning balances. 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. The Successor period includes a $19 million "day one" gain related to a long-term power derivative. 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) | Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to certain margin deposits classified as settlement for certain transactions done on the CME as well as premiums related to options purchased or sold and the initial fair value of the earn-out provision related to the Odessa Acquisition (see Note 3 to the Financial Statements). |
Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values at September 30, 2017, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
Successor | ||||||||||||||||||||
Maturity dates of unrealized commodity contract net asset at September 30, 2017 | ||||||||||||||||||||
Source of fair value | Less than 1 year | 1-3 years | 4-5 years | Excess of 5 years | Total | |||||||||||||||
Prices actively quoted | $ | 2 | $ | (2 | ) | $ | (1 | ) | $ | — | $ | (1 | ) | |||||||
Prices provided by other external sources | 63 | 2 | — | — | 65 | |||||||||||||||
Prices based on models | 64 | 73 | 11 | 9 | 157 | |||||||||||||||
Total | $ | 129 | $ | 73 | $ | 10 | $ | 9 | $ | 221 | ||||||||||
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FINANCIAL CONDITION
Cash Flows
Successor — Nine Months Ended September 30, 2017 — Cash provided by operating activities totaled $845 million in 2017 and was primarily driven by cash from operations of approximately $957 million after taking into consideration depreciation and amortization, noncash impacts of the Tax Receivable Agreement and unrealized mark-to-market gains on derivatives, offset by a net use of cash of approximately $112 million in changes in operating assets and liabilities primarily driven by working capital, incentive plan payments and tax payments, partially offset by decreases in cash utilized in margin postings related to derivative contracts.
Cash used in financing activities totaled $37 million in 2017 and reflected the repayment of debt.
Cash used in investing activities totaled $597 million in 2017 and reflected payments of $355 million related to the Odessa Acquisition, capital expenditures (including nuclear fuel purchases) totaling $142 million and Upton solar development expenditures totaling $129 million. The Odessa Acquisition and the Upton solar development were funded using cash on hand.
Predecessor — Nine Months Ended September 30, 2016 — Cash used in operating activities totaled $196 million in 2016 and reflected cash interest payments of $1.064 billion, mostly offset by cash from operations.
Cash provided by financing activities totaled $1.913 billion and reflected $2.040 billion in net borrowings under the DIP Roll Facilities and the DIP Facility, including $870 million in net borrowings to fund the Lamar and Forney Acquisition (see Note 3 to the Financial Statements). Activity in 2016 also reflected $112 million in fees related to the issuance of the DIP Roll Facilities.
Cash used in investing activities totaled $1.288 billion and reflected payments of $1.343 billion related to the Lamar and Forney Acquisition net of cash acquired (see Note 3 to the Financial Statements) and capital expenditures (including nuclear fuel purchases) totaling $263 million, partially offset by a $365 million decrease in restricted cash used to backstop letters of credit.
Debt Activity
See Note 9 to the Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt.
Available Liquidity
The following table summarizes changes in available liquidity for the nine months ended September 30, 2017:
September 30, 2017 | December 31, 2016 | Change | |||||||||
Cash and cash equivalents (a) | $ | 1,054 | $ | 843 | $ | 211 | |||||
Vistra Operations Credit Facilities — Revolving Credit Facility | 860 | 860 | — | ||||||||
Vistra Operations Credit Facilities — Term Loan C Facility (b) | 170 | 131 | 39 | ||||||||
Total liquidity | $ | 2,084 | $ | 1,834 | $ | 250 | |||||
___________
(a) | Cash and cash equivalents excludes $650 million of restricted cash held for letter of credit support at both September 30, 2017 and December 31, 2016 (see Note 16 to the Financial Statements). |
(b) | The Term Loan C Facility is used for issuing letters of credit for general corporate purposes. Borrowing totaling $650 million under this facility were funded to collateral accounts that are reported as restricted cash in our condensed consolidated balance sheets. The September 30, 2017 restricted cash balance represents borrowings under the Term Loan C Facility held in a collateral account that supports $480 million in letters of credit outstanding, leaving $170 million in available letter of credit capacity (see Note 9). |
The increase in available liquidity to $2.084 billion in the nine months ended September 30, 2017 compared to December 31, 2016 was primarily driven by increased available cash from operations and reduced letter of credit postings, partially offset by cash utilized in the Odessa Acquisition and our development of the Upton solar facility.
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Based upon our current internal financial forecasts, we believe that we will have sufficient amounts available under the Vistra Operations Credit Facilities, plus cash generated from operations, to fund our anticipated cash requirements through at least the next 12 months.
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. We use cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 9 to the Financial Statements for discussion of the Vistra Operations Credit Facilities.
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 business 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. 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 September 30, 2017, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:
• | $3 million in cash has been posted with counterparties as compared to $213 million posted at December 31, 2016; |
• | $14 million in cash has been received from counterparties as compared to $41 million received at December 31, 2016; |
• | $350 million in letters of credit have been posted with counterparties as compared to $363 million posted at December 31, 2016, and |
• | $10 million in letters of credit have been received from counterparties as compared to $10 million received at December 31, 2016. |
Income Tax Matters
EFH Corp files a U.S. federal income tax return that, prior to the Effective Date, included the results of our Predecessor, which was classified as a disregarded entity for US federal income tax purposes. Subsequent to the Effective Date, the TCEH Debtors and the Contributed EFH Debtors are no longer included in the EFH Corp. consolidated group and will be included in a consolidated group of which Vistra Energy is the corporate parent. Prior to the Effective Date, EFH Corp. and certain of its subsidiaries (including EFCH and TCEH) were parties to a Federal and State Income Tax Allocation Agreement, which provided, among other things, that any corporate member or disregarded entity in the EFH Corp. group was 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. Pursuant to the Plan of Reorganization, the TCEH Debtors and the Contributed EFH Debtors rejected this agreement on the Effective Date. Additionally, since the date of the Settlement Agreement, no further cash payments among the Debtors were made in respect of federal income taxes. EFH Corp. has 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 continued to be settled prior to the Effective Date.
The TCEH Debtors and the Contributed EFH Debtors emerged from the Chapter 11 Cases on the Effective Date in a tax-free spin-off from EFH Corp that was part of a series of transactions that included a taxable component, which generated a taxable gain that will be offset with available net operating losses (NOLs) of EFH Corp., substantially reducing the NOLs available to EFH Corp. in the future. As a result of the use of the NOLs, the taxable portion of the transaction resulted in no regular tax liability due and approximately $14 million of alternative minimum tax, payable to the IRS by EFH Corp. Pursuant to the Tax Matters Agreement, Vistra Energy had an obligation to reimburse EFH Corp. 50% of the alternative minimum tax, and approximately $7 million was reimbursed during the three months ended June 30, 2017. In October 2017, the 2016 federal tax return that included the results of EFCH, EFIH, Oncor Holdings and TCEH was filed with the IRS and resulted in $3 million payable from EFH Corp to Vistra Energy.
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Income Tax Payments — In the next twelve months, we expect to make federal income tax payments of approximately $33 million, which represents Vistra Energy's 2016 tax liability paid in October 2017 and our remaining estimated 2017 federal income tax liability. We also expect to make Texas margin tax payments of approximately $19 million in the next twelve months. Income tax payments totaled $51 million and $22 million for the nine months ended September 30, 2017 and 2016, respectively.
Financial Covenants
The agreement governing the Vistra Operations Credit Facilities includes a covenant, solely with respect to the Revolving Credit Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $100 million) exceed 30% of the revolving commitments), that requires the consolidated first lien net leverage ratio not exceed 4.25 to 1.00. Although we had no borrowings under the Revolving Credit Facility as of September 30, 2017, we would have been in compliance with this financial covenant if it was required to be tested at such date.
See Note 9 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.
Collateral Support Obligations
The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In September 2016, the RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations. The collateral bond is effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) that contractually enables the RCT to be paid (up to $975 million) before the other first lien lenders in the event of a liquidation of our 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 September 30, 2017, Vistra Energy has posted letters of credit in the amount of $55 million with the PUCT, which is subject to adjustments.
ERCOT has rules in place to assure adequate creditworthiness of parties that participate in the day-ahead, real-time and congestion revenue rights markets operated by ERCOT. Under these rules, Vistra Energy has posted collateral support, in the form of letters of credit, totaling $110 million at September 30, 2017 (which is subject to daily adjustments based on settlement activity with ERCOT).
Material Cross Default/Acceleration Provisions
Certain of our contractual arrangements contain provisions that could result in an event of default if there was a failure under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due. Such provisions are referred to as "cross default" or "cross acceleration" provisions.
A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of $300 million may result in a cross default under the Vistra Operations Credit Facilities. Such a default would allow the lenders to accelerate the maturity of outstanding balances (approximately $4.5 billion at September 30, 2017) under such facilities.
Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross default provision. An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness in excess of $300 million that results in the acceleration of such debt, would give each counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with Vistra Operations (or its applicable subsidiary) and require all outstanding obligations under such agreement to be settled.
Additionally, we enter into energy-related physical and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which may vary by contract.
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Guarantees
See Note 10 to the Financial Statements for discussion of guarantees.
OFF–BALANCE SHEET ARRANGEMENTS
We do not have any off-balance sheet arrangements.
COMMITMENTS AND CONTINGENCIES
See Note 10 to the Financial Statements for discussion of commitments and contingencies.
CHANGES IN ACCOUNTING STANDARDS
See Note 1 to the Financial Statements for discussion of changes in accounting standards.
Item 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Market risk is the risk that in the normal 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 our 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 reporting and 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.
Vistra Energy has a risk management organization that enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits, and evaluates the risks inherent in our businesses.
Commodity Price Risk
Our business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. We actively manage the portfolio of generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices.
In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. We continuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.
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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.
VaR for Underlying Generation Assets and 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 underlying generation assets and contracts marked-to-market in net income (through the end of 2018), based on a 95% confidence level and an assumed holding period of 60 days.
Nine Months Ended September 30, 2017 | Year Ended December 31, 2016 | ||||||
Month-end average VaR: | $ | 101 | $ | 65 | |||
Month-end high VaR: | $ | 140 | $ | 119 | |||
Month-end low VaR: | $ | 67 | $ | 30 | |||
The increase in the month-end high VaR risk measure in 2017 reflected increased natural gas volatility and lower seasonal natural gas to power correlations in early 2017.
Interest Rate Risk
At September 30, 2017, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $15 million, taking into account the interest rate swaps discussed in Note 9 to Financial Statements.
Credit Risk
Credit risk relates to the risk of loss associated with nonperformance by counterparties. We minimize credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial condition, current and potential credit exposures, credit rating and other quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental guarantees and surety bonds. See Note 13 to the Financial Statements for further discussion of this exposure.
Credit Exposure — Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled $925 million at September 30, 2017.
At September 30, 2017, Retail Electricity segment credit exposure totaled $569 million, including $558 million of trade accounts receivable and $11 million related to derivative assets. Cash deposits and letters of credit held as collateral for these receivables totaled $45 million, resulting in a net exposure of $524 million. We believe 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.
At September 30, 2017, Wholesale Generation segment credit exposure totaled $356 million including $130 million of trade accounts receivable and $226 million related to derivative assets, after taking into account master netting agreement provisions but excluding collateral impacts.
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Including collateral posted to us by counterparties, our net Wholesale Generation segment exposure was $322 million, substantially all of which is with investment grade customers as seen in the following table that presents the distribution of credit exposure at September 30, 2017. Credit collateral includes cash and letters of credit, but excludes other credit enhancements such as guarantees or liens on assets.
Exposure Before Credit Collateral | Credit Collateral | Net Exposure | |||||||||
Investment grade | $ | 335 | $ | 32 | $ | 303 | |||||
Below investment grade or no rating | 21 | 2 | 19 | ||||||||
Totals | $ | 356 | $ | 34 | $ | 322 | |||||
Significant (10% or greater) concentration of credit exposure exists with three counterparties, which represented an aggregate $162 million, or 50%, of the total 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.
Contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements and are excluded from the detail above. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.
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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 financial or operational projections, capital allocation, capital expenditures, liquidity, dividend policy, 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," "may," "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 risks and is qualified in its entirety by reference to the discussion under Risk Factors in our prospectus filed with the SEC pursuant to Rule 424(b) of the Securities Act in May 2017 (as supplemented to date) and 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 or implied by such forward-looking statements:
• | the actions and decisions of regulatory authorities; |
• | prohibitions and other restrictions on our operations due to the terms of our agreements; |
• | prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the US Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Texas Reliability Entity, Inc., the PUCT, the RCT, the NRC, the EPA, the TCEQ, the US Mine Safety and Health Administration and the CFTC, with respect to, among other things: |
◦ | allowed prices; |
◦ | industry, market and rate structure; |
◦ | purchased power and recovery of investments; |
◦ | operations of nuclear generation facilities; |
◦ | operations of fossil fueled generation facilities; |
◦ | operations of mines; |
◦ | acquisition and disposal of assets and facilities; |
◦ | development, construction and operation of facilities; |
◦ | decommissioning costs; |
◦ | present or prospective wholesale and retail competition; |
◦ | changes in tax laws and policies; |
◦ | changes in and compliance with environmental and safety laws and policies, including National Ambient Air Quality Standards, the Cross-State Air Pollution Rule, the Mercury and Air Toxics Standard, regional haze program implementation and GHG 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; |
• | general industry trends; |
• | economic conditions, including the impact of an economic downturn; |
• | 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; |
• | 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; |
• | 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; |
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• | access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and refinancing efforts, including availability of funds in capital markets; |
• | our ability to maintain prudent financial leverage; |
• | our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our debt obligations: |
• | competition for new energy development and other business opportunities; |
• | our ability to successfully complete our solar generation project in a timely and cost-efficient manner or at all; |
• | 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 power generation to compete with our generation assets; |
• | our ability to attract and retain qualified employees; |
• | 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; |
• | the impact of our obligations under the TRA; |
• | expectations regarding the Merger, including beliefs concerning stockholder and regulatory approvals; |
• | the occurrence of any event that could give rise to the termination of the Merger Agreement, including a termination of the Merger Agreement under circumstances that could require us to pay a termination fee, 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 them. In addition, we may be unable to assess the impact of any such event or condition or the extent to which any such event or condition, or combination of events or conditions, may cause results to differ materially from those contained in or implied by any forward-looking statement. As such, you should not unduly rely on such forward-looking statements.
INDUSTRY AND MARKET INFORMATION
Certain 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, reports or other sources. 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. Industry publications, reports and other sources 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, publications, reports and other sources is reliable, we have not independently investigated or verified the information contained or referred to therein and make no representation as to the accuracy or completeness of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions were used in preparing such forecasts. Statements regarding industry and market data and other statistical information used throughout this report involve risks and uncertainties and are subject to change based on various factors.
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 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 10 to the Financial Statements regarding legal proceedings.
Item 1A. | RISK FACTORS |
There have been no material changes to the risk factors discussed in Risk Factors in our prospectus filed with the SEC pursuant to Rule 424(b) of the Securities Act in May 2017 (as supplemented to date) except for the risks related to the Merger described below and for the information disclosed below and elsewhere in this quarterly report on Form 10-Q that provides factual updates to risk factors contained in such prospectus. The risks described in such reports are not the only risks facing our company.
Risks related to the Merger
The Merger is subject to a number of conditions which, if not satisfied or waived in a timely manner, would delay the Merger or adversely impact our ability to complete the Merger on the terms set forth in the Merger Agreement or at all.
The completion of the Merger is subject to the satisfaction or waiver of a number of conditions. For example, before the Merger may be completed, both the Company and Dynegy will need to obtain stockholder approval of the proposed transaction. In addition, various filings must be made with the Federal Energy Regulatory Commission and various other regulatory, antitrust and other authorities in the United States. These governmental authorities may impose conditions on the completion, or require changes to the terms of the Merger, including restrictions or conditions on the business, operations or financial performance of the combined company following completion of the Merger. These conditions or changes, including potential litigation brought in connection with the Merger, could have the effect of delaying completion of the Merger or imposing additional costs on or limiting the revenues of the combined company following the Merger, any of which could have a material adverse effect on the financial condition, results of operations and cash flows of the combined company and/or cause either the Company or Dynegy to abandon the Merger. These conditions or changes could also have the effect of causing the Merger to be consummated on terms different than those contemplated by the Merger Agreement or causing the Merger to fail to be consummated.
If we are unable to complete the Merger, we still will incur and will remain liable for significant transaction costs, including legal, accounting, filing, printing and other costs relating to the Merger. Also, depending upon the reasons for not completing the Merger, we may be required to pay Dynegy a termination fee of $100 million. If such a termination fee is payable, the payment of this fee could have a material adverse effect on the financial condition, results of operations and cash flows of the Company.
Failure to consummate the Merger as currently contemplated or at all could adversely affect the price of our stock and our future business and financial results.
The completion of the Merger is subject to the satisfaction or waiver of a number of conditions. We cannot guarantee when or if these conditions will be satisfied or the Merger will be successfully completed. If the Merger is not consummated, or is consummated on different terms than as contemplated by the Merger Agreement, we could be adversely affected and subject to a variety of risks associated with the failure to consummate the Merger, or to consummate the Merger as contemplated by the Merger Agreement, including:
• | our stockholders may be prevented from realizing the anticipated potential benefits of the Merger; |
• | the market price of our stock could decline significantly; |
• | we may experience reputational harm due to the adverse public perception of any failure to successfully complete the Merger; |
• | we may be required, under certain circumstances, to pay Dynegy a termination fee of up to $100 million or reimburse its expenses up to $22 million; |
• | we may incur substantial costs, in addition to the substantial costs we have already incurred, relating to the Merger, such as legal, accounting, financial advisory, filing, printing and mailing fees, and |
• | the attention of our management and employees may be diverted from their day-to-day business and operational matters and our relationships with our customers and suppliers may be disrupted as a result of efforts relating to attempting to consummate the Merger. |
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Any delay in the consummation of the Merger, any uncertainty about the consummation of the Merger on terms other than those contemplated by the Merger Agreement and any failure to consummate the Merger could adversely affect our business, financial results and share price.
If completed, our Merger may not achieve its intended results.
We entered into the Merger Agreement with the expectation that the Merger would result in various benefits, including, among other things, cost savings and operating efficiencies. Achievement of the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the businesses of the Company and Dynegy are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits in a timely fashion, or at all, could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company's business, financial results and prospects.
We will be subject to business uncertainties and contractual restrictions while the Merger is pending that could adversely affect our financial results.
Uncertainty about the effect of the Merger with Dynegy on employees, customers and suppliers may have an adverse effect on our business. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with us to seek to change existing business relationships.
Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees depart or prospective employees fail to accept employment with us for any reason, including because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our operations and financial results could be affected.
The pursuit of the Merger and the preparation for the integration of Dynegy may place a significant burden on management and internal resources. The diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process could affect our business, and our financial condition, results of operations and cash flows.
In addition, we are restricted under the Merger Agreement, without Dynegy's consent, from making certain acquisitions and taking other specified actions until the Merger occurs or the Merger Agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to completion of the Merger or termination of the Merger Agreement.
Because the market price of shares of the Company and Dynegy common stock will fluctuate and the exchange ratio is fixed, the market value of the Merger consideration at the date of the closing may vary significantly from the date the Merger Agreement was executed.
Upon completion of the Merger, subject to certain exceptions, each outstanding share of Dynegy common stock will be converted into the right to receive 0.652 of a share of common stock of the Company. The number of shares of common stock of the Company to be issued pursuant to the Merger Agreement for each share of Dynegy common stock is fixed and will not change to reflect changes in the market price of the Company or Dynegy common stock. The market prices of common stock of the Company at the time of completion of the Merger may vary significantly from the market prices of common stock of the Company or Dynegy common stock on the date the Merger Agreement was executed, particularly since the Merger may not be completed until a significant period of time has passed after the respective stockholder meetings. Because the exchange ratio is fixed, the market value of the common stock of the Company issued in connection with the Merger and the Dynegy common stock surrendered in connection with the Merger may be significantly higher or lower than the values of those shares on the date the Merger Agreement was signed, the date of the joint proxy statement/prospectus to be prepared in connection with the Merger, the dates of the Company's and Dynegy's stockholder meetings to approve the Merger or other earlier dates. Stock price changes may result from market assessment of the likelihood that the Merger will be completed, changes in the business, operations or prospects of the Company or Dynegy prior to or following the Merger, litigation or regulatory considerations, general business, market, industry or economic conditions and other factors both within and beyond the control of the Company and Dynegy. Neither the Company nor Dynegy is permitted to terminate the Merger Agreement solely because of changes in the market price of either company's common stock.
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The Merger Agreement contains provisions that limit the Company's ability to pursue alternatives to the Merger, which could discourage a potential competing acquirer of the Company from making a favorable alternative transaction proposal and, in certain circumstances, could require the Company to pay a termination fee to Dynegy.
Under the Merger Agreement, the Company is restricted from entering into alternative transactions to the Merger. Unless and until the Merger Agreement is terminated, subject to specified exceptions, the Company is restricted from soliciting, initiating or knowingly encouraging, inducing or facilitating, or participating in any discussions or negotiations with any person regarding, or cooperating in any way with any person with respect to, any alternative proposal or any inquiry or proposal that would reasonably be expected to lead to an alternative proposal. While the Board is permitted to change its recommendation to stockholders prior to the special meeting under certain circumstances, namely if the Company is in receipt of a superior proposal or an intervening event has occurred, before the Board changes its recommendation to stockholders in such circumstances, the Company must, if requested by Dynegy, negotiate with Dynegy regarding potential amendments to the Merger Agreement. The Company may terminate the Merger Agreement and enter into an agreement with respect to a superior proposal only if specified conditions have been satisfied, including compliance with the provisions of the Merger Agreement restricting solicitation of alternative proposals and requiring payment of a termination fee of $100 million in certain circumstances. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of the Company from considering or proposing an alternative acquisition, even if such third party were prepared to pay consideration with a higher per share cash or market value than the market value proposed to be received or realized in the Merger, or could result in a potential competing acquirer proposing to pay a lower price than it would otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances. As a result of these restrictions, the Company may not be able to enter into an agreement with respect to a more favorable alternative transaction without incurring potentially significant liabilities in respect of the Merger.
If the Merger Agreement is terminated because the Board changes its recommendation to stockholders or the Company enters into a definitive agreement for a superior proposal, the Company will be required to pay Dynegy a termination fee of $100 million. If such a termination fee is payable, the payment of this fee could have a material adverse effect on the financial condition, results of operations and cash flows of the Company.
Current stockholders of the Company may have a reduced ownership and voting interest after the Merger and will exercise less influence over management of the combined company.
Upon completion of the Merger, stockholders of the Company will own approximately 79% of the combined company. Stockholders of the Company currently have the right to vote for the Board and on other matters affecting the Company. When the Merger occurs, each Dynegy stockholder will receive 0.652 shares of common stock of the Company per share of Dynegy common stock, resulting in a percentage ownership of the combined company that is smaller than the Company's stockholders' percentage ownership of the Company prior to the Merger. As a result of these reduced ownership percentages, current stockholders of the Company may have less influence on the combined company than they now have with respect to the Company.
Item 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
None.
Item 3. | DEFAULTS UPON SENIOR SECURITIES |
None.
Item 4. | MINE SAFETY DISCLOSURES |
Vistra Energy currently owns and operates 12 surface lignite coal mines in Texas to provide fuel for its 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 Vistra Energy's mines, 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 5. | OTHER INFORMATION |
Election of Chairman of the Board
On October 25, 2017, upon the recommendation of the Nominating and Governance Committee of the Board, Scott B. Helm was elected chairman of the Board. Mr. Helm was elected a director and appointed as a member of the Audit Committee of the Board on July 14, 2017.
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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) | Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession | |||||||
2(a) | 333-215288 Amendment No. 3 to Form S-1 (filed May 1, 2017) | 2.1 | — | |||||
2(b) | 001-38086 Form 8-K (filed October 31, 2017) | 2.1 | — | |||||
(3(i)) | Articles of Incorporation | |||||||
3(a) | 333-215288 Amendment No. 3 to Form S-1 (filed May 1, 2017) | 3.1 | ||||||
3(b) | 333-215288 Amendment No. 3 to Form S-1 (filed May 1, 2017) | 3.2 | — | |||||
(3(ii)) | By-laws | |||||||
3(c) | 333-215288 Amendment No. 3 to Form S-1 (filed May 1, 2017) | 3.3 | — | |||||
(4) | Instruments Defining the Rights of Security Holders, Including Indentures | |||||||
4(a) | 333-215288 Amendment No. 3 to Form S-1 (filed May 1, 2017) | 4.1 | — | |||||
(10) | Material Contracts | |||||||
10(a) | 001-38086 Form 8-K (filed July 7, 2017) | 10(a) | — | |||||
10(b) | 001-38086 Form 8-K (filed August 17, 2017) | 10.1 | — | |||||
10(c) | 001-38086 Form 8-K (filed October 31, 2017) | 10.1 | — | |||||
10(d) | 001-38086 Form 8-K (filed October 31, 2017) | 10.2 | — | |||||
(31) | Rule 13a-14(a) / 15d-14(a) Certifications | |||||||
31(a) | — | |||||||
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Exhibits | Previously Filed With File Number* | As Exhibit | ||||||
31(b) | — | |||||||
(32) | Section 1350 Certifications | |||||||
32(a) | — | |||||||
32(b) | — | |||||||
(95) | Mine Safety Disclosures | |||||||
95(a) | — | |||||||
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.
Vistra Energy Corp. | ||||
By: | /s/ TERRY L. NUTT | |||
Name: | Terry L. Nutt | |||
Title: | Senior Vice President and Controller | |||
(Principal Accounting Officer) | ||||
Date: November 2, 2017
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