VISTRA ENERGY CORP, 10-Q filed on 11/3/2017
Quarterly Report
Document And Entity Information
9 Months Ended
Sep. 30, 2017
Oct. 31, 2017
Document And Entity Information [Abstract]
 
 
Entity Registrant Name
Vistra Energy Corp 
 
Entity Central Index Key
0001692819 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Non-accelerated Filer 
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2017 
 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q3 
 
Amendment Flag
false 
 
Entity Common Stock, Shares Outstanding
 
428,210,147 
Condensed Statements Of Consolidated Income (Loss) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Sep. 30, 2016
Predecessor
Sep. 30, 2016
Predecessor
Operating revenues
$ 1,833 
$ 4,487 
$ 1,690 
$ 3,973 
Fuel, purchased power costs and delivery fees
(838)
(2,250)
(874)
(2,082)
Net gain from commodity hedging and trading activities
0 
0 
336 
282 
Operating costs
(218)
(626)
(190)
(664)
Depreciation and amortization
(178)
(519)
(157)
(459)
Selling, general and administrative expenses
(147)
(434)
(165)
(482)
Operating income
452 
658 
640 
568 
Other income
10 
29 
7 
19 
Other deductions
0 
(5)
(28)
(75)
Interest expense and related charges
(76)
(169)
(371)
(1,049)
Impacts of tax receivable agreement
138 
96 
0 
0 
Reorganization items
0 
0 
(64)
(116)
Income (loss) before income taxes
524 
609 
184 
(653)
Income tax (expense) benefit
(251)
(284)
3 
(3)
Net income (loss)
$ 273 
$ 325 
$ 187 
$ (656)
Weighted average shares of common stock outstanding - basic
427,591,426 
427,587,404 
 
 
Weighted average shares of common stock outstanding - diluted
428,312,438 
428,001,869 
 
 
Net income per weighted average share of common stock outstanding - basic
$ 0.64 
$ 0.76 
 
 
Net income per weighted average share of common stock outstanding - diluted
$ 0.64 
$ 0.76 
 
 
Condensed Statements Of Consolidated Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Sep. 30, 2016
Predecessor
Sep. 30, 2016
Predecessor
Net income (loss)
$ 273 
$ 325 
$ 187 
$ (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)
0 
0 
0 
1 
Total other comprehensive income
0 
0 
0 
1 
Comprehensive income (loss)
$ 273 
$ 325 
$ 187 
$ (655)
Condensed Statements Of Consolidated Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Sep. 30, 2016
Predecessor
Sep. 30, 2016
Predecessor
Effects related to pension and other retirement benefit obligations (net of tax benefit of $— in all periods)
$ 0 
$ 0 
$ 0 
$ 0 
Condensed Statements Of Consolidated Cash Flows (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Successor
Sep. 30, 2016
Predecessor
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
0 
45 
Impacts of Tax Receivable Agreement
(96)
0 
Stock-based compensation
13 
0 
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
0 
4,680 
TCEH DIP Roll Facilities financing fees
0 
(112)
Repayments/repurchases of debt
(32)
(2,655)
Other, net
(5)
0 
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)
0 
Odessa acquisition
(355)
0 
Lamar and Forney acquisition — net of cash acquired
0 
(1,343)
Changes in restricted cash
34 
365 
Proceeds from sales of nuclear decommissioning trust fund securities
154 
201 
Investments in nuclear decommissioning trust fund securities
(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 
Condensed Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Current assets:
 
 
Cash and cash equivalents
$ 1,054 
$ 843 
Restricted cash
61 
95 
Trade accounts receivable — net
717 
612 
Inventories
295 
285 
Commodity and other derivative contractual assets
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
650 
650 
Investments
1,183 
1,064 
Property, plant and equipment — net
4,746 
4,443 
Goodwill
1,907 
1,907 
Identifiable intangible assets — net
2,849 
3,205 
Commodity and other derivative contractual assets
129 
64 
Accumulated deferred income taxes
913 
1,122 
Other noncurrent assets
183 
239 
Total assets
15,000 
15,167 
Current liabilities:
 
 
Long-term debt due currently
44 
46 
Trade accounts payable
487 
479 
Commodity and other derivative contractual liabilities
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
4,540 
4,577 
Commodity and other derivative contractual liabilities
32 
2 
Tax Receivable Agreement obligation, Noncurrent
476 
596 
Asset retirement obligation
1,666 
1,671 
Other noncurrent liabilities and deferred credits
232 
220 
Total liabilities
8,065 
8,570 
Commitments and Contingencies
   
   
Total equity:
 
 
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 
Condensed Consolidated Balance Sheets Condensed Consolidated Balance Sheets (Parenthetical) (USD $)
Sep. 30, 2017
Dec. 31, 2016
Statement of Changes in Financial Position [Abstract]
 
 
Common Stock, Par or Stated Value Per Share
$ 0.01 
 
Common stock, shares authorized
1,800,000,000 
 
Common stock, shares outstanding
427,597,368 
427,580,232 
Business And Significant Accounting Policies
Business And Significant Accounting Policies
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.

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.
Emergence From Chapter 11 Cases
Chapter 11 Cases
    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.

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

Acquisition and Development of Generation Facilities (Notes)
Business Combination Disclosure [Text Block]

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.

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.
Goodwill And Identifiable Intangible Assets
Goodwill And Identifiable Intangible Assets
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.

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

Income Taxes
Income Taxes
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.

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.
Tax Receivable Agreement Obligation (Notes)
Tax Receivable Agreement Obligation [Table Text Block]
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.

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).
Earnings Per Share (Notes)
Earnings Per Share [Text Block]
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.
Long-Term Debt
Debtor-In-Possession Borrowing Facilities And Long-Term Debt Not Subject To Compromise

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.

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.

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.
Commitments And Contingencies
Commitments And Contingencies
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.

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.

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.

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.

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.

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.
Equity
Equity
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
)
Fair Value Measurements
Fair Value Measurements
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.

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



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.

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.

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.
Commodity And Other Derivative Contractual Assets And Liabilities
Commodity And Other Derivative Contractual Assets And Liabilities
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.

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.

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.

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.
Related Party Transactions
Related Party Transactions
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.

•
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.
Segment Information
Segment Information
.
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.
 
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

Supplementary Financial Information
Supplementary Financial Information
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.

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



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.

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



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.
Subsequent Events (Notes)
Subsequent Events [Text Block]
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.

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.

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
 
 
Business And Significant Accounting Policies (Policies)
Basis of Presentation 
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.

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 
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.
Emergence From Chapter 11 Cases (Tables)
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

Acquisition and Development of Generation Facilities (Tables)
Business Acquisition, Pro Forma Information [Table Text Block] 
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
)
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] 
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.
Goodwill And Identifiable Intangible Assets (Tables)
Schedule of identifiable intangible assets reported in the balance sheet 
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.
Schedule of amortization expense related to intangible assets (including income statement line item) 
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.
Schedule of estimated amortization expense 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

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

Income Taxes (Tables)
Calculation of Effective Income Tax Rate
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
)%
Earnings Per Share (Tables)
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]
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

Long-Term Debt (Tables)
Schedule of Long-term Debt Instruments 
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.
Schedule of Line of Credit Facilities 
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.

Equity (Tables)
Schedule of Stockholders Equity
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
)
Fair Value Measurements (Tables)
Schedule of assets and liabilities measured at fair value on a recurring basis 
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



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.

Schedule of fair value of the Level 3 assets and liabilities by major contract type (all related to commodity contracts) and the significant unobservable inputs used in the valuations 
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.

Schedule of changes in fair value of the Level 3 assets and liabilities 
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.
Commodity And Other Derivative Contractual Assets And Liabilities (Tables)
Schedule of Commodity and Other Derivative Contractual Assets and Liabilities as Reported in the Balance Sheets 
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


Schedule Of Pretax Effect On Net Income Of Derivatives Not Under Hedge Accounting, Including Realized And Unrealized Effects [Table Text Block] 
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).

Offsetting Assets and Liabilities 
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.

Schedule of Gross Notional Amounts of 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.
Credit Risk-Related Contingent Features Of Derivatives [Table Text Block] 
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.
Segment Information (Tables)
Schedule of segment reporting information, by segment
.
 
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

Supplementary Financial Information (Tables)
Schedule of other income and deductions 
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).
Schedule of restricted cash 
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



Schedule of accounts, notes, loans and financing receivable 
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



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.
Schedule of inventories by major category 
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

Summary of other investments 
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

Summary of investments in the fund 
 
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.

Summary of proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales 
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
)
Schedule of asset retirement and mining reclamation obligations 
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

Schedule of other noncurrent liabilities and deferred credits 
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



Schedule of estimated amortization of unfavorable purchase and sales contracts [Table Text Block] 
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

Schedule of fair value of debt 
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

Schedule of supplemental cash flow information 
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.
Subsequent Events (Tables)
Planned Retirements Of Generation Capacity [Table Text Block]
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
 
 



Business And Significant Accounting Policies (Details)
9 Months Ended
Sep. 30, 2017
Reportable_segment
Business and Significant Accounting Policies
 
Number of reportable segments (in reportable segments)
2 
Emergence From Chapter 11 Cases (Narrative) (Details) (USD $)
3 Months Ended 1 Months Ended
Sep. 30, 2017
Oct. 3, 2016
Oct. 3, 2016
EFH Corp. [Member]
Internal Revenue Service (IRS) [Member]
Jun. 30, 2017
Vistra Energy Corp. [Member]
EFH Corp. [Member]
Oct. 3, 2016
Vistra Energy Corp. [Member]
EFH Corp. [Member]
Oct. 31, 2017
Subsequent Event [Member]
Vistra Energy Corp. [Member]
EFH Corp. [Member]
Schedule of Reorganization Costs [Line Items]
 
 
 
 
 
 
Alternative Minimum Tax Liability
 
 
$ 14,000,000 
 
 
 
Tax Matters Agreement Obligation To Reimburse Counterparty For Alternative Minimum Tax Liability Percent
 
 
 
 
50.00% 
 
Tax Matters Agreement, Reimbursement To Counterparty To Settle Alternative Minimum Tax Liability
 
 
 
7,000,000 
 
(3,000,000)
Fresh-Start Adjustment, Increase (Decrease), Liabilities Subject to Compromise
 
33,800,000,000 
 
 
 
 
Bankruptcy Claim, Held In Escrow Account To Settle Claims Postconfirmation
54,000,000 
 
 
 
 
 
Chapter 11 Cases, Held In Escrow To Pay Professional Fees Postconfirmation
$ 7,000,000 
 
 
 
 
 
Emergence From Chapter 11 Cases (Reorganization Items) (Details) (Predecessor, USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2016
Predecessor
 
 
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 
Acquisition and Development of Generation Facilities (Odessa Acquisition) (Details) (Successor, Odessa-Ector Power Partners, L.P. [Member], La Frontera Holdings, LLC [Member], USD $)
In Millions, unless otherwise specified
1 Months Ended
Aug. 31, 2017
Aug. 1, 2017
Megawatt-hour
Successor |
Odessa-Ector Power Partners, L.P. [Member] |
La Frontera Holdings, LLC [Member]
 
 
Electricity Generation Facility Capacity
 
1,054 
Purchase And Sale Agreement, Aggregate Purchase Price
$ 355 
 
Earn-Out Provision, Initial Fair Value Included In Purchase Price
$ 16 
 
Acquisition and Development of Generation Facilities (Upton Solar Development) (Details) (Successor, USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Payments to Acquire Other Productive Assets
$ 129 
Luminant Generation Company LLC [Member] |
Upton County 2 Solar Facility [Member]
 
Electricity Generation Facility Capacity
180 
Acquisition and Development of Generation Facilities (Forney and Lamar Acquisition) (Details) (Predecessor, La Frontera Holdings, LLC [Member], Texas Competitive Electric Holdings Company LLC [Member], La Frontera Ventures, LLC [Member], USD $)
In Millions, unless otherwise specified
1 Months Ended
Apr. 30, 2016
Apr. 4, 2016
Megawatt-hour
Predecessor |
La Frontera Holdings, LLC [Member] |
Texas Competitive Electric Holdings Company LLC [Member] |
La Frontera Ventures, LLC [Member]
 
 
Number Of Natural Gas Fueled Generation Facilities Purchased
2 
 
Electricity Generation Facility Capacity
 
3,000 
Purchase And Sale Agreement, Aggregate Purchase Price
$ 1,313 
 
Purchase And Sale Agreement, Repayment Of Existing Project Financing At Closing
950 
 
Purchase And Sale Agreement, Cash And Net Working Capital
$ 236 
 
Acquisition and Development of Generation Facilities (Pro Forma Financial Information) (Details) (Predecessor, La Frontera Holdings, LLC [Member], USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2016
Predecessor |
La Frontera Holdings, LLC [Member]
 
Statement [Line Items]
 
Revenues
$ 4,116 
Net loss
$ (672)
Goodwill And Identifiable Intangible Assets (Goodwill) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Dec. 31, 2016
Goodwill [Line Items]
 
 
Goodwill
$ 1,907 
$ 1,907 
Retail Electric Segment [Member]
 
 
Goodwill [Line Items]
 
 
Goodwill
1,907 
1,907 
Goodwill, Expected Tax Deductible Amount
$ 1,686 
 
Business Acquisition, Goodwill, Expected Tax Deductible Term
15 years 
 
Goodwill And Identifiable Intangible Assets (Identifiable Intangible Assets Reported in the Balance Sheet) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
$ 2,213 
$ 2,179 
Accumulated Amortization
593 
203 
Total identifiable intangible assets subject to amortization, net
1,620 
1,976 
Total identifiable intangible assets
2,849 
3,205 
Retail trade names (not subject to amortization) [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount, Unamortized Intangibles
1,225 
1,225 
Mineral interests (not currently subject to amortization) [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount, Unamortized Intangibles
4 
4 
Retail customer relationship [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
1,648 
1,648 
Accumulated Amortization
467 
152 
Total identifiable intangible assets subject to amortization, net
1,181 
1,496 
Software and other technology-related assets [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
178 
147 
Accumulated Amortization
36 
9 
Total identifiable intangible assets subject to amortization, net
142 
138 
Electricity supply contract [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
190 1
190 1
Accumulated Amortization
9 1
2 1
Total identifiable intangible assets subject to amortization, net
181 1
188 1
Retail and wholesale contracts [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
164 
164 
Accumulated Amortization
72 
38 
Total identifiable intangible assets subject to amortization, net
92 
126 
Other Identifiable Intangible Assets [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
33 2
30 2
Accumulated Amortization
9 2
2 2
Total identifiable intangible assets subject to amortization, net
$ 24 2
$ 28 2
Goodwill And Identifiable Intangible Assets (Estimated Amortization of Identifiable Intangible Assets) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
 
2017
$ 560 
2018
374 
2019
266 
2020
198 
2021
$ 130 
Income Taxes (Calculation of Effective Tax Rate)(Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Effective tax rate at federal statutory rate
35.00% 
35.00% 
35.00% 
35.00% 
Successor
 
 
 
 
Income (loss) before income taxes
$ 524 
 
$ 609 
 
Income tax (expense) benefit
(251)
 
(284)
 
Effective tax rate
47.90% 
 
46.60% 
 
Predecessor
 
 
 
 
Income (loss) before income taxes
 
184 
 
(653)
Income tax (expense) benefit
 
$ 3 
 
$ (3)
Effective tax rate
 
(1.60%)
 
(0.50%)
Income Taxes (Accounting for Uncertainty in Income Taxes) (Details) (Texas Comptroller Of Public Accounts [Member], USD $)
In Millions, unless otherwise specified
1 Months Ended
Sep. 30, 2016
Texas Comptroller Of Public Accounts [Member]
 
Income Tax Examination [Line Items]
 
Tax Payment Related To Settlement With Taxing Authority, Net
$ 12 
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities
$ 27 
Tax Receivable Agreement Obligation (Details) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Dec. 31, 2016
Estimated Future Tax Payments Under Tax Receivables Agreement, Approximate Amount Attributable To First Fifteen Tax Years After Emergence, Percent
 
 
50.00% 
 
 
Tax Receivable Agreement obligation
$ 500,000,000 
 
$ 500,000,000 
 
$ 596,000,000 
Effective tax rate at federal statutory rate
35.00% 
35.00% 
35.00% 
35.00% 
 
Estimated Undiscounted Future Payments Under Tax Receivable Agreement
 
 
2,200,000,000 
 
 
Tax Receivable Agreement obligation, current
24,000,000 
 
24,000,000 
 
 
Successor
 
 
 
 
 
Percent Of Cash Tax Savings Due Tax Receivable Agreement Rights Holders
 
 
85.00% 
 
 
Additions (Reductions) To Tax Receivable Agreement Obligation
(160,000,000)
 
 
 
 
Impacts of tax receivable agreement
138,000,000 
 
96,000,000 
 
 
Accretion Expense
$ 22,000,000 
 
$ 64,000,000 
 
 
Earnings Per Share (Details) (Successor, USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2017
Successor
 
 
Net Income Available to Common Stockholders, Basic
$ 273 
$ 325 
Weighted average shares of common stock outstanding - basic
427,591,426 
427,587,404 
Net income per weighted average share of common stock outstanding - basic
$ 0.64 
$ 0.76 
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements
721,012 
414,465 
Net Income Available to Common Stockholders, Diluted
$ 273 
$ 325 
Weighted average shares of common stock outstanding - diluted
428,312,438 
428,001,869 
Net income per weighted average share of common stock outstanding - diluted
$ 0.64 
$ 0.76 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
85,393 
490,345 
Long-Term Debt (Long-Term Debt) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Debt Instrument [Line Items]
 
 
Long-term debt, including amounts due currently
$ 4,584 
$ 4,623 
Long-term debt due currently
44 
46 
Long-term debt, less amounts due currently
4,540 
4,577 
Vistra Operations Credit Facility [Member] |
Line of Credit [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term debt, including amounts due currently
4,484 
4,515 
Debt Instrument, Unamortized Premium
22 
25 
Debt Instrument, Unamortized Discount
2 
2 
Unamortized Debt Issuance Expense
7 
8 
PrefCo Mandatorily Redeemable Preferred Stock [Member] |
Mandatorily Redeemable Preferred Stock [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term debt, including amounts due currently
70 
70 
Building Financing 8.82% due semiannually through February 11, 2022 [Member] |
Construction Loans [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term debt, including amounts due currently
30 
36 
Debt Instrument, Interest Rate, Stated Percentage
8.82% 
 
Capital Lease Obligations [Member] |
Capital Lease Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term debt, including amounts due currently
$ 0 
$ 2 
Long-Term Debt (Vistra Operations Credit Facilities) (Details) (Vistra Operations Company LLC [Member], Line of Credit [Member], USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Maximum Borrowing Capacity
$ 5,360 
Line Of Credit Facility, Borrowings Outstanding
4,471 
Line of Credit Facility, Remaining Borrowing Capacity
1,030 
Senior Secured Revolving Credit Facility [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Maximum Borrowing Capacity
860 1
Line Of Credit Facility, Borrowings Outstanding
0 1
Line of Credit Facility, Remaining Borrowing Capacity
860 1
Debt Instrument, Basis Spread on Variable Rate
2.75% 
Senior Secured Initial Term Loan B, Senior Secured Incremental Term Loan B And Term Loan C Facilities [Member] [Member]
 
Line of Credit Facility [Line Items]
 
Debt Instrument, Basis Spread on Variable Rate
2.75% 
Line of Credit Facility, Interest Rate at Period End
3.98% 
Senior Secured Revolving Credit Facility Letter Of Credit Sub-Facility [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Maximum Borrowing Capacity
600 
Senior Secured Initial Term Loan B Facility [Member] [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Maximum Borrowing Capacity
2,850 2 3
Line Of Credit Facility, Borrowings Outstanding
2,829 2 3
Line of Credit Facility, Remaining Borrowing Capacity
0 2 3
Senior Secured Incremental Term Loan B Facility [Member] [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Maximum Borrowing Capacity
1,000 2
Line Of Credit Facility, Borrowings Outstanding
992 2
Line of Credit Facility, Remaining Borrowing Capacity
0 2
Senior Secured Term Loan C Facility [Member] [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Maximum Borrowing Capacity
650 4
Line Of Credit Facility, Borrowings Outstanding
650 4
Line Of Credit Facility, Unused Letter Of Credit Capacity
170 4
Line Of Credit Facility, Letters Of Credit Outstanding
480 
Senior Secured Initial Term Loan B And Incremental Term Loan B Facilities [Member]
 
Line of Credit Facility [Line Items]
 
Line Of Credit Facility, Percentage Of Debt Required To Be Repaid Annually
1.00% 
Minimum [Member] |
Senior Secured Initial Term Loan B, Senior Secured Incremental Term Loan B And Term Loan C Facilities [Member] [Member]
 
Line of Credit Facility [Line Items]
 
Debt Instrument, Interest Rate, Stated Percentage
0.75% 
Maximum [Member] |
Senior Secured Revolving Credit Facility [Member]
 
Line of Credit Facility [Line Items]
 
Debt Covenant, Outstanding Borrowings To Outstanding Commitments Threshold, Amount Of Letters Of Credit Excluded
$ 100 
Debt Covenant, Outstanding Borrowings To Outstanding Commitments Threshold, Percent
30.00% 
Debt Covenant, Net First Lien Debt To EBITDA Threshold
4.25 
Long-Term Debt (Interest Rate Swaps) (Details) (Interest Rate Swap [Member], USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Derivative, Notional Amount
$ 3,000 1
$ 3,000 1
Minimum [Member]
 
 
Effective Interest Rate Debt Fixed Based On Derivative Contracts
4.75% 
 
Maximum [Member]
 
 
Effective Interest Rate Debt Fixed Based On Derivative Contracts
4.88% 
 
Long-Term Debt (TCEH Debtor-In-Possession Facilities) (Details) (Predecessor, Texas Competitive Electric Holdings Company LLC [Member], USD $)
In Millions, unless otherwise specified
Sep. 30, 2016
Debtor-In-Possession Roll Facility [Member]
Jul. 31, 2016
Debtor-In-Possession Facility [Member]
Line of Credit Facility [Line Items]
 
 
Debtor-in-Possession Financing, Amount Arranged
$ 4,250 
$ 3,375 
Commitments And Contingencies (Narrative) (Details) (USD $)
1 Months Ended 9 Months Ended
Oct. 31, 2015
Aug. 31, 2015
Sep. 30, 2017
Pending Litigation [Member]
EPA Versus Luminant and Big Brown Power Company (Big Brown and Martin Lake Generation Facilities) [Member]
Minimum [Member]
Sep. 30, 2017
Pending Litigation [Member]
EPA Versus Luminant and Big Brown Power Company (Big Brown and Martin Lake Generation Facilities) [Member]
Maximum [Member]
Sep. 30, 2017
United States Environmental Protection Agency [Member]
Sep. 30, 2017
Luminant Generation Company LLC [Member]
United States Environmental Protection Agency [Member]
Sep. 30, 2017
Financial Standby Letter of Credit [Member]
Vistra Operations Company LLC [Member]
Sep. 30, 2017
Support Risk Management And Trading Margin Requirements Including Over The Counter Hedging Transactions And Collateral Postings With Electric Reliability Council Of Texas [Member]
Financial Standby Letter of Credit [Member]
Vistra Operations Company LLC [Member]
Sep. 30, 2017
Support Executory Contracts And Insurance Agreements [Member]
Financial Standby Letter of Credit [Member]
Vistra Operations Company LLC [Member]
Sep. 30, 2017
Support Retail Electric Provider's financial requirements with the Public Utility Commission of Texas [Member]
Financial Standby Letter of Credit [Member]
Vistra Operations Company LLC [Member]
Sep. 30, 2017
Miscellaneous credit support requirements [Member]
Financial Standby Letter of Credit [Member]
Vistra Operations Company LLC [Member]
Commitments and Contingencies [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Letters of Credit
 
 
 
 
 
 
$ 480,000,000 
$ 350,000,000 
$ 46,000,000 
$ 55,000,000 
$ 29,000,000 
Loss Contingency Damages Sought Value Per Day
 
 
$ 32,500 
$ 37,500 
 
 
 
 
 
 
 
EPA Rule Addressing Greenhouse Gas Emissions From Existing Electricity Generation Plants, State-Specific Emission Rate Goals, Percent Reduction From 2012 Levels To 2030 Levels
 
30.00% 
 
 
 
 
 
 
 
 
 
EPA Rule Addressing Greenhouse Gas Emissions From Existing Electricity Generation Plants, Number Of States Challenging Rule
27 
 
 
 
 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Number Of Components Of Federal Program
 
 
 
 
2 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Reasonable Progress Program, Number Of Electricity Generation Units In Texas, Affected By The EPA's Proposed FIP On Texas, Units Subject To New Scrubbers
 
 
 
 
7 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Reasonable Progress Program, Number Of Electricity Units In Texas, Affected By The EPA's Proposed FIP On Texas, Units Subject To Upgrades To Existing Scrubbers
 
 
 
 
7 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Best Available Retrofit Technology, Number Of Units In Texas Subject To New Scrubbers
 
 
 
 
12 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Best Available Retrofit Technology, Number Of Units In Texas Subject To Upgrades To Existing Scrubbers
 
 
 
 
4 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Best Available Retrofit Technology Alternative, Sulfur Dioxide Emissions, Number of Unit In Texas Subject To Rule, Total
 
 
 
 
39 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Best Available Retrofit Technology Alternative, Sulfur Dioxide Emissions, Number Of Units In Texas Subject To Rule, BART-Eligible Units
 
 
 
 
30 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Best Available Retrofit Technology Alternative, Sulfur Dioxide Emissions, Number Of Units In Texas Subject To Rule, Co-Located With BART-Eligible Units
 
 
 
 
3 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Best Available Retrofit Technology Alternative, Sulfur Dioxide Emissions, Number Of Units In Texas Subject To Rule, Based On Visibility Impact Analysis Units
 
 
 
 
6 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Best Available Retrofit Technology Alternative, Sulfur Dioxide Emissions In Texas Represented By BART-Eligible Units, Percent
 
 
 
 
89.00% 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Best Available Retrofit Technology Alternative, CSAPR Sulfur Dioxide Allowance Allocations In Texas Represented By BART-Eligible Units, Percent
 
 
 
 
85.00% 
 
 
 
 
 
 
Clean Air Act, Regional Haze Program, Best Available Retrofit Technology Alternative, Sulfur Dioxide Annual Emission Allowances Allocated To Units Covered By Program
 
 
 
 
 
91,222 
 
 
 
 
 
Equity (Narrative) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Dec. 31, 2016
Sep. 30, 2017
Vistra Energy Corp. [Member]
Vistra Operations Company LLC [Member]
Sep. 30, 2017
Vistra Energy Corp. [Member]
Vistra Operations Company LLC [Member]
Debt Instrument [Line Items]
 
 
 
 
Maximum Allowable Distribution To Parent Company By Consolidated Subsidiary Without Consent
 
 
$ 980 
$ 980 
Cash Dividends Paid to Parent Company by Consolidated Subsidiaries
 
 
$ 67 
$ 537 
Equity
 
 
 
 
Common stock, shares authorized
1,800,000,000 
 
 
 
Common stock, shares outstanding
427,597,368 
427,580,232 
 
 
Equity (Changes to Equity) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Dec. 31, 2016
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Common Stock [Member]
Dec. 31, 2016
Successor
Common Stock [Member]
Sep. 30, 2017
Successor
Additional Paid-in Capital [Member]
Sep. 30, 2017
Successor
Retained Earnings [Member]
Sep. 30, 2017
Successor
Accumulated Other Comprehensive Income (Loss) [Member]
Dec. 31, 2016
Successor
Accumulated Other Comprehensive Income (Loss) [Member]
Sep. 30, 2016
Predecessor
Sep. 30, 2016
Predecessor
Sep. 30, 2016
Predecessor
Common Stock [Member]
Sep. 30, 2016
Predecessor
Accumulated Other Comprehensive Income (Loss) [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance
$ 6,935 
$ 6,597 
 
$ 6,597 
$ 4 1
$ 4 1
$ 7,742 
$ (1,155)
$ 6 
$ 6 
 
$ (22,884)
$ (22,851)
$ (33)
Net income (loss)
 
 
273 
325 
 
 
 
325 
 
 
187 
(656)
(656)
 
Effects of stock-based incentive compensation plans
 
 
 
13 
 
 
13 
 
 
 
 
 
 
 
Net effects of cash flow hedges
 
 
 
 
 
 
 
 
 
 
 
(1)
 
(1)
Ending balance
$ 6,935 
$ 6,597 
$ 6,935 
$ 6,935 
$ 4 1
$ 4 1
$ 7,755 
$ (830)
$ 6 
$ 6 
$ (23,539)
$ (23,539)
$ (23,507)
$ (32)
Fair Value Measurements (Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Assets:
 
 
Nuclear decommissioning trust
$ 1,132 
$ 1,012 
Equity Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
767 1
672 1
Debt Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
365 2
340 2
Fair Value, Measurements, Recurring [Member]
 
 
Assets:
 
 
Sub-total
10 3
13 3
Liabilities:
 
 
Total liabilities
10 3
13 3
Fair Value, Measurements, Recurring [Member] |
Equity Securities [Member]
 
 
Assets:
 
 
Assets measured at net asset value
281 4 5
247 4 5
Fair Value, Measurements, Recurring [Member] |
Commodity contracts [Member]
 
 
Assets:
 
 
Derivative Assets
3 3
 
Liabilities:
 
 
Derivative Liabilities
3 3
 
Fair Value, Measurements, Recurring [Member] |
Interest Rate Swap [Member]
 
 
Assets:
 
 
Derivative Assets
7 3
13 3
Liabilities:
 
 
Derivative Liabilities
7 3
13 3
Fair Value, Measurements, Recurring [Member] |
Total [Member]
 
 
Assets:
 
 
Sub-total
1,162 
1,179 
Total assets
1,443 
1,426 
Liabilities:
 
 
Total liabilities
104 
361 
Fair Value, Measurements, Recurring [Member] |
Total [Member] |
Equity Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
486 4
425 4
Fair Value, Measurements, Recurring [Member] |
Total [Member] |
Debt Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
365 4
340 4
Fair Value, Measurements, Recurring [Member] |
Total [Member] |
Commodity contracts [Member]
 
 
Assets:
 
 
Derivative Assets
302 
396 
Liabilities:
 
 
Derivative Liabilities
81 
332 
Fair Value, Measurements, Recurring [Member] |
Total [Member] |
Interest Rate Swap [Member]
 
 
Assets:
 
 
Derivative Assets
9 
18 
Liabilities:
 
 
Derivative Liabilities
23 
29 
Level 1 [Member] |
Fair Value, Measurements, Recurring [Member]
 
 
Assets:
 
 
Sub-total
513 
592 
Liabilities:
 
 
Total liabilities
28 
302 
Level 1 [Member] |
Fair Value, Measurements, Recurring [Member] |
Equity Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
486 4
425 4
Level 1 [Member] |
Fair Value, Measurements, Recurring [Member] |
Commodity contracts [Member]
 
 
Assets:
 
 
Derivative Assets
27 
167 
Liabilities:
 
 
Derivative Liabilities
28 
302 
Level 2 [Member] |
Fair Value, Measurements, Recurring [Member]
 
 
Assets:
 
 
Sub-total
457 
476 
Liabilities:
 
 
Total liabilities
41 
31 
Level 2 [Member] |
Fair Value, Measurements, Recurring [Member] |
Debt Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
365 4
340 4
Level 2 [Member] |
Fair Value, Measurements, Recurring [Member] |
Commodity contracts [Member]
 
 
Assets:
 
 
Derivative Assets
90 
131 
Liabilities:
 
 
Derivative Liabilities
25 
15 
Level 2 [Member] |
Fair Value, Measurements, Recurring [Member] |
Interest Rate Swap [Member]
 
 
Assets:
 
 
Derivative Assets
2 
5 
Liabilities:
 
 
Derivative Liabilities
16 
16 
Level 3 [Member]
 
 
Assets:
 
 
Sub-total
182 6
98 6
Liabilities:
 
 
Total liabilities
25 6
15 6
Level 3 [Member] |
Fair Value, Measurements, Recurring [Member]
 
 
Assets:
 
 
Sub-total
182 
98 
Liabilities:
 
 
Total liabilities
25 
15 
Level 3 [Member] |
Fair Value, Measurements, Recurring [Member] |
Commodity contracts [Member]
 
 
Assets:
 
 
Derivative Assets
182 
98 
Liabilities:
 
 
Derivative Liabilities
$ 25 
$ 15 
Commodity And Other Derivative Contractual Assets And Liabilities (Financial Statement Effects of Derivatives) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
$ 301 
$ 401 
Derivative liabilities, Fair Value, Gross Liability
(94)
(348)
Derivative, Fair Value, Net
207 
53 
Current assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets And Liability, Fair Value, Gross Assets
182 
350 
Noncurrent assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets And Liability, Fair Value, Gross Assets
129 
64 
Current liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets And Liability, Fair Value, Gross Liability
(72)
(359)
Noncurrent Liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets And Liability, Fair Value, Gross Liability
(32)
(2)
Commodity contracts [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
299 
396 
Derivative liabilities, Fair Value, Gross Liability
(78)
(332)
Derivative asset, Fair Value, Net
299 
396 
Derivative liabilities, Fair Value, Net
(78)
(332)
Commodity contracts [Member] |
Current assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
181 
350 
Derivative liabilities, Fair Value, Gross Asset
1 
0 
Commodity contracts [Member] |
Noncurrent assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
120 
46 
Derivative liabilities, Fair Value, Gross Asset
0 
0 
Commodity contracts [Member] |
Current liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative asset, Fair Value, Gross Liability
(2)
0 
Derivative liabilities, Fair Value, Gross Liability
(53)
(330)
Commodity contracts [Member] |
Noncurrent Liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative asset, Fair Value, Gross Liability
0 
0 
Derivative liabilities, Fair Value, Gross Liability
(26)
(2)
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
2 
5 
Derivative liabilities, Fair Value, Gross Liability
(16)
(16)
Derivative asset, Fair Value, Net
2 
5 
Derivative liabilities, Fair Value, Net
(16)
(16)
Interest Rate Swap [Member] |
Current assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
0 
0 
Derivative liabilities, Fair Value, Gross Asset
0 
0 
Interest Rate Swap [Member] |
Noncurrent assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
9 
17 
Derivative liabilities, Fair Value, Gross Asset
0 
1 
Interest Rate Swap [Member] |
Current liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative asset, Fair Value, Gross Liability
(7)
(12)
Derivative liabilities, Fair Value, Gross Liability
(10)
(17)
Interest Rate Swap [Member] |
Noncurrent Liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative asset, Fair Value, Gross Liability
0 
0 
Derivative liabilities, Fair Value, Gross Liability
$ (6)
$ 0 
Commodity And Other Derivative Contractual Assets And Liabilities (Derivative (Income Statement Presentation) and Derivative type (Income Statement Presentation of Loss Reclassified from Accumulated OCI into Income)) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Operating revenues [Member]
Commodity contracts [Member]
Sep. 30, 2017
Successor
Operating revenues [Member]
Commodity contracts [Member]
Sep. 30, 2017
Successor
Fuel, Purchased Power Costs And Delivery Fees [Member]
Commodity contracts [Member]
Sep. 30, 2017
Successor
Fuel, Purchased Power Costs And Delivery Fees [Member]
Commodity contracts [Member]
Sep. 30, 2017
Successor
Net gain from commodity hedging and trading activities [Member]
Commodity contracts [Member]
Sep. 30, 2017
Successor
Net gain from commodity hedging and trading activities [Member]
Commodity contracts [Member]
Sep. 30, 2017
Successor
Interest Expense [Member]
Interest Rate Swap [Member]
Sep. 30, 2017
Successor
Interest Expense [Member]
Interest Rate Swap [Member]
Sep. 30, 2016
Predecessor
Sep. 30, 2016
Predecessor
Sep. 30, 2016
Predecessor
Operating revenues [Member]
Commodity contracts [Member]
Sep. 30, 2016
Predecessor
Operating revenues [Member]
Commodity contracts [Member]
Sep. 30, 2016
Predecessor
Fuel, Purchased Power Costs And Delivery Fees [Member]
Commodity contracts [Member]
Sep. 30, 2016
Predecessor
Fuel, Purchased Power Costs And Delivery Fees [Member]
Commodity contracts [Member]
Sep. 30, 2016
Predecessor
Net gain from commodity hedging and trading activities [Member]
Commodity contracts [Member]
Sep. 30, 2016
Predecessor
Net gain from commodity hedging and trading activities [Member]
Commodity contracts [Member]
Sep. 30, 2016
Predecessor
Interest Expense [Member]
Interest Rate Swap [Member]
Sep. 30, 2016
Predecessor
Interest Expense [Member]
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net gain (loss)
$ 171 
$ 312 
$ 166 1
$ 333 1
$ 9 1
$ 3 1
$ 0 1
$ 0 1
$ (4)2
$ (24)2
$ 239 
$ 194 
$ 0 1
$ 0 1
$ 0 1
$ 0 1
$ 239 1
$ 194 1
$ 0 2
$ 0 2
Commodity And Other Derivative Contractual Assets And Liabilities (Derivative Assets and Liabilities From Balance Sheet to Net Amounts After Consideration Netting Arrangements with Counterparties and Financial Collateral) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Derivatives, Fair Value [Line Items]
 
 
Derivative assets: Amounts Presented in Balance Sheet
$ 301 
$ 401 
Derivative assets: Offsetting Financial Instruments
(64)1
(193)1
Derivative assets: Financial Collateral (Received) Pledged
(9)2
(20)2
Derivative assets: Net Amounts
228 
188 
Derivative liabilities: Amounts Presented in Balance Sheet
(94)
(348)
Derivative liabilities: Offsetting Financial Instruments
64 1
193 1
Derivative liabilities: Financial Collateral (Received) Pledged
1 2
136 2
Derivative liabilities: Net Amounts
(29)
(19)
Derivative, Fair Value, Net
207 
53 
Derivative (Assets) Liability, Fair Value of Collateral, Net
(8)2
116 2
Derivative Assets (Liability), Fair Value, Amount Offset Against Collateral
199 
169 
Commodity contracts [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets: Amounts Presented in Balance Sheet
299 
396 
Derivative assets: Offsetting Financial Instruments
(64)1
(193)1
Derivative assets: Financial Collateral (Received) Pledged
(9)2
(20)2
Derivative assets: Net Amounts
226 
183 
Derivative liabilities: Amounts Presented in Balance Sheet
(78)
(332)
Derivative liabilities: Offsetting Financial Instruments
64 1
193 1
Derivative liabilities: Financial Collateral (Received) Pledged
1 2
136 2
Derivative liabilities: Net Amounts
(13)
(3)
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets: Amounts Presented in Balance Sheet
2 
5 
Derivative assets: Offsetting Financial Instruments
0 
0 
Derivative assets: Financial Collateral (Received) Pledged
0 
0 
Derivative assets: Net Amounts
2 
5 
Derivative liabilities: Amounts Presented in Balance Sheet
(16)
(16)
Derivative liabilities: Offsetting Financial Instruments
0 
0 
Derivative liabilities: Financial Collateral (Received) Pledged
0 
0 
Derivative liabilities: Net Amounts
$ (16)
$ (16)
Commodity And Other Derivative Contractual Assets And Liabilities (Derivative Volumes) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
MMBTU
Dec. 31, 2016
MMBTU
Natural Gas Derivative [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
1,420,000,000 1
1,282,000,000 1
Electricity (in GWh) [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
106,190 
75,322 
Congestion Revenue RIghts (in GWh) [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
96,269 2
126,573 2
Coal (in tons) [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
4,000,000 
12,000,000 
Fuel oil (in gallons) [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
19,000,000 
34,000,000 
Uranium (in pounds) [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
450,000 
25,000 
Interest rate swaps - Floating/fixed [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative, Notional Amount
$ 3,000 3
$ 3,000 3
Related Party Transactions (Narrrative) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Successor
Maximum [Member]
Sep. 30, 2016
Predecessor
Texas Competitive Electric Holdings Company LLC [Member]
Oncor [Member]
Sep. 30, 2016
Predecessor
Texas Competitive Electric Holdings Company LLC [Member]
Oncor [Member]
Sep. 30, 2016
Predecessor
Texas Competitive Electric Holdings Company LLC [Member]
Energy Future Holdings Corp. [Member]
Sep. 30, 2016
Predecessor
Texas Competitive Electric Holdings Company LLC [Member]
Energy Future Holdings Corp. [Member]
Sep. 30, 2017
Legal Expenses Paid On Behalf of Selling Stockholders [Member]
Successor
Sep. 30, 2017
Legal Expenses Paid On Behalf of Selling Stockholders [Member]
Successor
Related Party Transaction [Line Items]
 
 
 
 
 
 
 
Registration Rights Agreement, Number Of Days To Convert S-1 Registration Statement To S-3 Registration Statement
30 days 
 
 
 
 
 
 
Registration Rights Agreement, Demand Registration, Number Of Days To File S-1 Registration Statement
45 days 
 
 
 
 
 
 
Registration Rights Agreement, Demand Registration, Number Of Days To File S-3 Registration Statement
30 days 
 
 
 
 
 
 
Registration Rights Agreement, Demand Registration, Number Of Days Between Initial Registration And Effective Date
120 days 
 
 
 
 
 
 
Legal Fees
 
 
 
 
 
$ 1 
$ 1 
Related party transaction, amounts of transaction
 
265 
700 
 
 
 
 
Selling, general and administrative expenses from transactions with related party
 
 
 
51 
157 
 
 
Delivery fee surcharge remitted to related party
 
6 
15 
 
 
 
 
Related Party Tax Expense, Due to Affiliates, Current
 
 
 
 
$ 22 
 
 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Reportable_segment
Dec. 31, 2016
Sep. 30, 2017
Intersegment Eliminations [Member]
Dec. 31, 2016
Intersegment Eliminations [Member]
Sep. 30, 2017
Wholesale Generation Segment [Member]
Operating Segments [Member]
Dec. 31, 2016
Wholesale Generation Segment [Member]
Operating Segments [Member]
Sep. 30, 2017
Retail Electric Segment [Member]
Operating Segments [Member]
Dec. 31, 2016
Retail Electric Segment [Member]
Operating Segments [Member]
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Corporate, Non-Segment [Member]
Sep. 30, 2017
Successor
Corporate, Non-Segment [Member]
Sep. 30, 2017
Successor
Intersegment Eliminations [Member]
Sep. 30, 2017
Successor
Intersegment Eliminations [Member]
Sep. 30, 2017
Successor
Wholesale Generation Segment [Member]
Sep. 30, 2017
Successor
Wholesale Generation Segment [Member]
Sep. 30, 2017
Successor
Retail Electric Segment [Member]
Sep. 30, 2017
Successor
Retail Electric Segment [Member]
Sep. 30, 2017
Successor
Operating revenues [Member]
Wholesale Generation Segment [Member]
Sep. 30, 2017
Successor
Operating revenues [Member]
Wholesale Generation Segment [Member]
Sep. 30, 2017
Successor
Operating revenues [Member]
Wholesale Generation Segment [Member]
Intersegment Eliminations [Member]
Sep. 30, 2017
Successor
Operating revenues [Member]
Wholesale Generation Segment [Member]
Intersegment Eliminations [Member]
Sep. 30, 2017
Successor
Operating revenues [Member]
Retail Electric Segment [Member]
Sep. 30, 2017
Successor
Operating revenues [Member]
Retail Electric Segment [Member]
Sep. 30, 2017
Successor
Fuel, Purchased Power Costs And Delivery Fees [Member]
Retail Electric Segment [Member]
Intersegment Eliminations [Member]
Sep. 30, 2017
Successor
Fuel, Purchased Power Costs And Delivery Fees [Member]
Retail Electric Segment [Member]
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of reportable segments (in reportable segments)
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
$ 1,833 
$ 4,487 
 
 
$ (656)1
$ (1,406)1
$ 1,203 1
$ 2,757 1
$ 1,286 1
$ 3,136 1
 
 
 
 
 
 
 
 
Depreciation and amortization
 
 
 
 
 
 
 
 
178 
519 
10 
30 
 
 
60 
167 
108 
322 
 
 
 
 
 
 
 
 
Operating income (loss)
 
 
 
 
 
 
 
 
452 
658 
(14)
(47)
 
 
469 
651 
(3)
54 
 
 
 
 
 
 
 
 
Unrealized mark-to-market net losses on interest rate swaps
 
 
 
 
 
 
 
 
3 
(3)
 
 
 
 
 
 
 
 
137 
204 
89 
171 
2 
11 
(89)
(171)
Net income (loss)
 
 
 
 
 
 
 
 
273 
325 
(203)
(405)
 
 
469 
653 
7 
77 
 
 
 
 
 
 
 
 
Net Income (Loss) Available to Common Stockholders, Basic
 
 
 
 
 
 
 
 
273 
325 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$ 15,000 
$ 15,167 
$ 1,629 
$ 2,462 
$ 7,445 
$ 6,952 
$ 5,926 
$ 5,753 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
[1] )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 result
Supplementary Financial Information (Other Income and Deductions) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Corporate and Other Nonsegment [Member]
Sep. 30, 2017
Successor
Corporate and Other Nonsegment [Member]
Sep. 30, 2017
Successor
Wholesale Generation Segment [Member]
Sep. 30, 2017
Successor
Wholesale Generation Segment [Member]
Sep. 30, 2016
Predecessor
Sep. 30, 2016
Predecessor
Other income:
 
 
 
 
 
 
 
 
Office space sublease rental income
 
 
$ 3 1
$ 9 1
 
 
$ 0 
$ 0 
Insurance settlement
0 
0 
 
 
 
 
0 
9 
Sale of land
 
 
 
 
1 2
4 2
2 
2 
Interest income
4 
10 
 
 
 
 
2 
3 
All other
2 
6 
 
 
 
 
3 
5 
Total other income
10 
29 
 
 
 
 
7 
19 
Other deductions:
 
 
 
 
 
 
 
 
Write-off of generation equipment
 
 
 
 
0 
2 2
4 
45 
Adjustment to asbestos liability
0 
0 
 
 
 
 
(11)
(11)
Fees associated with TCEH DIP Roll Facilities
0 
0 
 
 
 
 
5 
5 
All other
0 
3 
 
 
 
 
8 
14 
Total other deductions
$ 0 
$ 5 
 
 
 
 
$ 28 
$ 75 
Supplementary Financial Information (Restricted Cash) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Restricted Cash and Investments, Current
$ 61 
$ 95 
Restricted Cash and Investments, Noncurrent
650 
650 
Vistra Operations Credit Facility [Member]
 
 
Restricted Cash and Investments, Current
0 
0 
Restricted Cash and Investments, Noncurrent
650 
650 
Amounts related to restructuring escrow accounts [Member]
 
 
Restricted Cash and Investments, Current
61 
90 
Restricted Cash and Investments, Noncurrent
0 
0 
Other
 
 
Restricted Cash and Investments, Current
0 
5 
Restricted Cash and Investments, Noncurrent
$ 0 
$ 0 
Supplementary Financial Information (Trade Accounts Receivable and Allowance for Doubtful Accounts) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Dec. 31, 2016
Sep. 30, 2017
Successor
Sep. 30, 2016
Predecessor
Wholesale and retail trade accounts receivable
$ 738 
$ 622 
 
 
Allowance for uncollectible accounts
(21)
(10)
(21)
(13)
Trade accounts receivable — net
717 
612 
 
 
Unbilled Receivables, Current
250 
225 
 
 
Allowance for Doubtful Accounts Receivable [Roll Forward]
 
 
 
 
Allowance for uncollectible accounts receivable at beginning of period
21 
10 
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 
$ 10 
$ 21 
$ 13 
Supplementary Financial Information (Inventories by Major Category and Other Investments) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Inventories by Major Category
 
 
Materials and supplies
$ 172 
$ 173 
Fuel stock
102 
88 
Natural gas in storage
21 
24 
Total inventories
295 
285 
Other Investments
 
 
Nuclear plant decommissioning trust
1,132 
1,012 
Land
49 
49 
Miscellaneous other
2 
3 
Total other investments
$ 1,183 
$ 1,064 
Supplementary Financial Information (Nuclear Decommissioning Trust) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 12 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Dec. 31, 2016
Sep. 30, 2017
Debt Securities [Member]
Dec. 31, 2016
Debt Securities [Member]
Sep. 30, 2017
Equity Securities [Member]
Dec. 31, 2016
Equity Securities [Member]
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Sep. 30, 2016
Predecessor
Sep. 30, 2016
Predecessor
Schedule of Schedule of Decommissioning Fund Investments [Line Items]
 
 
 
 
 
 
 
 
 
 
Cost
$ 673 1
$ 642 1
$ 352 1 2
$ 333 1 2
$ 321 1 3
$ 309 1 3
 
 
 
 
Unrealized gain
465 
378 
14 2
10 2
451 3
368 3
 
 
 
 
Unrealized loss
(6)
(8)
(1)2
(3)2
(5)3
(5)3
 
 
 
 
Fair market value
1,132 
1,012 
365 2
340 2
767 3
672 3
 
 
 
 
Debt, Weighted Average Interest Rate
 
 
3.57% 
3.56% 
 
 
 
 
 
 
Decommissioning Fund Investments, Debt securities, average maturity
 
 
9 years 
9 years 
 
 
 
 
 
 
Decommissioning Fund Investments, debt maturities, one through five years, fair value
 
 
102 
 
 
 
 
 
 
 
Decommissioning Fund Investments, debt maturities, five through ten years, fair value
 
 
99 
 
 
 
 
 
 
 
Decommissioning Fund Investments, debt maturities, after ten years, fair value
 
 
164 
 
 
 
 
 
 
 
Realized gains
 
 
 
 
 
 
1 
3 
3 
3 
Realized losses
 
 
 
 
 
 
(1)
(3)
(2)
(2)
Proceeds from sales of securities
 
 
 
 
 
 
56 
154 
46 
201 
Investments in securities
 
 
 
 
 
 
$ (62)
$ (169)
$ (52)
$ (215)
Supplementary Financial Information (Property, Plant and Equipment) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Supplementary Financial Information [Abstract]
 
 
Property, plant and equipment — net
$ 4,746 
$ 4,443 
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment
$ 318 
$ 85 
Supplementary Financial Information (Asset Retirement and Mining Reclamation Obligations) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance, Liability
$ 1,726 
 
Additions:
 
 
Accretion
41 
 
Adjustment for change in estimates
7 1
 
Reductions:
 
 
Payments
(23)
 
Ending balance, Liability
1,751 
 
Less amounts due currently
(85)
 
Noncurrent liability at end of period
1,666 
1,671 
Nuclear Plant Decommissioning [Member]
 
 
Asset Retirement Obligations [Line Items]
 
 
Regulatory Assets
91 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance, Liability
1,200 
 
Additions:
 
 
Accretion
23 
 
Adjustment for change in estimates
0 
 
Reductions:
 
 
Payments
0 
 
Ending balance, Liability
1,223 
 
Less amounts due currently
0 
 
Noncurrent liability at end of period
1,223 
 
Mining Land Reclamation [Member]
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance, Liability
375 
 
Additions:
 
 
Accretion
14 
 
Adjustment for change in estimates
3 1
 
Reductions:
 
 
Payments
(23)
 
Ending balance, Liability
369 
 
Less amounts due currently
(83)
 
Noncurrent liability at end of period
286 
 
Other Asset Retirement Obligations [Member]
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance, Liability
151 
 
Additions:
 
 
Accretion
4 
 
Adjustment for change in estimates
4 1
 
Reductions:
 
 
Payments
0 
 
Ending balance, Liability
159 
 
Less amounts due currently
(2)
 
Noncurrent liability at end of period
$ 157 
 
Supplementary Financial Information (Other Noncurrent Liabilities and Deferred Credits) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2017
Dec. 31, 2016
Sep. 30, 2017
Successor
Sep. 30, 2017
Successor
Sep. 30, 2016
Predecessor
Sep. 30, 2016
Predecessor
Other Noncurrent Liabilities Noncurrent and Deferred Credits [Line Items]
 
 
 
 
 
 
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 
 
 
 
 
Amortization of Deferred Charges [Abstract]
 
 
 
 
 
 
Amortization of Unfavorable Purchase and Sales Contracts
 
 
2 
7 
6 
18 
Future Amortization Expense, Unfavorable Purchase and Sales Contracts [Abstract]
 
 
 
 
 
 
2017
10 
 
 
 
 
 
2018
11 
 
 
 
 
 
2019
9 
 
 
 
 
 
2020
9 
 
 
 
 
 
2021
$ 1 
 
 
 
 
 
Supplementary Financial Information (Fair Value of Debt) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Vistra Operations Credit Facility [Member] |
Reported Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Debt Instrument, Fair Value Disclosure
$ 4,484 
$ 4,515 
Long-Term Debt, Including Amounts Due Currently [Member] |
Reported Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Debt Instrument, Fair Value Disclosure
30 
36 
Mandatorily Redeemable Preferred Stock [Member] |
Reported Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Debt Instrument, Fair Value Disclosure
70 
70 
Fair Value, Inputs, Level 2 [Member] |
Vistra Operations Credit Facility [Member] |
Estimate of Fair Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Debt Instrument, Fair Value Disclosure
4,484 
4,552 
Fair Value, Inputs, Level 2 [Member] |
Long-Term Debt, Including Amounts Due Currently [Member] |
Estimate of Fair Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Debt Instrument, Fair Value Disclosure
27 
32 
Fair Value, Inputs, Level 2 [Member] |
Mandatorily Redeemable Preferred Stock [Member] |
Reported Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Debt Instrument, Fair Value Disclosure
$ 70 
$ 70 
Supplementary Financial Information (Supplemental Cash Flow Information) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Successor
Sep. 30, 2016
Predecessor
Cash payments related to:
 
 
Interest paid
$ 197 1
$ 1,064 1
Capitalized interest
(5)
(9)
Interest paid (net of capitalized interest)
192 1
1,055 1
Income taxes
51 
22 
Reorganization items
0 
104 2
Noncash investing and financing activities:
 
 
Construction expenditures
$ 16 3
$ 53 3
Subsequent Events (Merger Agreement) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
1 Months Ended 1 Months Ended 1 Months Ended
Sep. 30, 2017
Oct. 31, 2017
Subsequent Event [Member]
Oct. 29, 2017
Subsequent Event [Member]
Sep. 30, 2017
Vistra Energy Corp. [Member]
Oct. 29, 2017
Vistra Energy Corp. [Member]
Subsequent Event [Member]
Oct. 31, 2017
Vistra Energy Corp. [Member]
Dynegy Inc. [Member]
Subsequent Event [Member]
Oct. 29, 2017
Vistra Energy Corp. [Member]
Affiliates Of Apollo Management Holdings, L.P., Brookfield Management Private Institutional Capital Advisor (Canada), L.P. And Oaktree Capital Management, L.P. [Member]
Subsequent Event [Member]
Sep. 30, 2017
Dynegy Inc. [Member]
Oct. 29, 2017
Dynegy Inc. [Member]
Subsequent Event [Member]
Oct. 31, 2017
Dynegy Inc. [Member]
Vistra Energy Corp. [Member]
Subsequent Event [Member]
Oct. 29, 2017
Dynegy Inc. [Member]
Affiliates Of Terawatt Holding, LP And Oaktree Capital Management, L.P. [Member]
Subsequent Event [Member]
Subsequent Event [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Common Stock, Par or Stated Value Per Share
$ 0.01 
 
 
$ 0.01 
 
 
 
$ 0.01 
 
 
 
Merger Agreement, Common Stock Conversion Ratio
 
 
0.652 
 
 
 
 
 
 
 
 
Merger Agreement, Combined Company Ownership, Percent
 
 
 
 
79.00% 
 
 
 
21.00% 
 
 
Merger Agreement, Combined Company, Number Of Board Members
 
 
11 
 
8 
 
 
 
3 
 
 
Merger Agreement, Combined Company, Number Of Board Members, Class I Directors
 
 
 
 
 
 
 
 
1 
 
 
Merger Agreement, Combined Company, Number Of Board Members, Class II Directors
 
 
 
 
 
 
 
 
1 
 
 
Merger Agreement, Combined Company, Number Of Board Members, Class III Directors
 
 
 
 
 
 
 
 
1 
 
 
Merger Agreement, Combined Company, Number of Board Members, Class I Directors, If Merger Closed After Surviving Company's 2018 Annual Meeting
 
 
 
 
 
 
 
 
1 
 
 
Merger Agreement, Combined Company, Number Of Board Members, Class II Directors, If Merger Closed After Surviving Company's 2018 Annual Meeting
 
 
 
 
 
 
 
 
2 
 
 
Merger Agreement, Contract Termination Payment, Due To Failure To Obtain Regulatory Approvals
 
 
 
 
 
$ 100 
 
 
 
 
 
Merger Agreement, Contract Termination Payment, Due To Superior Offer, Acquisition Proposal Or Unforseeable Material Intervening Event
 
 
 
 
 
100 
 
 
 
87 
 
Merger Agreement, Contract Termination Payment, Due To Stockholder's Not Approving Issuance Of Surviving Company Stock Or Not Adopting Merger Agreement
 
$ 22 
 
 
 
 
 
 
 
 
 
Merger Agreement, Merger Support Agreement, Stockholders Entitled To Vote Agreeing To Support Merger Agreement, Percentage
 
 
 
 
 
 
34.00% 
 
 
 
21.00% 
Subsequent Events (Planned Retirements of Generation Facilities) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 1 Months Ended
Sep. 30, 2017
Megawatt-hour
Sep. 30, 2017
Monticello Steam Electric Station [Member]
Megawatt-hour
Sep. 30, 2017
Sandow Steam Electric Station Units 4 and 5 [Member]
Megawatt-hour
Sep. 30, 2017
Big Brown Steam Electric Station [Member]
Megawatt-hour
Oct. 31, 2017
Alcoa Corporation and Alcoa USA Corp. [Member]
Subsequent Event [Member]
Vistra Energy Corp. [Member]
Costs Associated With Planned Retirement Of Generation Facilities
 
$ 24 
 
 
 
Contract Termination Payment
 
 
 
 
$ 238 
Electricity Generation Facility Capacity
4,167 
1,880 
1,137 
1,150 
 
Number Of Electric Generation Units To Be Retired
7 
3 
2 
2