VISTRA ENERGY CORP, 10-Q filed on 5/18/2017
Quarterly Report
Document And Entity Information
3 Months Ended
Mar. 31, 2017
May 16, 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
Mar. 31, 2017 
 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q1 
 
Amendment Flag
false 
 
Entity Common Stock, Shares Outstanding
 
427,587,401 
Condensed Statements Of Consolidated Income (Loss) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Successor [Member]
Mar. 31, 2016
Predecessor [Member]
Operating revenues
$ 1,357 1
$ 1,049 
Fuel, purchased power costs and delivery fees
(683)
(554)
Net gain from commodity hedging and trading activities
0 
64 
Operating costs
(214)
(219)
Depreciation and amortization
(170)
(139)
Selling, general and administrative expenses
(135)
(162)
Operating income
155 
39 
Other income
8 
1 
Other deductions
0 
(21)
Interest income
1 
1 
Interest expense and related charges
(24)
(335)
Impacts of Tax Receivable Agreement
(21)
0 
Reorganization items
0 
(22)
Income (loss) before income taxes
119 
(337)
Income tax expense
(41)
(6)
Net income (loss)
$ 78 
$ (343)
Weighted average shares of common stock outstanding - basic
427,583,339 
 
Weighted average shares of common stock outstanding - diluted
427,800,350 
 
Net income per weighted average share of common stock outstanding - basic
$ 0.18 
 
Net income per weighted average share of common stock outstanding - diluted
$ 0.18 
 
Condensed Statements Of Consolidated Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Successor [Member]
Mar. 31, 2016
Predecessor [Member]
Net income (loss)
$ 78 
$ (343)
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 
Total other comprehensive loss
0 
0 
Comprehensive income (loss)
$ 78 
$ (343)
Condensed Statements Of Consolidated Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Successor [Member]
Mar. 31, 2016
Predecessor [Member]
Effects related to pension and other retirement benefit obligations (net of tax benefit of $— in all periods)
$ 0 
$ 0 
Condensed Statements Of Consolidated Cash Flows (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Successor [Member]
Mar. 31, 2016
Predecessor [Member]
Cash flows — operating activities:
 
 
Net income (loss)
$ 78 
$ (343)
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
 
 
Depreciation and amortization
226 
167 
Deferred income tax expense, net
42 
2 
Contract claims adjustments of Predecessor
0 
1 
Unrealized net (gain) loss from mark-to-market valuations of derivatives
(129)
41 
Write-off of intangible and other assets
0 
20 
Stock-based compensation
4 
0 
Other, net
22 
15 
Changes in operating assets and liabilities:
 
 
Margin deposits, net
113 
17 
Accrued interest
(31)
3 
Accrued property taxes
(71)
(30)
Accrued incentive plan payments
(73)
(64)
Other operating assets and liabilities, including liabilities subject to compromise
(40)
(20)
Cash provided by (used in) operating activities
141 
(191)
Cash flows — financing activities:
 
 
Repayments/repurchases of debt
(13)
(4)
Other, net
(5)
0 
Cash used in financing activities
(18)
(4)
Cash flows — investing activities:
 
 
Capital expenditures
(31)
(83)
Nuclear fuel purchases
(12)
(10)
Changes in restricted cash
1 
(142)
Proceeds from sales of nuclear decommissioning trust fund securities
79 
67 
Investments in nuclear decommissioning trust fund securities
(84)
(71)
Other, net
(3)
2 
Cash used in investing activities
(50)
(237)
Net change in cash and cash equivalents
73 
(432)
Cash and cash equivalents — beginning balance
843 
1,400 
Cash and cash equivalents — ending balance
$ 916 
$ 968 
Condensed Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Current assets:
 
 
Cash and cash equivalents
$ 916 
$ 843 
Restricted cash
94 
95 
Trade accounts receivable — net
482 
612 
Inventories
315 
285 
Commodity and other derivative contractual assets
231 
350 
Margin deposits related to commodity contracts
75 
213 
Other current assets
72 
75 
Total current assets
2,185 
2,473 
Restricted cash
650 
650 
Investments
1,113 
1,064 
Property, plant and equipment — net
4,415 
4,443 
Goodwill
1,907 
1,907 
Identifiable intangible assets — net
3,069 
3,205 
Commodity and other derivative contractual assets
90 
64 
Accumulated deferred income taxes
1,080 
1,122 
Other noncurrent assets
206 
239 
Total assets
14,715 
15,167 
Current liabilities:
 
 
Long-term debt due currently
45 
46 
Trade accounts payable
402 
479 
Commodity and other derivative contractual liabilities
124 
359 
Margin deposits related to commodity contracts
16 
41 
Accrued taxes
29 
31 
Accrued taxes other than income
52 
128 
Accrued interest
3 
33 
Other current liabilities
310 
387 
Total current liabilities
981 
1,504 
Long-term debt, less amounts due currently
4,541 
4,577 
Commodity and other derivative contractual liabilities
5 
2 
Tax Receivable Agreement obligation, Noncurrent
601 
596 
Asset retirement obligation
1,673 
1,671 
Other noncurrent liabilities and deferred credits
234 
220 
Total liabilities
8,035 
8,570 
Commitments and Contingencies
   
   
Total equity:
 
 
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: March 31, 2017 — 427,587,401; December 31, 2016 — 427,580,232)
4 
4 
Additional paid-in-capital
7,746 
7,742 
Retained deficit
(1,076)
(1,155)
Accumulated other comprehensive income
6 
6 
Total equity
6,680 
6,597 
Total liabilities and equity
$ 14,715 
$ 15,167 
Condensed Consolidated Balance Sheets Condensed Consolidated Balance Sheets (Parenthetical) (USD $)
Mar. 31, 2017
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
427,587,401 
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 reorganized 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 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 May 2016, the FASB issued Accounting Standards Update 2016-10, Revenue from Contracts with Customers (Topic 606), which was further amended through various updates issued by the FASB thereafter. 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 by the entity. In 2016, we continued to assess the new standard, including 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 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. The ASU is effective for public companies for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017 and the adoption should be applied prospectively. We early adopted this standard in 2017. We do not currently anticipate ASU 2017-04 to 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. Vistra Energy has an obligation to reimburse EFH Corp. 50% of such alternative minimum tax, approximately $7 million, pursuant to the Tax Matters Agreement. 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. In addition to the Plan of Reorganization, the separation was effectuated, in part, pursuant to the terms of a separation agreement, a transition services agreement and a tax matters agreement.

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 liabilities subject to compromise (LSTC). Distributions for the settled claims related to the funded debt of the TCEH Debtors commenced subsequent to the Effective Date. With respect to remaining claims related to the TCEH Debtors, as of March 31, 2017, the TCEH Debtors have approximately $54 million in escrow to allocate among and resolve the remaining claims, which consist primarily of remaining unsecured debt and legal claims, including asbestos claims. The Bankruptcy code allows up to 180 days from the Effective Date to resolve these 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 restricted cash, respectively.

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 months ended March 31, 2016 as reported in the condensed statements of consolidated income (loss):
 
Predecessor
 
Three Months
Ended
March 31, 2016
Expenses related to legal advisory and representation services
$
13

Expenses related to other professional consulting and advisory services
8

Contract claims adjustments
1

Total reorganization items
$
22

Lamar and Forney Acquisition (Notes)
Business Combination Disclosure [Text Block]

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.

Unaudited Pro Forma Financial Information

The following unaudited pro forma financial information for the three months ended March 31, 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
 
Three Months
Ended
March 31, 2016
Revenues
$
1,192

Net loss
$
(359
)


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 March 31, 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 2). Of the goodwill recorded at Emergence, $1.686 billion is considered purchased goodwill and 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 2), are comprised of the following:
 
 
March 31, 2017
 
December 31, 2016
Identifiable Intangible Asset
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
Retail customer relationship
 
$
1,648

 
$
257

 
$
1,391

 
$
1,648

 
$
152

 
$
1,496

Software and other technology-related assets
 
155

 
17

 
138

 
147

 
9

 
138

Electricity supply contract
 
190

 
4

 
186

 
190

 
2

 
188

Retail and wholesale contracts
 
164

 
66

 
98

 
164

 
38

 
126

Other identifiable intangible assets (a)
 
31

 
4

 
27

 
30

 
2

 
28

Total identifiable intangible assets subject to amortization
 
$
2,188

 
$
348

 
1,840

 
$
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
 
 
 
 
 
$
3,069

 
 
 
 
 
$
3,205


____________
(a)
Includes environmental allowances and credits and mining development costs.

Amortization expense related to finite-lived identifiable intangible assets (including the classification in the condensed statements of consolidated income (loss)) consisted of:
 
 
 
 
Successor
 
 
Predecessor
Identifiable Intangible Asset
 
Condensed Statements of Consolidated Income (Loss) Line
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Retail customer relationship
 
Depreciation and amortization
 
$
105

 
 
$
3

Software and other technology-related assets
 
Depreciation and amortization
 
8

 
 
15

Electricity supply contract
 
Operating revenues
 
2

 
 
—

Retail and wholesale contracts
 
Operating revenues/fuel, purchased power costs and delivery fees
 
28

 
 
—

Other identifiable intangible assets
 
Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization
 
2

 
 
3

Total amortization expense (a)
 
$
145

 
 
$
21


____________
(a)
Amounts recorded in depreciation and amortization totaled $115 million and $20 million for the three months ended March 31, 2017 and 2016.

Estimated Amortization of Identifiable Intangible Assets

As of March 31, 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
 
$
526

2018
 
$
369

2019
 
$
267

2020
 
$
195

2021
 
$
138

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. will file a US federal income tax return that will include 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
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Income (loss) before income taxes
$
119

 
 
$
(337
)
Income tax expense
$
(41
)
 
 
$
(6
)
Effective tax rate
34.5
%
 
 
(1.8
)%


For the three months ended March 31, 2017, the effective tax rate of 34.5% related to our income tax expense was lower than the US Federal statutory rate of 35% due primarily to nondeductible TRA accretion and the Texas margin tax, net of federal benefit, offset by the difference in the forecasted effective tax rate and the statutory tax rate applied to mark-to-market unrealized gains.

For the three months ended March 31, 2016, the effective tax rate of (1.8)% related to our income tax expense was lower than the US Federal statutory rate of 35% due primarily to a forecasted valuation allowance 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 has yet to file a federal tax return. We currently have no liabilities for uncertain tax positions.

Predecessor — In March 2016, EFH Corp. signed a Revenue Agent Report (RAR) with the IRS for the 2014 tax year. No material financial statement impacts resulted from the signing of the 2014 RAR.
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 any 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).

The fair value of the obligation at the Emergence Date 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 cash flows 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 months ended March 31, 2017, the Impacts of Tax Receivable Agreement on the condensed statement of consolidated income (loss) was $21 million, which represents accretion expense for the period. The balance at March 31, 2017 and December 31, 2016 totaled $617 million and $596 million, respectively. The balance at March 31, 2017 included $16 million recorded to other current liabilities in the condensed consolidated balance sheet.
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 March 31, 2017
 
Net Income
 
Shares
 
Per Share Amount
Net income available for common stock — basic
$
78

 
427,583,339

 
$
0.18

Dilutive securities:
 
 
 
 
 
Stock-based incentive compensation plan
—

 
217,011

 
—

Net income available for common stock — diluted
$
78

 
427,800,350

 
$
0.18



Stock-based incentive compensation plan awards totaling 602,403 shares 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.
 
March 31,
2017
 
December 31,
2016
Vistra Operations Credit Facilities (a)
$
4,482

 
$
4,515

Mandatorily redeemable preferred stock (b)
70

 
70

8.82% Building Financing due semiannually through February 11, 2022 (c)
32

 
36

Capital lease obligations
2

 
2

Total long-term debt including amounts due currently
4,586

 
4,623

Less amounts due currently
(45
)
 
(46
)
Total long-term debt less amounts due currently
$
4,541

 
$
4,577

____________
(a)
At March 31, 2017, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of $4 million, debt discounts of $2 million and debt issuance costs of $11 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. As discussed below, in February 2017 certain pricing terms for the Vistra Operations Credit Facilities were amended, resulting in the recognition of a debt extinguishment gain totaling $21 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's 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 March 31, 2017 are presented below.
 
 
 
 
March 31, 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

 
2,842

 
—

Incremental Term Loan B Facility (c)(d)
 
December 14, 2023
 
1,000

 
998

 
—

Term Loan C Facility (e)
 
August 4, 2023
 
650

 
650

 
210

Total Vistra Operations Credit Facilities
 
 
 
$
5,360

 
$
4,490

 
$
1,070

___________
(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 to fund a special cash dividend paid in December 2016.
(e)
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 March 31, 2017, the restricted cash supported $440 million in letters of credit outstanding (see Note 16), leaving $210 million in available letter of credit capacity.

In February 2017, certain pricing terms for the Vistra Operations Credit Facility were amended. 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 March 31, 2017. Amounts borrowed under the Initial 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%, and the rate outstanding on outstanding borrowings was 3.73% at March 31, 2017. Amounts borrowed under the Incremental Term Loan B Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 3.25%, and the interest rate on outstanding borrowings was 4.19% at March 31, 2017. 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 Energy's 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 Operation Credit Facilities provide for affirmative and negative covenants applicable to Vistra Energy, including affirmative covenants requiring us to provide financial and other information to the agents under the Vistra Operations Credit Facilities and to not change our lines of business, and negative covenants restricting Vistra Energy's 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 Operation Credit Facilities. Vistra Energy's 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 Energy. 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 exceed 4.25 to 1.00. 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 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 4.67% and 5.39%. 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 March 31, 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 March 31, 2017, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling $440 million as follows:

•
$297 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;
•
$63 million to support executory contracts and insurance agreements;
•
$55 million to support our REP financial requirements with the PUCT, and
•
$25 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 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. 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 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 by May 15, 2017 on whether the cases should be remanded to the EPA rather than held in abeyance. 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.

In August 2015, the EPA proposed model rules and federal plan requirements for states to consider as they develop state plans to comply with the rules for GHG emissions. A federal plan would then be finalized for a state if a state fails to submit a state plan by the deadlines established in the Clean Power Plan for existing plants or if the EPA disapproves a submitted state plan. Luminant filed comments on the federal plan proposal and model rules in January 2016. The Order directed the EPA to review this proposed rule for consistency with the policies in the Order and, if appropriate, to revise or withdraw the proposed rule. In April 2017, the EPA published the withdrawal of the proposed rule and plan requirements. While we cannot predict the timing or outcome of this rulemaking and related legal proceedings, or estimate a range of reasonably possible costs, 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 SIP submittal and imposed a 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 State Implementation Plan (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 Federal Implementation Plan (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. Because the EPA has not finalized its proposal to remove Texas from the annual CSAPR programs, these programs will continue to apply to Texas and Texas sources. At this time, the EPA has not populated the allowance accounts for Texas sources with 2017 annual CSAPR program allowances. 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. 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 released a final rule in January 2016 approving in part and disapproving in part Texas' SIP for Regional Haze and issuing a FIP for Regional Haze. In the rule, the EPA asserts that the Texas SIP does not show reasonable progress in improving visibility for two areas in Texas and that its long-term strategy fails to make emission reductions needed to achieve reasonable progress in improving visibility in the Wichita Mountains of Oklahoma. The EPA's proposed 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. Luminant is continuing to evaluate the requirements and potential financial and operational impacts of the rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the FIP (if those limits are possible to attain), along with the existence of low wholesale electricity prices in ERCOT, would likely challenge the long-term economic viability of those units. Under the terms of the rule, the scrubber upgrades will be required by February 2019, and the new scrubbers will be required by February 2021.

In March 2016, Luminant and a number of other parties, including the State of Texas, filed petitions for review in the 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 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. 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 has until September 2017 to finalize, a FIP for BART for Texas electricity generation sources if the EPA determines that BART requirements have not been met. The EPA issued its proposed BART FIP for Texas in December 2016. 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 emission limitations are based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3 and Monticello Unit 3. Luminant is continuing to evaluate the requirements and potential financial and operational impacts of the proposed rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the FIP (if those limits are possible to attain), along with the existence of low wholesale power prices in ERCOT, would likely challenge the long-term economic viability of those units. Under the terms of the rule, the scrubber upgrades will be 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. While we cannot predict the outcome of the rulemaking and potential 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.

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 proposed to remove Texas from the annual CSAPR trading programs. If Texas were in the CSAPR annual trading programs, the EPA would have no basis for its BART FIP because it has made a determination for Texas and all other states that participate in the CSAPR annual trading programs that such participation satisfies their BART obligations. We do not believe that EPA's proposal to remove Texas from the CSAPR annual trading programs satisfies the D.C. Circuit Court's mandate to the EPA to develop non-over-controlling budgets for Texas and we submitted comments on the EPA's proposed rule to remove Texas from the CSAPR annual trading programs. While we cannot predict the outcome of these matters, or estimate a range of reasonably possible costs, the result may have a material impact on our results of operations, liquidity or financial condition.

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 have filed an opposition to that motion. In addition, Luminant has filed a request with the EPA to reconsider the rule and immediately stay its effective date. 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 three months ended March 31, 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 March 31, 2017, Vistra Operations can distribute approximately $1.0 billion to Vistra Energy Corp. (Parent) under the Credit Facilities Agreement without the consent of any party. 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 three months ended March 31, 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
—

 
—

 
78

 
—

 
78

Effects of stock-based incentive compensation plans
—

 
4

 
—

 
—

 
4

Other
—

 
—

 
1

 
—

 
1

Balance at March 31, 2017
$
4

 
$
7,746

 
$
(1,076
)
 
$
6

 
$
6,680

________________
(a)
Authorized shares totaled 1,800,000,000 at March 31, 2017. Outstanding shares totaled 427,587,401 and 427,580,232 at March 31, 2017 and December 31, 2016, respectively.

Predecessor Membership Interests

The following table presents the changes to membership interests for the three months ended March 31, 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
(343
)
 
—

 
(343
)
Balance at March 31, 2016
$
(23,194
)
 
$
(33
)
 
$
(23,227
)
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:
March 31, 2017
 
Level 1
 
Level 2
 
Level 3 (a)
 
Reclassification (b)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
45

 
$
123

 
$
128

 
$
3

 
$
299

Interest rate swaps
—

 
9

 
—

 
13

 
22

Nuclear decommissioning trust –
equity securities (c)
451

 
—

 
—

 
—

 
451

Nuclear decommissioning trust –
debt securities (c)
—

 
348

 
—

 
—

 
348

Sub-total
$
496

 
$
480

 
$
128

 
$
16

 
1,120

Assets measured at net asset value (d):
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trust –
equity securities (c)
 
 
 
 
 
 
 
 
262

Total assets
 
 
 
 
 
 
 
 
$
1,382

Liabilities:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
66

 
$
15

 
$
21

 
$
3

 
$
105

Interest rate swaps
—

 
11

 
—

 
13

 
24

Total liabilities
$
66

 
$
26

 
$
21

 
$
16

 
$
129



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 hedging purposes as well as physical contracts that have not been designated 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 March 31, 2017 and December 31, 2016:
March 31, 2017
 
 
Fair Value
 
 
 
 
 
 
Contract Type (a)
 
Assets
 
Liabilities
 
Total
 
Valuation Technique
 
Significant Unobservable Input
 
Range (b)
Electricity purchases and sales
 
$
57

 
$
(1
)
 
$
56

 
Valuation Model
 
Hourly price curve shape (c)
 
$0 to $35/ MWh
 
 
 
 
 
 
 
 
 
 
Illiquid delivery periods for ERCOT hub power prices and heat rates (d)
 
$25 to $60/ MWh
Electricity congestion revenue rights
 
41

 
(5
)
 
36

 
Market Approach (e)
 
Illiquid price differences between settlement points (f)
 
$0 to $10/ MWh
Other (g)
 
30

 
(15
)
 
15

 
 
 
 
 
 
Total
 
$
128

 
$
(21
)
 
$
107

 
 
 
 
 
 

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 (e)
 
Illiquid price differences between settlement points (f)
 
$0 to $10/ MWh
Other (g)
 
24

 
(9
)
 
15

 
 
 
 
 
 
Total
 
$
98

 
$
(15
)
 
$
83

 
 
 
 
 
 
____________
(a)
Electricity purchase and sales contracts include power and heat rate hedging 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.
(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)
While we use the market approach, there is insufficient market data to consider the valuation liquid.
(f)
Based on the historical price differences between settlement points within ERCOT hubs and load zones.
(g)
Other includes contracts for ancillary services, natural gas, electricity options, coal and coal options. Electricity option contracts consist of physical electricity options and spread options.

There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the three months ended March 31, 2017 and 2016. See the table below for discussion of transfers between Level 2 and Level 3 for the three months ended March 31, 2017 and 2016.

The following table presents the changes in fair value of the Level 3 assets and liabilities for the three months ended March 31, 2017 and 2016.
 
Successor
 
 
Predecessor
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Net asset balance at beginning of period
$
83

 
 
$
37

Total unrealized valuation gains (losses)
40

 
 
(5
)
Purchases, issuances and settlements (a):
 
 
 
 
Purchases
10

 
 
14

Issuances
(12
)
 
 
(12
)
Settlements
(19
)
 
 
(10
)
Transfers into Level 3 (b)
3

 
 
—

Transfers out of Level 3 (b)
2

 
 
1

Net change (c)
24

 
 
(12
)
Net asset balance at end of period
$
107

 
 
$
25

Unrealized valuation gains (losses) relating to instruments held at end of period
$
36

 
 
$
(4
)
____________
(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)
Substantially all changes in value of commodity contracts 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 March 31, 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.
 
March 31, 2017
 
Derivative Assets
 
Derivative Liabilities
 
 
 
Commodity Contracts
 
Interest Rate Swaps
 
Commodity Contracts
 
Interest Rate Swaps
 
Total
Current assets
$
231

 
$
—

 
$
—

 
$
—

 
$
231

Noncurrent assets
66

 
19

 
2

 
3

 
90

Current liabilities
—

 
(10
)
 
(100
)
 
(14
)
 
(124
)
Noncurrent liabilities
(1
)
 
—

 
(4
)
 
—

 
(5
)
Net assets (liabilities)
$
296

 
$
9

 
$
(102
)
 
$
(11
)
 
$
192


 
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 March 31, 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 derivatives on net income (gains (losses)), including realized and unrealized effects:
 
Successor
 
 
Predecessor
Derivative (condensed statements of consolidated income (loss) presentation)
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Commodity contracts (Operating revenues) (a)
$
175

 
 
$
—

Commodity contracts (Fuel, purchased power costs and delivery fees) (a)
(5
)
 
 
—

Commodity contracts (Net gain from commodity hedging and trading activities) (a)
—

 
 
56

Interest rate swaps (Interest expense and related charges) (b)
3

 
 
—

Net gain (loss)
$
173

 
 
$
56

____________
(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 months ended March 31, 2016. There were no amounts recognized in OCI for the three months ended March 31, 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 as presented in our condensed consolidated balance sheets to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
 
 
March 31, 2017
 
December 31, 2016
 
 
Amounts Presented in Balance Sheet
 
Offsetting Instruments (a)
 
Cash Collateral (Received) Pledged (b)
 
Net Amounts
 
Amounts Presented in Balance Sheet
 
Offsetting Instruments (a)
 
Cash Collateral (Received) Pledged (b)
 
Net Amounts
Derivative assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
296

 
$
(78
)
 
$
(10
)
 
$
208

 
$
396

 
$
(193
)
 
$
(20
)
 
$
183

Interest rate swaps
 
9

 
—

 
—

 
9

 
5

 
—

 
—

 
5

Total derivative assets
 
305

 
(78
)
 
(10
)
 
217

 
401

 
(193
)
 
(20
)
 
188

Derivative liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
(102
)
 
78

 
21

 
(3
)
 
(332
)
 
193

 
136

 
(3
)
Interest rate swaps
 
(11
)
 
—

 
—

 
(11
)
 
(16
)
 
—

 
—

 
(16
)
Total derivative liabilities
 
(113
)
 
78

 
21

 
(14
)
 
(348
)
 
193

 
136

 
(19
)
Net amounts
 
$
192

 
$
—

 
$
11

 
$
203

 
$
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 March 31, 2017 and December 31, 2016:
 
 
March 31, 2017
 
December 31, 2016
 
 
Derivative type
 
Notional Volume
 
Unit of Measure
Natural gas (a)
 
1,322

 
1,282

 
Million MMBtu
Electricity
 
72,320

 
75,322

 
GWh
Congestion Revenue Rights (b)
 
114,761

 
126,573

 
GWh
Coal
 
9

 
12

 
Million US tons
Fuel oil
 
26

 
34

 
Million gallons
Uranium
 
325

 
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:
 
March 31,
2017
 
December 31,
2016
Fair value of derivative contract liabilities (a)
$
(32
)
 
$
(31
)
Offsetting fair value under netting arrangements (b)
18

 
13

Cash collateral and letters of credit
1

 
1

Liquidity exposure
$
(13
)
 
$
(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 March 31, 2017, total credit risk exposure to all counterparties related to derivative contracts totaled $400 million (including associated accounts receivable). The net exposure to those counterparties totaled $299 million at March 31, 2017 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $89 million. At March 31, 2017, the credit risk exposure to the banking and financial sector represented 44% of the total credit risk exposure and 35% 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 the three months ended March 31, 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 $220 million for the three months ended March 31, 2016.

•
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 $60 million for the three months ended March 31, 2016.

•
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 $4 million for the three months ended March 31, 2016. 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 three months ended March 31, 2016, our Predecessor made no income tax payments 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
March 31, 2017
Operating revenues (a)
 
Wholesale Generation
$
971

Retail Electricity
865

Corporate and Other
(1
)
Eliminations
(478
)
Consolidated operating revenues
$
1,357

Depreciation and amortization
 
Wholesale Generation
$
53

Retail Electricity
106

Corporate and Other
11

Consolidated depreciation and amortization
$
170

Operating income (loss)
 
Wholesale Generation
$
285

Retail Electricity
(118
)
Corporate and Other
(12
)
Consolidated operating income (loss)
$
155

Net income (loss)
 
Wholesale Generation
$
290

Retail Electricity
(113
)
Corporate and Other
(99
)
Consolidated net income
$
78


____________
(a)
Includes third-party unrealized net gains from mark-to-market valuations of commodity positions of $126 million recorded to the Wholesale Generation segment and $8 million recorded to the Retail Electricity segment. In addition, an unrealized net gain with affiliate of $170 million was recorded to operating revenues for the Wholesale Generation segment and a corresponding unrealized net loss with affiliate of $170 million was recorded to fuel, purchased power costs and delivery fees for the Retail Electricity segment, with no impact to consolidated results.
 
March 31, 2017
 
December 31, 2016
Total assets
 
 
 
Wholesale Generation
$
7,023

 
$
6,952

Retail Electricity
5,661

 
5,753

Corporate and Other and Eliminations
2,031

 
2,462

Consolidated total assets
$
14,715

 
$
15,167

Supplementary Financial Information
Supplementary Financial Information
SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions
 
Successor
 
 
Predecessor
 
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
 
Other income:
 
 
 
 
 
Office space sublease rental income (a)
$
3

 
 
$
—

 
Mineral rights royalty income (b)
1

 
 
1

 
Sale of land (b)
2

 
 
—

 
All other
2

 
 
—

 
Total other income
$
8

 
 
$
1

 
Other deductions:
 
 
 
 
 
Write-off of generation equipment
$
—

 
 
$
20

 
All other
—

 
 
1

 
Total other deductions
$
—

 
 
$
21

 
____________
(a)
Reported in Corporate and Other non-segment (Successor period only).
(b)
Reported in Wholesale Generation segment (Successor period only).

Restricted Cash
 
March 31, 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
89

 
—

 
90

 
—

Other
5

 
—

 
5

 
—

Total restricted cash
$
94

 
$
650

 
$
95

 
$
650



Trade Accounts Receivable
 
March 31,
2017
 
December 31,
2016
Wholesale and retail trade accounts receivable
$
490

 
$
622

Allowance for uncollectible accounts
(8
)
 
(10
)
Trade accounts receivable — net
$
482

 
$
612



Gross trade accounts receivable at March 31, 2017 and December 31, 2016 included unbilled revenues of $184 million and $225 million, respectively.

Allowance for Uncollectible Accounts Receivable
 
Successor
 
 
Predecessor
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Allowance for uncollectible accounts receivable at beginning of period
$
10

 
 
$
9

Increase for bad debt expense
7

 
 
5

Decrease for account write-offs
(9
)
 
 
(7
)
Allowance for uncollectible accounts receivable at end of period
$
8

 
 
$
7



Inventories by Major Category
 
March 31,
2017
 
December 31,
2016
Materials and supplies
$
169

 
$
173

Fuel stock
126

 
88

Natural gas in storage
20

 
24

Total inventories
$
315

 
$
285



Other Investments
 
March 31,
2017
 
December 31,
2016
Nuclear plant decommissioning trust
$
1,061

 
$
1,012

Land
49

 
49

Miscellaneous other
3

 
3

Total other investments
$
1,113

 
$
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 payable reported in noncurrent liabilities) 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:
 
March 31, 2017
 
Cost (a)
 
Unrealized gain
 
Unrealized loss
 
Fair market
value
Debt securities (b)
$
340

 
$
10

 
$
(2
)
 
$
348

Equity securities (c)
313

 
404

 
(4
)
 
713

Total
$
653

 
$
414

 
$
(6
)
 
$
1,061


 
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 3.52% and 3.56% at March 31, 2017 and December 31, 2016, respectively, and an average maturity of 9 years at both March 31, 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 March 31, 2017 mature as follows: $106 million in one to five years, $94 million in five to ten years and $148 million after ten years.

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.
 
Successor
 
 
Predecessor
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Realized gains
$
1

 
 
$
1

Realized losses
$
(2
)
 
 
$
(1
)
Proceeds from sales of securities
$
79

 
 
$
67

Investments in securities
$
(84
)
 
 
$
(71
)


Property, Plant and Equipment

At March 31, 2017 and December 31, 2016, property, plant and equipment of $4.415 billion and $4.443 billion, respectively, is stated net of accumulated depreciation and amortization of $167 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 March 31, 2017, the current value of our ARO related to our nuclear generation plant decommissioning totaled $1.208 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 $147 million in other noncurrent assets.

The following table summarizes the changes to these obligations, reported in other current liabilities and other noncurrent liabilities and deferred credits in our condensed consolidated balance sheets, for the three months ended March 31, 2017:
 
Nuclear Plant Decommissioning
 
Mining Land Reclamation
 
Other
 
Total
Liability at December 31, 2016
$
1,200

 
$
375

 
$
151

 
$
1,726

Additions:
 
 
 
 
 
 
 
Accretion
8

 
5

 
1

 
14

Reductions:
 
 
 
 
 
 
 
Payments
—

 
(5
)
 
—

 
(5
)
Liability at March 31, 2017
1,208

 
375

 
152

 
1,735

Less amounts due currently
—

 
(61
)
 
(1
)
 
(62
)
Noncurrent liability at March 31, 2017
$
1,208

 
$
314

 
$
151

 
$
1,673



Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:
 
March 31,
2017
 
December 31,
2016
Unfavorable purchase and sales contracts
$
43

 
$
46

Other, including retirement and other employee benefits
191

 
174

Total other noncurrent liabilities and deferred credits
$
234

 
$
220



Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $3 million and $6 million for the three months ended March 31, 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
 
$
9

2018
 
$
11

2019
 
$
11

2020
 
$
9

2021
 
$
1



Fair Value of Debt
 
 
March 31, 2017
 
December 31, 2016
Debt:
 
Carrying Amount
 
Fair
Value
 
Carrying Amount
 
Fair
Value
Long-term debt under the Vistra Operations Credit Facilities (Note 9)
 
$
4,482

 
$
4,489

 
$
4,515

 
$
4,552

Other long-term debt, excluding capital lease obligations (Note 9)
 
32

 
29

 
36

 
32

Mandatorily redeemable preferred stock (Note 9)
 
70

 
70

 
70

 
70



We determine fair value in accordance with accounting standards as discussed in Note 12, and at March 31, 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
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Cash payments related to:
 
 
 
 
Interest paid (a)
$
89

 
 
$
335

Capitalized interest
(3
)
 
 
(3
)
Interest paid (net of capitalized interest) (a)
$
86

 
 
$
332

Reorganization items (b)
$
—

 
 
$
41

Noncash investing and financing activities:
 
 
 
 
Construction expenditures (c)
$
1

 
 
$
82

____________
(a)
Predecessor period includes amounts paid for adequate protection.
(b)
Represents cash payments 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.
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 reorganized 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 months ended March 31, 2016 as reported in the condensed statements of consolidated income (loss):
 
Predecessor
 
Three Months
Ended
March 31, 2016
Expenses related to legal advisory and representation services
$
13

Expenses related to other professional consulting and advisory services
8

Contract claims adjustments
1

Total reorganization items
$
22

Lamar and Forney Acquisition (Tables)
Business Acquisition, Pro Forma Information [Table Text Block]
The following unaudited pro forma financial information for the three months ended March 31, 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
 
Three Months
Ended
March 31, 2016
Revenues
$
1,192

Net loss
$
(359
)
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 2), are comprised of the following:
 
 
March 31, 2017
 
December 31, 2016
Identifiable Intangible Asset
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
Retail customer relationship
 
$
1,648

 
$
257

 
$
1,391

 
$
1,648

 
$
152

 
$
1,496

Software and other technology-related assets
 
155

 
17

 
138

 
147

 
9

 
138

Electricity supply contract
 
190

 
4

 
186

 
190

 
2

 
188

Retail and wholesale contracts
 
164

 
66

 
98

 
164

 
38

 
126

Other identifiable intangible assets (a)
 
31

 
4

 
27

 
30

 
2

 
28

Total identifiable intangible assets subject to amortization
 
$
2,188

 
$
348

 
1,840

 
$
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
 
 
 
 
 
$
3,069

 
 
 
 
 
$
3,205


____________
(a)
Includes environmental allowances and credits and mining development costs.
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
Identifiable Intangible Asset
 
Condensed Statements of Consolidated Income (Loss) Line
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Retail customer relationship
 
Depreciation and amortization
 
$
105

 
 
$
3

Software and other technology-related assets
 
Depreciation and amortization
 
8

 
 
15

Electricity supply contract
 
Operating revenues
 
2

 
 
—

Retail and wholesale contracts
 
Operating revenues/fuel, purchased power costs and delivery fees
 
28

 
 
—

Other identifiable intangible assets
 
Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization
 
2

 
 
3

Total amortization expense (a)
 
$
145

 
 
$
21


____________
(a)
Amounts recorded in depreciation and amortization totaled $115 million and $20 million for the three months ended March 31, 2017 and 2016.
Schedule of estimated amortization expense of identifiable intangible assets 
As of March 31, 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
 
$
526

2018
 
$
369

2019
 
$
267

2020
 
$
195

2021
 
$
138

As of March 31, 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
 
$
526

2018
 
$
369

2019
 
$
267

2020
 
$
195

2021
 
$
138

Income Taxes (Tables)
Calculation of Effective Income Tax Rate
The calculation of our effective tax rate is as follows:
 
Successor
 
 
Predecessor
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Income (loss) before income taxes
$
119

 
 
$
(337
)
Income tax expense
$
(41
)
 
 
$
(6
)
Effective tax rate
34.5
%
 
 
(1.8
)%
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 March 31, 2017
 
Net Income
 
Shares
 
Per Share Amount
Net income available for common stock — basic
$
78

 
427,583,339

 
$
0.18

Dilutive securities:
 
 
 
 
 
Stock-based incentive compensation plan
—

 
217,011

 
—

Net income available for common stock — diluted
$
78

 
427,800,350

 
$
0.18

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.
 
March 31,
2017
 
December 31,
2016
Vistra Operations Credit Facilities (a)
$
4,482

 
$
4,515

Mandatorily redeemable preferred stock (b)
70

 
70

8.82% Building Financing due semiannually through February 11, 2022 (c)
32

 
36

Capital lease obligations
2

 
2

Total long-term debt including amounts due currently
4,586

 
4,623

Less amounts due currently
(45
)
 
(46
)
Total long-term debt less amounts due currently
$
4,541

 
$
4,577

____________
(a)
At March 31, 2017, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of $4 million, debt discounts of $2 million and debt issuance costs of $11 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. As discussed below, in February 2017 certain pricing terms for the Vistra Operations Credit Facilities were amended, resulting in the recognition of a debt extinguishment gain totaling $21 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's 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 March 31, 2017 are presented below.
 
 
 
 
March 31, 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

 
2,842

 
—

Incremental Term Loan B Facility (c)(d)
 
December 14, 2023
 
1,000

 
998

 
—

Term Loan C Facility (e)
 
August 4, 2023
 
650

 
650

 
210

Total Vistra Operations Credit Facilities
 
 
 
$
5,360

 
$
4,490

 
$
1,070

___________
(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 to fund a special cash dividend paid in December 2016.
(e)
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 March 31, 2017, the restricted cash supported $440 million in letters of credit outstanding (see Note 16), leaving $210 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 three months ended March 31, 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
—

 
—

 
78

 
—

 
78

Effects of stock-based incentive compensation plans
—

 
4

 
—

 
—

 
4

Other
—

 
—

 
1

 
—

 
1

Balance at March 31, 2017
$
4

 
$
7,746

 
$
(1,076
)
 
$
6

 
$
6,680

________________
(a)
Authorized shares totaled 1,800,000,000 at March 31, 2017. Outstanding shares totaled 427,587,401 and 427,580,232 at March 31, 2017 and December 31, 2016, respectively.

Predecessor Membership Interests

The following table presents the changes to membership interests for the three months ended March 31, 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
(343
)
 
—

 
(343
)
Balance at March 31, 2016
$
(23,194
)
 
$
(33
)
 
$
(23,227
)
Fair Value Measurements (Tables)
Schedule of assets and liabilities measured at fair value on a recurring basis 
March 31, 2017
 
Level 1
 
Level 2
 
Level 3 (a)
 
Reclassification (b)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
45

 
$
123

 
$
128

 
$
3

 
$
299

Interest rate swaps
—

 
9

 
—

 
13

 
22

Nuclear decommissioning trust –
equity securities (c)
451

 
—

 
—

 
—

 
451

Nuclear decommissioning trust –
debt securities (c)
—

 
348

 
—

 
—

 
348

Sub-total
$
496

 
$
480

 
$
128

 
$
16

 
1,120

Assets measured at net asset value (d):
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trust –
equity securities (c)
 
 
 
 
 
 
 
 
262

Total assets
 
 
 
 
 
 
 
 
$
1,382

Liabilities:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
66

 
$
15

 
$
21

 
$
3

 
$
105

Interest rate swaps
—

 
11

 
—

 
13

 
24

Total liabilities
$
66

 
$
26

 
$
21

 
$
16

 
$
129



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 
March 31, 2017 and December 31, 2016:
March 31, 2017
 
 
Fair Value
 
 
 
 
 
 
Contract Type (a)
 
Assets
 
Liabilities
 
Total
 
Valuation Technique
 
Significant Unobservable Input
 
Range (b)
Electricity purchases and sales
 
$
57

 
$
(1
)
 
$
56

 
Valuation Model
 
Hourly price curve shape (c)
 
$0 to $35/ MWh
 
 
 
 
 
 
 
 
 
 
Illiquid delivery periods for ERCOT hub power prices and heat rates (d)
 
$25 to $60/ MWh
Electricity congestion revenue rights
 
41

 
(5
)
 
36

 
Market Approach (e)
 
Illiquid price differences between settlement points (f)
 
$0 to $10/ MWh
Other (g)
 
30

 
(15
)
 
15

 
 
 
 
 
 
Total
 
$
128

 
$
(21
)
 
$
107

 
 
 
 
 
 

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 (e)
 
Illiquid price differences between settlement points (f)
 
$0 to $10/ MWh
Other (g)
 
24

 
(9
)
 
15

 
 
 
 
 
 
Total
 
$
98

 
$
(15
)
 
$
83

 
 
 
 
 
 
____________
(a)
Electricity purchase and sales contracts include power and heat rate hedging 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.
(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)
While we use the market approach, there is insufficient market data to consider the valuation liquid.
(f)
Based on the historical price differences between settlement points within ERCOT hubs and load zones.
(g)
Other includes contracts for ancillary services, natural gas, electricity options, coal and coal options. Electricity option contracts consist of physical electricity options and spread options.

There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the three months ended March 31, 2017 and 2016. See the table below for discussion of transfers between Level 2 and Level 3 for the three months ended March 31, 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 months ended March 31, 2017 and 2016.
 
Successor
 
 
Predecessor
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Net asset balance at beginning of period
$
83

 
 
$
37

Total unrealized valuation gains (losses)
40

 
 
(5
)
Purchases, issuances and settlements (a):
 
 
 
 
Purchases
10

 
 
14

Issuances
(12
)
 
 
(12
)
Settlements
(19
)
 
 
(10
)
Transfers into Level 3 (b)
3

 
 
—

Transfers out of Level 3 (b)
2

 
 
1

Net change (c)
24

 
 
(12
)
Net asset balance at end of period
$
107

 
 
$
25

Unrealized valuation gains (losses) relating to instruments held at end of period
$
36

 
 
$
(4
)
____________
(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)
Substantially all changes in value of commodity contracts 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 March 31, 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.
 
March 31, 2017
 
Derivative Assets
 
Derivative Liabilities
 
 
 
Commodity Contracts
 
Interest Rate Swaps
 
Commodity Contracts
 
Interest Rate Swaps
 
Total
Current assets
$
231

 
$
—

 
$
—

 
$
—

 
$
231

Noncurrent assets
66

 
19

 
2

 
3

 
90

Current liabilities
—

 
(10
)
 
(100
)
 
(14
)
 
(124
)
Noncurrent liabilities
(1
)
 
—

 
(4
)
 
—

 
(5
)
Net assets (liabilities)
$
296

 
$
9

 
$
(102
)
 
$
(11
)
 
$
192


 
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 derivatives on net income (gains (losses)), including realized and unrealized effects:
 
Successor
 
 
Predecessor
Derivative (condensed statements of consolidated income (loss) presentation)
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Commodity contracts (Operating revenues) (a)
$
175

 
 
$
—

Commodity contracts (Fuel, purchased power costs and delivery fees) (a)
(5
)
 
 
—

Commodity contracts (Net gain from commodity hedging and trading activities) (a)
—

 
 
56

Interest rate swaps (Interest expense and related charges) (b)
3

 
 
—

Net gain (loss)
$
173

 
 
$
56

____________
(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 as presented in our condensed consolidated balance sheets to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
 
 
March 31, 2017
 
December 31, 2016
 
 
Amounts Presented in Balance Sheet
 
Offsetting Instruments (a)
 
Cash Collateral (Received) Pledged (b)
 
Net Amounts
 
Amounts Presented in Balance Sheet
 
Offsetting Instruments (a)
 
Cash Collateral (Received) Pledged (b)
 
Net Amounts
Derivative assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
296

 
$
(78
)
 
$
(10
)
 
$
208

 
$
396

 
$
(193
)
 
$
(20
)
 
$
183

Interest rate swaps
 
9

 
—

 
—

 
9

 
5

 
—

 
—

 
5

Total derivative assets
 
305

 
(78
)
 
(10
)
 
217

 
401

 
(193
)
 
(20
)
 
188

Derivative liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
(102
)
 
78

 
21

 
(3
)
 
(332
)
 
193

 
136

 
(3
)
Interest rate swaps
 
(11
)
 
—

 
—

 
(11
)
 
(16
)
 
—

 
—

 
(16
)
Total derivative liabilities
 
(113
)
 
78

 
21

 
(14
)
 
(348
)
 
193

 
136

 
(19
)
Net amounts
 
$
192

 
$
—

 
$
11

 
$
203

 
$
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 March 31, 2017 and December 31, 2016:
 
 
March 31, 2017
 
December 31, 2016
 
 
Derivative type
 
Notional Volume
 
Unit of Measure
Natural gas (a)
 
1,322

 
1,282

 
Million MMBtu
Electricity
 
72,320

 
75,322

 
GWh
Congestion Revenue Rights (b)
 
114,761

 
126,573

 
GWh
Coal
 
9

 
12

 
Million US tons
Fuel oil
 
26

 
34

 
Million gallons
Uranium
 
325

 
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:
 
March 31,
2017
 
December 31,
2016
Fair value of derivative contract liabilities (a)
$
(32
)
 
$
(31
)
Offsetting fair value under netting arrangements (b)
18

 
13

Cash collateral and letters of credit
1

 
1

Liquidity exposure
$
(13
)
 
$
(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
March 31, 2017
Operating revenues (a)
 
Wholesale Generation
$
971

Retail Electricity
865

Corporate and Other
(1
)
Eliminations
(478
)
Consolidated operating revenues
$
1,357

Depreciation and amortization
 
Wholesale Generation
$
53

Retail Electricity
106

Corporate and Other
11

Consolidated depreciation and amortization
$
170

Operating income (loss)
 
Wholesale Generation
$
285

Retail Electricity
(118
)
Corporate and Other
(12
)
Consolidated operating income (loss)
$
155

Net income (loss)
 
Wholesale Generation
$
290

Retail Electricity
(113
)
Corporate and Other
(99
)
Consolidated net income
$
78


____________
(a)
Includes third-party unrealized net gains from mark-to-market valuations of commodity positions of $126 million recorded to the Wholesale Generation segment and $8 million recorded to the Retail Electricity segment. In addition, an unrealized net gain with affiliate of $170 million was recorded to operating revenues for the Wholesale Generation segment and a corresponding unrealized net loss with affiliate of $170 million was recorded to fuel, purchased power costs and delivery fees for the Retail Electricity segment, with no impact to consolidated results.
 
March 31, 2017
 
December 31, 2016
Total assets
 
 
 
Wholesale Generation
$
7,023

 
$
6,952

Retail Electricity
5,661

 
5,753

Corporate and Other and Eliminations
2,031

 
2,462

Consolidated total assets
$
14,715

 
$
15,167

Supplementary Financial Information (Tables)
Schedule of other income and deductions 
Other Income and Deductions
 
Successor
 
 
Predecessor
 
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
 
Other income:
 
 
 
 
 
Office space sublease rental income (a)
$
3

 
 
$
—

 
Mineral rights royalty income (b)
1

 
 
1

 
Sale of land (b)
2

 
 
—

 
All other
2

 
 
—

 
Total other income
$
8

 
 
$
1

 
Other deductions:
 
 
 
 
 
Write-off of generation equipment
$
—

 
 
$
20

 
All other
—

 
 
1

 
Total other deductions
$
—

 
 
$
21

 
____________
(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
 
March 31, 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
89

 
—

 
90

 
—

Other
5

 
—

 
5

 
—

Total restricted cash
$
94

 
$
650

 
$
95

 
$
650



Schedule of accounts, notes, loans and financing receivable 
Trade Accounts Receivable
 
March 31,
2017
 
December 31,
2016
Wholesale and retail trade accounts receivable
$
490

 
$
622

Allowance for uncollectible accounts
(8
)
 
(10
)
Trade accounts receivable — net
$
482

 
$
612



Gross trade accounts receivable at March 31, 2017 and December 31, 2016 included unbilled revenues of $184 million and $225 million, respectively.
Allowance for Uncollectible Accounts Receivable
 
Successor
 
 
Predecessor
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Allowance for uncollectible accounts receivable at beginning of period
$
10

 
 
$
9

Increase for bad debt expense
7

 
 
5

Decrease for account write-offs
(9
)
 
 
(7
)
Allowance for uncollectible accounts receivable at end of period
$
8

 
 
$
7



Schedule of inventories by major category 
Inventories by Major Category
 
March 31,
2017
 
December 31,
2016
Materials and supplies
$
169

 
$
173

Fuel stock
126

 
88

Natural gas in storage
20

 
24

Total inventories
$
315

 
$
285

Summary of other investments 
Other Investments
 
March 31,
2017
 
December 31,
2016
Nuclear plant decommissioning trust
$
1,061

 
$
1,012

Land
49

 
49

Miscellaneous other
3

 
3

Total other investments
$
1,113

 
$
1,064

Summary of investments in the fund 
 
March 31, 2017
 
Cost (a)
 
Unrealized gain
 
Unrealized loss
 
Fair market
value
Debt securities (b)
$
340

 
$
10

 
$
(2
)
 
$
348

Equity securities (c)
313

 
404

 
(4
)
 
713

Total
$
653

 
$
414

 
$
(6
)
 
$
1,061


 
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 3.52% and 3.56% at March 31, 2017 and December 31, 2016, respectively, and an average maturity of 9 years at both March 31, 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
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Realized gains
$
1

 
 
$
1

Realized losses
$
(2
)
 
 
$
(1
)
Proceeds from sales of securities
$
79

 
 
$
67

Investments in securities
$
(84
)
 
 
$
(71
)
Schedule of asset retirement and mining reclamation obligations 
The following table summarizes the changes to these obligations, reported in other current liabilities and other noncurrent liabilities and deferred credits in our condensed consolidated balance sheets, for the three months ended March 31, 2017:
 
Nuclear Plant Decommissioning
 
Mining Land Reclamation
 
Other
 
Total
Liability at December 31, 2016
$
1,200

 
$
375

 
$
151

 
$
1,726

Additions:
 
 
 
 
 
 
 
Accretion
8

 
5

 
1

 
14

Reductions:
 
 
 
 
 
 
 
Payments
—

 
(5
)
 
—

 
(5
)
Liability at March 31, 2017
1,208

 
375

 
152

 
1,735

Less amounts due currently
—

 
(61
)
 
(1
)
 
(62
)
Noncurrent liability at March 31, 2017
$
1,208

 
$
314

 
$
151

 
$
1,673

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:
 
March 31,
2017
 
December 31,
2016
Unfavorable purchase and sales contracts
$
43

 
$
46

Other, including retirement and other employee benefits
191

 
174

Total other noncurrent liabilities and deferred credits
$
234

 
$
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
 
$
9

2018
 
$
11

2019
 
$
11

2020
 
$
9

2021
 
$
1

Schedule of fair value of debt 
Fair Value of Debt
 
 
March 31, 2017
 
December 31, 2016
Debt:
 
Carrying Amount
 
Fair
Value
 
Carrying Amount
 
Fair
Value
Long-term debt under the Vistra Operations Credit Facilities (Note 9)
 
$
4,482

 
$
4,489

 
$
4,515

 
$
4,552

Other long-term debt, excluding capital lease obligations (Note 9)
 
32

 
29

 
36

 
32

Mandatorily redeemable preferred stock (Note 9)
 
70

 
70

 
70

 
70

Schedule of supplemental cash flow information 
Supplemental Cash Flow Information
 
Successor
 
 
Predecessor
 
Three Months
Ended
March 31, 2017
 
 
Three Months
Ended
March 31, 2016
Cash payments related to:
 
 
 
 
Interest paid (a)
$
89

 
 
$
335

Capitalized interest
(3
)
 
 
(3
)
Interest paid (net of capitalized interest) (a)
$
86

 
 
$
332

Reorganization items (b)
$
—

 
 
$
41

Noncash investing and financing activities:
 
 
 
 
Construction expenditures (c)
$
1

 
 
$
82

____________
(a)
Predecessor period includes amounts paid for adequate protection.
(b)
Represents cash payments 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.
Business And Significant Accounting Policies (Details)
3 Months Ended
Mar. 31, 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
Mar. 31, 2017
Oct. 3, 2016
Mar. 31, 2017
Maximum [Member]
Oct. 3, 2016
EFH Corp. [Member]
Internal Revenue Service (IRS) [Member]
Oct. 3, 2016
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, Obligation To Reimburse Counterparty For Alternative Minimum Tax Liability
 
 
 
 
7,000,000 
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 
 
 
 
 
Bankruptcy Claims, Number Of Days From Effective Date Claims May Be Resolved
 
 
180 days 
 
 
Emergence From Chapter 11 Cases (Reorganization Items) (Details) (Predecessor [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Predecessor [Member]
 
Expenses related to legal advisory and representation services
$ 13 
Expenses related to other professional consulting and advisory services
8 
Contract claims adjustments
1 
Reorganization Items
$ 22 
Lamar and Forney Acquisition Narrative (Details) (Predecessor [Member], 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 [Member] |
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 
 
Lamar and Forney Acquisition Pro Forma Financial Information (Details) (Predecessor [Member], La Frontera Holdings, LLC [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Predecessor [Member] |
La Frontera Holdings, LLC [Member]
 
Statement [Line Items]
 
Revenues
$ 1,192 
Net loss
$ (359)
Goodwill And Identifiable Intangible Assets (Goodwill) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 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
Mar. 31, 2017
Dec. 31, 2016
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
$ 2,188 
$ 2,179 
Accumulated Amortization
348 
203 
Total identifiable intangible assets subject to amortization, net
1,840 
1,976 
Total identifiable intangible assets
3,069 
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
257 
152 
Total identifiable intangible assets subject to amortization, net
1,391 
1,496 
Software and other technology-related assets [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
155 
147 
Accumulated Amortization
17 
9 
Total identifiable intangible assets subject to amortization, net
138 
138 
Electricity supply contract [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
190 
190 
Accumulated Amortization
4 
2 
Total identifiable intangible assets subject to amortization, net
186 
188 
Retail and wholesale contracts [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
164 
164 
Accumulated Amortization
66 
38 
Total identifiable intangible assets subject to amortization, net
98 
126 
Other Identifiable Intangible Assets [Member]
 
 
Finite-Lived and Indefinite-Lived Intangible [Line Items]
 
 
Gross Carrying Amount
31 1
30 1
Accumulated Amortization
4 1
2 1
Total identifiable intangible assets subject to amortization, net
$ 27 1
$ 28 1
Goodwill And Identifiable Intangible Assets (Estimated Amortization of Identifiable Intangible Assets) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
 
2017
$ 526 
2018
369 
2019
267 
2020
195 
2021
$ 138 
Income Taxes (Calculation of Effective Tax Rate)(Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Effective tax rate at federal statutory rate
35.00% 
35.00% 
Successor [Member]
 
 
Income (loss) before income taxes
$ 119 
 
Income tax expense
(41)
 
Effective tax rate
34.50% 
 
Predecessor [Member]
 
 
Income (loss) before income taxes
 
(337)
Income tax expense
 
$ (6)
Effective tax rate
 
(1.80%)
Tax Receivable Agreement Obligation (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2017
Successor [Member]
Percent Of Cash Tax Savings Due Tax Receivable Agreement Rights Holders
 
 
85.00% 
Accretion Expense
 
 
$ 21 
Tax Receivable Agreement obligation
617 
596 
 
Tax Receivable Agreement obligation, current
$ 16 
 
 
Earnings Per Share (Details) (Successor [Member], USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Successor [Member]
 
Net Income (Loss) Available to Common Stockholders, Basic
$ 78 
Net Income (Loss) Available to Common Stockholders, Diluted
$ 78 
Weighted average shares of common stock outstanding - basic
427,583,339 
Weighted average shares of common stock outstanding - diluted
427,800,350 
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements
217,011 
Net income per weighted average share of common stock outstanding - basic
$ 0.18 
Net income per weighted average share of common stock outstanding - diluted
$ 0.18 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
602,403 
Long-Term Debt (Long-Term Debt) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2017
Vistra Operations Credit Facility [Member]
Line of Credit [Member]
Dec. 31, 2016
Vistra Operations Credit Facility [Member]
Line of Credit [Member]
Mar. 31, 2017
PrefCo Mandatorily Redeemable Preferred Stock [Member]
Mandatorily Redeemable Preferred Stock [Member]
Dec. 31, 2016
PrefCo Mandatorily Redeemable Preferred Stock [Member]
Mandatorily Redeemable Preferred Stock [Member]
Mar. 31, 2017
Building Financing 8.82% due semiannually through February 11, 2022 [Member]
Construction Loans [Member]
Dec. 31, 2016
Building Financing 8.82% due semiannually through February 11, 2022 [Member]
Construction Loans [Member]
Mar. 31, 2017
Capital Lease Obligations [Member]
Dec. 31, 2016
Capital Lease Obligations [Member]
Mar. 31, 2017
Successor [Member]
Vistra Operations Credit Facility [Member]
Line of Credit [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Long-term debt, including amounts due currently
$ 4,586 
$ 4,623 
$ 4,482 
$ 4,515 
$ 70 
$ 70 
$ 32 
$ 36 
$ 2 
$ 2 
 
Long-term debt due currently
45 
46 
 
 
 
 
 
 
 
 
 
Long-term debt, less amounts due currently
4,541 
4,577 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
 
 
 
 
8.82% 
 
 
 
 
Debt Instrument, Unamortized Premium
 
 
4 
25 
 
 
 
 
 
 
 
Debt Instrument, Unamortized Discount
 
 
2 
2 
 
 
 
 
 
 
 
Unamortized Debt Issuance Expense
 
 
11 
8 
 
 
 
 
 
 
 
Gain (Loss) on Extinguishment of Debt
 
 
 
 
 
 
 
 
 
 
$ 21 
Long-Term Debt (Vistra Operations Credit Facilities) (Details) (Vistra Operations Company LLC [Member], Line of Credit [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Maximum Borrowing Capacity
$ 5,360 
Line Of Credit Facility, Borrowings Outstanding
4,490 
Line of Credit Facility, Remaining Borrowing Capacity
1,070 
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 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
2,842 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 4
Line Of Credit Facility, Borrowings Outstanding
998 2 4
Line of Credit Facility, Remaining Borrowing Capacity
0 2 4
Debt Instrument, Basis Spread on Variable Rate
3.25% 
Line of Credit Facility, Interest Rate at Period End
4.19% 
Senior Secured Term Loan C Facility [Member] [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Maximum Borrowing Capacity
650 5
Line Of Credit Facility, Borrowings Outstanding
650 5
Line Of Credit Facility, Unused Letter Of Credit Capacity
210 5
Line Of Credit Facility, Letters Of Credit Outstanding
440 
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% 
Senior Secured Initial Term Loan B And Term Loan C Facilities [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
3.73% 
Minimum [Member] |
Senior Secured Incremental Term Loan B Facility [Member] [Member]
 
Line of Credit Facility [Line Items]
 
Debt Instrument, Interest Rate, Stated Percentage
0.75% 
Minimum [Member] |
Senior Secured Initial Term Loan B And Term Loan C Facilities [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
Mar. 31, 2017
Dec. 31, 2016
Derivative, Notional Amount
$ 3,000 
$ 3,000 1
Minimum [Member]
 
 
Effective Interest Rate Debt Fixed Based On Derivative Contracts
4.67% 
 
Maximum [Member]
 
 
Effective Interest Rate Debt Fixed Based On Derivative Contracts
5.39% 
 
Long-Term Debt (TCEH Debtor-In-Possession Facilities) (Details) (Predecessor [Member], 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 3 Months Ended
Oct. 31, 2015
Aug. 31, 2015
Mar. 31, 2017
Pending Litigation [Member]
EPA Versus Luminant and Big Brown Power Company (Big Brown and Martin Lake Generation Facilities) [Member]
Minimum [Member]
Mar. 31, 2017
Pending Litigation [Member]
EPA Versus Luminant and Big Brown Power Company (Big Brown and Martin Lake Generation Facilities) [Member]
Maximum [Member]
Mar. 31, 2017
United States Environmental Protection Agency [Member]
Mar. 31, 2017
Financial Standby Letter of Credit [Member]
Vistra Operations Company LLC [Member]
Mar. 31, 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]
Mar. 31, 2017
Support Executory Contracts And Insurance Agreements [Member]
Financial Standby Letter of Credit [Member]
Vistra Operations Company LLC [Member]
Mar. 31, 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]
Mar. 31, 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
 
 
 
 
 
$ 440,000,000 
$ 297,000,000 
$ 63,000,000 
$ 55,000,000 
$ 25,000,000 
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 
 
 
 
 
 
Equity (Narrative) (Details) (USD $)
In Billions, except Share data, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Equity
 
 
Common stock, shares authorized
1,800,000,000 
 
Common stock, shares outstanding
427,587,401 
427,580,232 
Vistra Operations Company LLC [Member]
 
 
Equity
 
 
Authorized distribution to parent
$ 1.0 
 
Equity (Changes to Equity) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 3 Months Ended 3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2017
Successor [Member]
Mar. 31, 2017
Successor [Member]
Common Stock [Member]
Dec. 31, 2016
Successor [Member]
Common Stock [Member]
Mar. 31, 2017
Successor [Member]
Additional Paid-in Capital [Member]
Mar. 31, 2017
Successor [Member]
Retained Earnings [Member]
Mar. 31, 2017
Successor [Member]
Accumulated Other Comprehensive Income (Loss) [Member]
Dec. 31, 2016
Successor [Member]
Accumulated Other Comprehensive Income (Loss) [Member]
Mar. 31, 2016
Predecessor [Member]
Mar. 31, 2016
Predecessor [Member]
Common Stock [Member]
Mar. 31, 2016
Predecessor [Member]
Accumulated Other Comprehensive Income (Loss) [Member]
Dec. 31, 2015
Predecessor [Member]
Accumulated Other Comprehensive Income (Loss) [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance
$ 6,680 
$ 6,597 
$ 6,597 
$ 4 1
$ 4 1
$ 7,742 
$ (1,155)
$ 6 
$ 6 
$ (22,884)
$ (22,851)
$ (33)
$ (33)
Net income (loss)
 
 
78 
 
 
 
78 
 
 
(343)
(343)
 
 
Effects of stock-based incentive compensation plans
 
 
4 
 
 
4 
 
 
 
 
 
 
 
Other
 
 
1 
 
 
 
1 
 
 
 
 
 
 
Ending balance
$ 6,680 
$ 6,597 
$ 6,680 
$ 4 1
$ 4 1
$ 7,746 
$ (1,076)
$ 6 
$ 6 
$ (23,227)
$ (23,194)
$ (33)
$ (33)
Fair Value Measurements (Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Assets:
 
 
Nuclear decommissioning trust
$ 1,061 
$ 1,012 
Equity Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
713 1
672 1
Debt Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
348 2
340 2
Fair Value, Measurements, Recurring [Member]
 
 
Assets:
 
 
Sub-total
16 3
13 3
Liabilities:
 
 
Total liabilities
16 3
13 3
Fair Value, Measurements, Recurring [Member] |
Equity Securities [Member]
 
 
Assets:
 
 
Assets measured at net asset value
262 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
13 3
13 3
Liabilities:
 
 
Derivative Liabilities
13 3
13 3
Fair Value, Measurements, Recurring [Member] |
Total [Member]
 
 
Assets:
 
 
Sub-total
1,120 
1,179 
Total assets
1,382 
1,426 
Liabilities:
 
 
Total liabilities
129 
361 
Fair Value, Measurements, Recurring [Member] |
Total [Member] |
Equity Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
451 4
425 4
Fair Value, Measurements, Recurring [Member] |
Total [Member] |
Debt Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
348 4
340 4
Fair Value, Measurements, Recurring [Member] |
Total [Member] |
Commodity contracts [Member]
 
 
Assets:
 
 
Derivative Assets
299 
396 
Liabilities:
 
 
Derivative Liabilities
105 
332 
Fair Value, Measurements, Recurring [Member] |
Total [Member] |
Interest Rate Swap [Member]
 
 
Assets:
 
 
Derivative Assets
22 
18 
Liabilities:
 
 
Derivative Liabilities
24 
29 
Level 1 [Member] |
Fair Value, Measurements, Recurring [Member]
 
 
Assets:
 
 
Sub-total
496 
592 
Liabilities:
 
 
Total liabilities
66 
302 
Level 1 [Member] |
Fair Value, Measurements, Recurring [Member] |
Equity Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
451 4
425 4
Level 1 [Member] |
Fair Value, Measurements, Recurring [Member] |
Commodity contracts [Member]
 
 
Assets:
 
 
Derivative Assets
45 
167 
Liabilities:
 
 
Derivative Liabilities
66 
302 
Level 2 [Member] |
Fair Value, Measurements, Recurring [Member]
 
 
Assets:
 
 
Sub-total
480 
476 
Liabilities:
 
 
Total liabilities
26 
31 
Level 2 [Member] |
Fair Value, Measurements, Recurring [Member] |
Debt Securities [Member]
 
 
Assets:
 
 
Nuclear decommissioning trust
348 4
340 4
Level 2 [Member] |
Fair Value, Measurements, Recurring [Member] |
Commodity contracts [Member]
 
 
Assets:
 
 
Derivative Assets
123 
131 
Liabilities:
 
 
Derivative Liabilities
15 
15 
Level 2 [Member] |
Fair Value, Measurements, Recurring [Member] |
Interest Rate Swap [Member]
 
 
Assets:
 
 
Derivative Assets
9 
5 
Liabilities:
 
 
Derivative Liabilities
11 
16 
Level 3 [Member]
 
 
Assets:
 
 
Sub-total
128 6
98 6
Liabilities:
 
 
Total liabilities
21 6
15 6
Level 3 [Member] |
Fair Value, Measurements, Recurring [Member]
 
 
Assets:
 
 
Sub-total
128 
98 
Liabilities:
 
 
Total liabilities
21 
15 
Level 3 [Member] |
Fair Value, Measurements, Recurring [Member] |
Commodity contracts [Member]
 
 
Assets:
 
 
Derivative Assets
128 
98 
Liabilities:
 
 
Derivative Liabilities
$ 21 
$ 15 
Commodity And Other Derivative Contractual Assets And Liabilities (Financial Statement Effects of Derivatives) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
$ 305 
$ 401 
Derivative liabilities, Fair Value, Gross Liability
(113)
(348)
Derivative, Fair Value, Net
192 
53 
Current assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets And Liability, Fair Value, Gross Assets
231 
350 
Noncurrent assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets And Liability, Fair Value, Gross Assets
90 
64 
Current liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets And Liability, Fair Value, Gross Liability
(124)
(359)
Noncurrent Liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets And Liability, Fair Value, Gross Liability
(5)
(2)
Commodity contracts [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
296 
396 
Derivative liabilities, Fair Value, Gross Liability
(102)
(332)
Derivative asset, Fair Value, Net
296 
396 
Derivative liabilities, Fair Value, Net
(102)
(332)
Commodity contracts [Member] |
Current assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
231 
350 
Derivative liabilities, Fair Value, Gross Asset
0 
0 
Commodity contracts [Member] |
Noncurrent assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
66 
46 
Derivative liabilities, Fair Value, Gross Asset
2 
0 
Commodity contracts [Member] |
Current liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative asset, Fair Value, Gross Liability
0 
0 
Derivative liabilities, Fair Value, Gross Liability
(100)
(330)
Commodity contracts [Member] |
Noncurrent Liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative asset, Fair Value, Gross Liability
(1)
0 
Derivative liabilities, Fair Value, Gross Liability
(4)
(2)
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
9 
5 
Derivative liabilities, Fair Value, Gross Liability
(11)
(16)
Derivative asset, Fair Value, Net
9 
5 
Derivative liabilities, Fair Value, Net
(11)
(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
19 
17 
Derivative liabilities, Fair Value, Gross Asset
3 
1 
Interest Rate Swap [Member] |
Current liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative asset, Fair Value, Gross Liability
(10)
(12)
Derivative liabilities, Fair Value, Gross Liability
(14)
(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
$ 0 
$ 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
Mar. 31, 2017
Successor [Member]
Mar. 31, 2017
Successor [Member]
Operating revenues [Member]
Commodity contracts [Member]
Mar. 31, 2017
Successor [Member]
Fuel, Purchased Power Costs And Delivery Fees [Member]
Commodity contracts [Member]
Mar. 31, 2017
Successor [Member]
Net gain from commodity hedging and trading activities [Member]
Commodity contracts [Member]
Mar. 31, 2017
Successor [Member]
Interest Expense [Member]
Interest Rate Swap [Member]
Mar. 31, 2016
Predecessor [Member]
Mar. 31, 2016
Predecessor [Member]
Operating revenues [Member]
Commodity contracts [Member]
Mar. 31, 2016
Predecessor [Member]
Fuel, Purchased Power Costs And Delivery Fees [Member]
Commodity contracts [Member]
Mar. 31, 2016
Predecessor [Member]
Net gain from commodity hedging and trading activities [Member]
Commodity contracts [Member]
Mar. 31, 2016
Predecessor [Member]
Interest Expense [Member]
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
 
 
 
 
 
 
Net gain (loss)
$ 173 
$ 175 
$ (5)
$ 0 
$ 3 
$ 56 
$ 0 
$ 0 
$ 56 
$ 0 
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
Mar. 31, 2017
Dec. 31, 2016
Derivatives, Fair Value [Line Items]
 
 
Derivative assets: Amounts Presented in Balance Sheet
$ 305 
$ 401 
Derivative assets: Offsetting Financial Instruments
(78)1
(193)
Derivative assets: Financial Collateral (Received) Pledged
(10)1
(20)1
Derivative assets: Net Amounts
217 
188 
Derivative liabilities: Amounts Presented in Balance Sheet
(113)
(348)
Derivative liabilities: Offsetting Financial Instruments
78 1
193 
Derivative liabilities: Financial Collateral (Received) Pledged
21 1
136 1
Derivative liabilities: Net Amounts
(14)
(19)
Derivative, Fair Value, Net
192 
53 
Derivative (Assets) Liability, Fair Value of Collateral, Net
11 1
116 1
Derivative Assets (Liability), Fair Value, Amount Offset Against Collateral
203 
169 
Commodity contracts [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets: Amounts Presented in Balance Sheet
296 
396 
Derivative assets: Offsetting Financial Instruments
(78)2
(193)2
Derivative assets: Financial Collateral (Received) Pledged
(10)1
(20)1
Derivative assets: Net Amounts
208 
183 
Derivative liabilities: Amounts Presented in Balance Sheet
(102)
(332)
Derivative liabilities: Offsetting Financial Instruments
78 2
193 2
Derivative liabilities: Financial Collateral (Received) Pledged
21 1
136 1
Derivative liabilities: Net Amounts
(3)
(3)
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets: Amounts Presented in Balance Sheet
9 
5 
Derivative assets: Offsetting Financial Instruments
0 
0 
Derivative assets: Financial Collateral (Received) Pledged
0 
0 
Derivative assets: Net Amounts
9 
5 
Derivative liabilities: Amounts Presented in Balance Sheet
(11)
(16)
Derivative liabilities: Offsetting Financial Instruments
0 
0 
Derivative liabilities: Financial Collateral (Received) Pledged
0 
0 
Derivative liabilities: Net Amounts
$ (11)
$ (16)
Commodity And Other Derivative Contractual Assets And Liabilities (Derivative Volumes) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
MMBTU
Dec. 31, 2016
MMBTU
Natural Gas Derivative [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
1,322,000,000 1
1,282,000,000 1
Electricity (in GWh) [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
72,320 
75,322 
Congestion Revenue RIghts (in GWh) [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
114,761 2
126,573 2
Coal (in tons) [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
9,000,000 
12,000,000 
Fuel oil (in gallons) [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
26,000,000 
34,000,000 
Uranium (in pounds) [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Nonmonetary Notional Volume
325,000 
25,000 
Interest rate swaps - Floating/fixed [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative, Notional Amount
$ 3,000 
$ 3,000 3
Related Party Transactions (Narrrative) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Successor [Member]
Maximum [Member]
Mar. 31, 2016
Predecessor [Member]
Texas Competitive Electric Holdings Company LLC [Member]
Oncor [Member]
Mar. 31, 2016
Predecessor [Member]
Texas Competitive Electric Holdings Company LLC [Member]
Energy Future Holdings Corp. [Member]
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 
 
 
Related party transaction, amounts of transaction
 
$ 220 
 
Selling, general and administrative expenses from transactions with related party
 
 
60 
Delivery fee surcharge remitted to related party
 
4 
 
Related Party Tax Expense, Due to Affiliates, Current
 
 
$ 0 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Reportable_segment
Dec. 31, 2016
Segment Reporting Information [Line Items]
 
 
Number of reportable segments (in reportable segments)
2 
 
Total assets
$ 14,715 
$ 15,167 
Intersegment Eliminations [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
2,031 
2,462 
Wholesale Generation Segment [Member] |
Operating Segments [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
7,023 
6,952 
Retail Electric Segment [Member] |
Operating Segments [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
5,661 
5,753 
Successor [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Operating revenues
1,357 1
 
Depreciation and amortization
170 
 
Operating income (loss)
155 
 
Unrealized mark-to-market net gain on interest rate swaps
9 
 
Net income (loss)
78 
 
Successor [Member] |
Corporate, Non-Segment [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Operating revenues
(1)1
 
Depreciation and amortization
11 
 
Operating income (loss)
(12)
 
Net income (loss)
(99)
 
Successor [Member] |
Intersegment Eliminations [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Operating revenues
(478)1
 
Successor [Member] |
Wholesale Generation Segment [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Operating revenues
971 1
 
Depreciation and amortization
53 
 
Operating income (loss)
285 
 
Net income (loss)
290 
 
Successor [Member] |
Retail Electric Segment [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Operating revenues
865 1
 
Depreciation and amortization
106 
 
Operating income (loss)
(118)
 
Net income (loss)
(113)
 
Successor [Member] |
Operating revenues [Member] |
Wholesale Generation Segment [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Unrealized mark-to-market net gain on interest rate swaps
126 
 
Successor [Member] |
Operating revenues [Member] |
Wholesale Generation Segment [Member] |
Intersegment Eliminations [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Unrealized mark-to-market net gain on interest rate swaps
170 
 
Successor [Member] |
Operating revenues [Member] |
Retail Electric Segment [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Unrealized mark-to-market net gain on interest rate swaps
8 
 
Successor [Member] |
Fuel, Purchased Power Costs And Delivery Fees [Member] |
Retail Electric Segment [Member] |
Intersegment Eliminations [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Unrealized mark-to-market net gain on interest rate swaps
$ 170 
 
Supplementary Financial Information (Other Income and Deductions) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Successor [Member]
Mar. 31, 2017
Successor [Member]
Corporate and Other Nonsegment [Member]
Mar. 31, 2017
Successor [Member]
Wholesale Generation Segment [Member]
Mar. 31, 2016
Predecessor [Member]
Other income:
 
 
 
 
Office space sublease rental income
 
$ 3 1
 
$ 0 
Mineral rights royalty income
 
 
1 2
1 
Sale of land
 
 
2 2
0 
All other
2 
 
 
0 
Total other income
8 
 
 
1 
Other deductions:
 
 
 
 
Write-off of generation equipment
0 
 
 
20 
All other
0 
 
 
1 
Total other deductions
$ 0 
 
 
$ 21 
Supplementary Financial Information (Restricted Cash) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Restricted Cash and Investments, Current
$ 94 
$ 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
89 
90 
Restricted Cash and Investments, Noncurrent
0 
0 
Other
 
 
Restricted Cash and Investments, Current
5 
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
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2017
Successor [Member]
Mar. 31, 2016
Predecessor [Member]
Wholesale and retail trade accounts receivable
$ 490 
$ 622 
 
 
Allowance for uncollectible accounts
(8)
(10)
(8)
(7)
Trade accounts receivable — net
482 
612 
 
 
Unbilled Receivables, Current
184 
225 
 
 
Allowance for Doubtful Accounts Receivable [Roll Forward]
 
 
 
 
Allowance for uncollectible accounts receivable at beginning of period
8 
10 
10 
9 
Increase for bad debt expense
 
 
7 
5 
Decrease for account write-offs
 
 
(9)
(7)
Allowance for uncollectible accounts receivable at end of period
$ 8 
$ 10 
$ 8 
$ 7 
Supplementary Financial Information (Inventories by Major Category and Other Investments) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Inventories by Major Category
 
 
Materials and supplies
$ 169 
$ 173 
Fuel stock
126 
88 
Natural gas in storage
20 
24 
Total inventories
315 
285 
Other Investments
 
 
Nuclear plant decommissioning trust
1,061 
1,012 
Land
49 
49 
Miscellaneous other
3 
3 
Total other investments
$ 1,113 
$ 1,064 
Supplementary Financial Information (Nuclear Decommissioning Trust) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended 3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2017
Debt Securities [Member]
Dec. 31, 2016
Debt Securities [Member]
Mar. 31, 2017
Equity Securities [Member]
Dec. 31, 2016
Equity Securities [Member]
Mar. 31, 2017
Successor [Member]
Mar. 31, 2016
Predecessor [Member]
Schedule of Schedule of Decommissioning Fund Investments [Line Items]
 
 
 
 
 
 
 
 
Cost
$ 653 1
$ 642 1
$ 340 1 2
$ 333 1 2
$ 313 1 3
$ 309 1 3
 
 
Unrealized gain
414 
378 
10 2
10 2
404 3
368 3
 
 
Unrealized loss
(6)
(8)
(2)2
(3)2
(4)3
(5)3
 
 
Fair market value
1,061 
1,012 
348 2
340 2
713 3
672 3
 
 
Debt, Weighted Average Interest Rate
 
 
3.52% 
3.56% 
 
 
 
 
Decommissioning Fund Investments, Debt securities, average maturity
 
 
9 years 
9 years 
 
 
 
 
Decommissioning Fund Investments, debt maturities, one through five years, fair value
 
 
106 
 
 
 
 
 
Decommissioning Fund Investments, debt maturities, five through ten years, fair value
 
 
94 
 
 
 
 
 
Decommissioning Fund Investments, debt maturities, after ten years, fair value
 
 
148 
 
 
 
 
 
Realized gains
 
 
 
 
 
 
1 
1 
Realized losses
 
 
 
 
 
 
(2)
(1)
Proceeds from sales of securities
 
 
 
 
 
 
79 
67 
Investments in securities
 
 
 
 
 
 
$ (84)
$ (71)
Supplementary Financial Information (Property, Plant and Equipment) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Supplementary Financial Information [Abstract]
 
 
Property, plant and equipment — net
$ 4,415 
$ 4,443 
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment
$ 167 
$ 85 
Supplementary Financial Information (Asset Retirement and Mining Reclamation Obligations) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance, Liability
$ 1,726 
 
Additions:
 
 
Accretion
14 
 
Reductions:
 
 
Payments
(5)
 
Ending balance, Liability
1,735 
 
Less amounts due currently
(62)
 
Noncurrent liability at end of period
1,673 
1,671 
Nuclear Plant Decommissioning [Member]
 
 
Asset Retirement Obligations [Line Items]
 
 
Regulatory Assets
147 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance, Liability
1,200 
 
Additions:
 
 
Accretion
8 
 
Reductions:
 
 
Payments
0 
 
Ending balance, Liability
1,208 
 
Less amounts due currently
0 
 
Noncurrent liability at end of period
1,208 
 
Mining Land Reclamation [Member]
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance, Liability
375 
 
Additions:
 
 
Accretion
5 
 
Reductions:
 
 
Payments
(5)
 
Ending balance, Liability
375 
 
Less amounts due currently
(61)
 
Noncurrent liability at end of period
314 
 
Other Asset Retirement Obligations [Member]
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning balance, Liability
151 
 
Additions:
 
 
Accretion
1 
 
Reductions:
 
 
Payments
0 
 
Ending balance, Liability
152 
 
Less amounts due currently
(1)
 
Noncurrent liability at end of period
$ 151 
 
Supplementary Financial Information (Other Noncurrent Liabilities and Deferred Credits) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2017
Successor [Member]
Mar. 31, 2016
Predecessor [Member]
Other Noncurrent Liabilities Noncurrent and Deferred Credits [Line Items]
 
 
 
 
Unfavorable purchase and sales contracts
$ 43 
$ 46 
 
 
Other, including retirement and other employee benefits
191 
174 
 
 
Amortization of Deferred Charges [Abstract]
 
 
 
 
Amortization of Unfavorable Purchase and Sales Contracts
 
 
3 
6 
Total other noncurrent liabilities and deferred credits
234 
220 
 
 
Future Amortization Expense, Unfavorable Purchase and Sales Contracts [Abstract]
 
 
 
 
2017
9 
 
 
 
2018
11 
 
 
 
2019
11 
 
 
 
2020
9 
 
 
 
2021
$ 1 
 
 
 
Supplementary Financial Information (Fair Value of Debt) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 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
$ 4,482 
$ 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
32 
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
4,489 
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
29 
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
3 Months Ended
Mar. 31, 2017
Successor [Member]
Mar. 31, 2016
Predecessor [Member]
Cash payments related to:
 
 
Interest paid
$ 89 1
$ 335 1
Capitalized interest
(3)
(3)
Interest paid (net of capitalized interest)
86 1
332 1
Reorganization items
0 
41 2
Noncash investing and financing activities:
 
 
Construction expenditures
$ 1 3
$ 82 3